20231017 Regular City Council Meeting - Packet (7)Regular City Council Meeting Agenda October 17, 2023
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Agenda
City of Vernon
Regular City Council Meeting
Tuesday, October 17, 2023, 9:00 AM
City Hall, Council Chamber
4305 Santa Fe Avenue, Vernon, California
Crystal Larios, Mayor
Judith Merlo, Mayor Pro Tem
Melissa Ybarra, Council Member
Leticia Lopez, Council Member
Jesus Rivera, Council Member
The public is encouraged to view the agenda and meeting through
CityofVernon.org/publicmeetings. You may address the Council in the Council Chambers, via mail
or email to PublicComment@cityofvernon.org, include the meeting date and item number in the
subject line (mail and/or email must be received at least two hours prior to the start of the meeting).
CALL TO ORDER
FLAG SALUTE
ROLL CALL
APPROVAL OF AGENDA
PUBLIC COMMENT
At this time the public is encouraged to address the City Council on any matter that is within the
subject matter jurisdiction of the City Council. The public will also be given a chance to comment
on matters which are on the posted agenda during City Council deliberation on those specific
matters.
PRESENTATIONS
1. Employee Service Pin Awards
Recommendation:
Recognize September 2023 Employee Service Pin Award recipient.
Regular City Council Meeting Agenda October 17, 2023
Page 2 of 5
2. City Administrator Report
Recommendation:
Receive presentation on various topics including New Business Welcome, Vernon Business
Milestones, Health and Wellness Grants, Update on Clean-Up Efforts, Pink Patch Project,
Business Engagement and Community Events.
CONSENT CALENDAR
All matters listed on the Consent Calendar are to be approved with one motion. Items may be
removed from the Consent Calendar for individual consideration. Removed items will be
considered immediately following the Consent Calendar.
3. Meeting Minutes
Recommendation:
Approve the October 3, 2023 Regular City Council Meeting Minutes.
4. Claims Against City
Recommendation:
Receive and file the claims submitted by Gabriela Nubia Rojas Palacios and Jennifer Beas.
5. City Payroll Warrant Register
Recommendation:
Approve City Payroll Warrant Register No. 808, for the period of September 1 through
September 30, 2023, totaling $2,989,186.50 and consisting of ratification of direct deposits,
checks and taxes totaling $1,979,738.61 and ratification of checks and electronic fund
transfers (EFT) for payroll related disbursements totaling $1,009,447.89 paid through
operating bank account.
6. Operating Account Warrant Register
Recommendation:
Approve Operating Account Warrant Register No. 118, for the period of September 3 through
September 16, 2023, totaling $4,516,762.48 and consisting of ratification of electronic
payments totaling $4,123,445.19 and ratification of the issuance of early checks totaling
$393,317.29.
7. Fire Department Activity Report
Recommendation:
Receive and file the August 2023 Fire Department Activity Report.
8. Police Department Activity Report
Recommendation:
Receive and file the August 2023 Police Department Activity Report.
Regular City Council Meeting Agenda October 17, 2023
Page 3 of 5
9. Service Level Performance Agreements with USIP Communications, LLC
Recommendation:
A. Approve and authorize the City Administrator to execute a Service Level Performance
Agreement and issue Change Orders with USIP Communications, LLC (USIPCOM), in
substantially the same form as submitted, in an amount not-to-exceed $333,252 and up to a
15% contingency of $49,988, to provide the primary feed for Upstream Internet Access
Services for three years; and
B. Approve and authorize the City Administrator to execute a Service Level Performance
Agreement and issue Change Orders with USIPCOM, in substantially the same form as
submitted, in an amount not-to-exceed $289,704 and up to a 15% contingency of $43,456, to
provide the backup feed for Upstream Internet Access Services for three years.
10. Lease Agreement with WEA CA, PC (WEA)
Recommendation:
Approve and authorize the City Administrator to execute a Lease Agreement with WEA, in
substantially the same form as submitted, for a one-year term.
11. Professional Services Agreement with Northwest Electrical Services, LLC to Perform
Technical Design, Controls, Automation and Analytical Services
Recommendation:
A. Find that the proposed action is categorically exempt from California Environmental
Quality Act (CEQA) review, in accordance with CEQA Guidelines Section 15301, because
the project consists of the maintenance, repair or minor alteration of existing
facilities/equipment and involves negligible or no expansion of an existing use;
B. Find that the best interests of the City are served by a direct award of an agreement with
Northwest Electrical Services, LLC without a competitive selection process pursuant to
Vernon Municipal Code Section 3.32.110(B)(2);
C. Approve and authorize the City Administrator to execute a Professional Services
Agreement with Northwest Electrical Services LLC, in substantially the same form as
submitted for a three-year term from November 17, 2023, through November 16, 2026, in an
amount not to exceed $2,719,903 to provide technical design, controls, automation,
construction, and analytical services for Vernon Public Utilities Department; and
D. Authorize a contingency amount of five percent (5%), or $135,995.15, for any unforeseen
changes in fees or other expenses not included in the proposal, and grant authority to the
City Administrator to issue Change Orders for an amount up to the contingency amount, if
necessary.
12. Audited Financial Reports
Recommendation:
A. Receive and file the Fiscal Year 2021-22 Annual Financial Statements; and
B. Extend submittal of the Fiscal Year 2022-23 Final Audit and Report to Council to January
16, 2024.
Regular City Council Meeting Agenda October 17, 2023
Page 4 of 5
NEW BUSINESS
13. Vernon Public Utilities 2023 Integrated Resource Plan (IRP)
Recommendation:
A. Find that approval of the proposed action is exempt from California Environmental Quality
Act (CEQA) review, because it is a continuing administrative activity that will not result in
direct or indirect physical changes in the environment, and therefore does not constitute a
“project” as defined by CEQA Guidelines Section 15378;
B. Approve and adopt the Vernon Public Utilities 2023 IRP; and
C. Authorize the General Manager of Public Utilities to take all necessary actions to
implement the IRP, consistent with California State law mandates, including but not limited to
periodic updates and IRP revisions.
ORAL REPORTS
14. City Administrator Reports on Activities and Other Announcements
15. Council Reports on Activities (including AB 1234), Announcements, or Directives to
Staff
ADJOURNMENT
On October 12, 2023, the foregoing agenda was posted in accordance with the applicable legal
requirements. Regular and Adjourned Regular meeting agendas may be amended up to 72
hours and Special meeting agendas may be amended up to 24 hours in advance of the meeting.
Regular City Council Meeting Agenda October 17, 2023
Page 5 of 5
Guide to City Council Proceedings
Meetings of the City Council are held the first and third Tuesday of each month at 9:00 a.m. and are
conducted in accordance with Rosenberg's Rules of Order (Vernon Municipal Code Section
2.04.020).
Copies of all agenda items and back-up materials are available for review in the City Clerk
Department, Vernon City Hall, 4305 Santa Fe Avenue, Vernon, California, and are available for
public inspection during regular business hours, Monday through Thursday, 7:00 a.m. to 5:30 p.m.
Agenda reports may be reviewed on the City's website at www.cityofvernon.org or copies may be
purchased for $0.10 per page.
Disability-related services are available to enable persons with a disability to participate in this
meeting, consistent with the Americans with Disabilities Act (ADA). In compliance with ADA, if you
need special assistance, please contact the City Clerk department at CityClerk@cityofvernon.org or
(323) 583-8811 at least 48 hours prior to the meeting to assure arrangements can be made.
The Public Comment portion of the agenda is for members of the public to present items, which are
not listed on the agenda but are within the subject matter jurisdiction of the City Council. The City
Council cannot take action on any item that is not on the agenda but matters raised under Public
Comment may be referred to staff or scheduled on a future agenda. Comments are limited to three
minutes per speaker unless a different time limit is announced. Speaker slips are available at the
entrance to the Council Chamber.
Public Hearings are legally noticed hearings. For hearings involving zoning matters, the applicant
and appellant will be given 15 minutes to present their position to the City Council. Time may be set
aside for rebuttal. All other testimony shall follow the rules as set for under Public Comment. If you
challenge any City action in court, you may be limited to raising only those issues you or someone
else raised during the public hearing, or in written correspondence delivered to the City Clerk at or
prior to the public hearing.
Consent Calendar items may be approved by a single motion. If a Council Member or the public
wishes to discuss an item, it may be removed from the calendar for individual consideration. Council
Members may indicate a negative or abstaining vote on any individual item by so declaring prior to
the vote on the motion to adopt the Consent Calendar. Items excluded from the Consent Calendar
will be taken up following action on the Consent Calendar. Public speakers shall follow the
guidelines as set forth under Public Comment.
New Business items are matters appearing before the Council for the first time for formal action.
Those wishing to address the Council on New Business items shall follow the guidelines for Public
Comment.
Closed Session allows the Council to discuss specific matters pursuant to the Brown Act,
Government Code Section 54956.9. Based on the advice of the City Attorney, discussion of these
matters in open session would prejudice the position of the City. Following Closed Session, the City
Attorney will provide an oral report on any reportable matters discussed and actions taken. At the
conclusion of Closed Session, the Council may continue any item listed on the Closed Session
agenda to the Open Session agenda for discussion or to take formal action as it deems appropriate.
City Council Agenda Report
Meeting Date:October 17, 2023
From:Michael Earl, Director of Human Resources
Department:Human Resources
Submitted by:Veronica Avendano, Human Resources Specialist
Subject
Employee Service Pin Awards
Recommendation
Recognize September 2023 Employee Service Pin Award recipient.
Background
The following employee is eligible to receive her service pin based on the number of service
years with the City of Vernon.
TEN YEARS OF SERVICE
Lisette M. Grizzelle, Senior Human Resources Analyst, Hired September 2013
Fiscal Impact
There is no fiscal impact associated with this report.
Attachments
None.
City Council Agenda Report
Meeting Date:October 17, 2023
From:Carlos Fandino, City Administrator
Department:City Administration
Submitted by:Diana Figueroa, Administrative Analyst
Subject
City Administrator Report
Recommendation
Receive presentation on various topics including New Business Welcome, Vernon Business
Milestones, Health and Wellness Grants, Update on Clean-Up Efforts, Pink Patch Project,
Business Engagement and Community Events.
Background
The City Administrator Report is a presentation highlighting City projects, responses to Council
inquiries, and events and activities of interest to the community. The report will be available at
the time of the meeting.
Fiscal Impact
There is no fiscal impact associated with this report.
Attachments
None.
City Council Agenda Report
Meeting Date:October 17, 2023
From:Lisa Pope, City Clerk
Department:City Clerk
Submitted by:Sandra Dolson, Administrative Secretary
Subject
Meeting Minutes
Recommendation
Approve the October 3, 2023 Regular City Council Meeting Minutes.
Background
Staff has prepared and submits the minutes for approval.
Fiscal Impact
There is no fiscal impact associated with this report.
Attachments
1. October 3, 2023 Regular City Council Meeting Minutes
MINUTES
VERNON CITY COUNCIL
REGULAR MEETING
TUESDAY, OCTOBER 3, 2023
COUNCIL CHAMBER, 4305 SANTA FE AVENUE
CALL TO ORDER
Mayor Larios called the meeting to order at 9:01 a.m.
FLAG SALUTE
Mayor Larios led the Flag Salute.
ROLL CALL
PRESENT:
Crystal Larios, Mayor
Judith Merlo, Mayor Pro Tem
Melissa Ybarra, Council Member
Leticia Lopez, Council Member
Jesus Rivera, Council Member
STAFF PRESENT:
Carlos Fandino, City Administrator
Angela Kimmey, Deputy City Administrator
Zaynah Moussa, City Attorney
Lisa Pope, City Clerk
Scott Williams, Finance Director
Fredrick Agyin, Health and Environmental Control Director
Michael Earl, Human Resources Director
Robert Sousa, Police Chief
Dan Wall, Public Works Director
Todd Dusenberry, Public Utilities General Manager
APPROVAL OF THE AGENDA
MOTION
Councill Member Ybarra moved and Mayor Pro Tem Merlo seconded a motion to
approve the agenda. The question was called and the motion carried unanimously.
PUBLIC COMMENT
Leonora K. Carrillo, Principal of Vernon City Elementary School, introduced herself
to the City Council and community.
Regular City Council Meeting Minutes Page 2 of 5
October 3, 2023
PRESENTATIONS
1. Proclamation Recognizing Daniel Cordova
The City Council acknowledged Daniel Cordova for his years of service to the City.
2. Indigenous Peoples’ Day Proclamation
City Clerk Pope read the proclamation and the City Council proclaimed October 9,
2023 as Indigenous Peoples’ Day in the City of Vernon.
CONSENT CALENDAR
MOTION
Council Member Ybarra moved and Council Member Rivera seconded a motion to
approve the Consent Calendar. The question was called and the motion carried
unanimously.
The Consent Calendar consisted of the following items:
3. Meeting Minutes
Recommendation: Approve the September 19, 2023 Regular City Council Meeting
Minutes.
4. Operating Account Warrant Register
Recommendation: Approve Operating Account Warrant Register No. 117, for the
period of August 20 through September 2, 2023, totaling $7,078,751.65 and
consisting of ratification of electronic payments totaling $6,788,492.44 and
ratification of the issuance of early checks totaling $290,259.21.
5. 2024 Calendar Year Medical, Dental, Vision, Life, and Employee Assistance
Program Benefit Proposals for City Employees and Retirees
Recommendation: Approve the acceptance of the 2024 Calendar Year Medical,
Dental, Vision, Life, and Employee Assistance program proposals and authorize
the City Administrator to execute 2024 calendar year carrier agreements with Blue
Shield of California, Anthem, MetLife, EyeMed, Mutual of Omaha, and Anthem
PRISM EAP.
6. Resource Adequacy Plan for 2024
Recommendation: A. Adopt Resolution No. 2023-21 approving and adopting the
Vernon Public Utilities Department Resource Adequacy Plan for 2024, which
includes the coincident peak Demand Forecast, the Planning Reserve Margin, the
Qualifying Capacity Criteria, and the Qualifying Capacity from such resources, the
City’s Resource Adequacy and Supply Data and approving the resources used to
satisfy the California Independent System Operator’s (CAISO) tariff requirements
and repealing Resolution No. 2022-35; and B. Authorize staff to submit the Vernon
Public Utilities Department’s Resource Adequacy Plan for 2024 and the Monthly
Resource Adequacy and Supply Data to the CAISO.
7. rPlanet Earth Los Angeles, LLC - Request to Consider Items Regarding
Added Facilities for Electric Service and Electric Consumption Hurdle
Escrow Funds
Regular City Council Meeting Minutes Page 3 of 5
October 3, 2023
Recommendation: A. Find the action is categorically exempt from California
Environmental Quality Act (CEQA) review, in accordance with CEQA Guidelines
section 15060(c)(3), because it constitutes government fiscal activities that do not
involve any commitment to any specific project that may result in a potentially
significant physical impact on the environment and organizational or administrative
activities of a public agency that will not result in direct or indirect physical changes
in the environment. Moreover, adoption of the Resolution does not qualify as a
"project" because it does not have the potential to result in either a direct, or
reasonably foreseeable indirect, physical change in the environment, in
accordance with CEQA Guidelines section 15378(a); B. Authorize the proposed
request for Disbursement No. 3 to the existing Added Facilities Agreement with
rPlanet Earth Los Angeles, LLC, in substantially the same form as submitted, for
electric service delivery in the amount of $416,610.27; and C. Adopt Resolution
No. 2023-22 amending the Escrow Agreement, agreement regarding Assignment
and Assumption of Purchase and Sale Agreement, and Added Facilities
Agreement to release remaining escrow funds for Added Facilities, in the
estimated amount of $813,915.40 plus accrued interest, and to waive the final
electric consumption hurdle of eight (8) megawatts (MW) and release the final
deposit of $441,613.98 plus accrued interest from the Consumption Hurdle Escrow
Account.
8. Public Works Department Monthly Report
Recommendation: Receive and file the July 2023 and August 2023 Building
Reports.
NEW BUSINESS
9. Amendment to Classification and Compensation Plan
Human Resources Director Earl presented the staff report.
MOTION
Council Member Lopez moved and Mayor Pro Tem Merlo seconded a motion to:
A. Approve new, retitled and revised job descriptions; and B. Adopt Resolution No.
2023-23 adopting the Classification and Compensation Plan in accordance with
Government Code Section 20636(b)(1) and repealing Resolution No. 2023-11
effective October 3, 2023. The question was called and the motion carried
unanimously.
Regular City Council Meeting Minutes Page 4 of 5
October 3, 2023
10. Citywide Fringe Benefits Policy
Human Resources Director Earl presented the staff report.
MOTION
Council Member Lopez moved and Council Member Rivera seconded a motion to:
Adopt Resolution No. 2023-24 approving the revised Citywide Fringe Benefits
Policy and repealing Resolution No. 2022-28. The question was called and the
motion carried unanimously.
ORAL REPORTS
11. City Administrator Reports on Activities and other Announcements.
City Administrator Fandino welcomed Vernon City Elementary School Principal
Carillo. He announced Coffee with a Cop on October 4 from 8 to 10 a.m. at the
new Starbucks on Soto Street; Grantmaking Workshop on October 18, from 10
a.m. to 2 p.m.; Annual Career Day on October 18, 5:30 – 7 p.m.; and the Annual
Spooktacular on October 26, 2023.
12. City Council Reports on Activities (including AB 1234), Announcements, or
Directives to Staff.
None.
RECESS
Mayor Larios recessed the meeting to Closed Session at 9:14 a.m.
CLOSED SESSION
13. Conference with Legal Counsel – Anticipated Litigation
Initiation of Litigation
Government Code Section 54956.9(d)(4)
Number of potential cases: 1
RECONVENE
At 9:51 a.m., Mayor Larios adjourned Closed Session and reconvened the regular
meeting.
CLOSED SESSION REPORT
City Attorney Moussa reported the Council met in Closed Session, Council
received an update from legal counsel and provided direction on the City’s
participation in City of Whittier, et al v. LA Superior Court, et al (LASC Case
Number 23STCP03579).
Regular City Council Meeting Minutes Page 5 of 5
October 3, 2023
ADJOURNMENT
Mayor Larios adjourned the meeting at 9:51 a.m.
______________________________
CRYSTAL LARIOS, Mayor
ATTEST:
____________________________
LISA POPE, City Clerk
(seal)
City Council Agenda Report
Meeting Date:October 17, 2023
From:Lisa Pope, City Clerk
Department:City Clerk
Submitted by:Yonnie Parker, Deputy City Clerk
Subject
Claims Against City
Recommendation
Receive and file the claims submitted by Gabriela Nubia Rojas Palacios and Jennifer Beas.
Background
The City received the following claims and, pursuant to Municipal Code Section 2.23.040, the
claims are being presented to the City Council as soon after filing as possible.
Name of Claimant Amount Demanded Date Received
Gabriela Nubia Rojas Palacios $468.04 September 25, 2023
Jennifer Beas $850 (Estimate)September 25, 2023
Fiscal Impact
There is no fiscal impact associated with this report.
Attachments
1. Gabriela Nubia Rojas Palacios Claim
2. Jennifer Beas Claim
City Council Agenda Report
Meeting Date:October 17, 2023
From:Scott Williams, Director of Finance
Department:Finance
Submitted by:Efren Peregrina Renteria, Finance Specialist
Subject
City Payroll Warrant Register
Recommendation
Approve City Payroll Warrant Register No. 808, for the period of September 1 through September
30, 2023, totaling $2,989,186.50 and consisting of ratification of direct deposits, checks and taxes
totaling $1,979,738.61 and ratification of checks and electronic fund transfers (EFT) for payroll
related disbursements totaling $1,009,447.89 paid through operating bank account.
Background
Section 2.32.060 of the Vernon Municipal Code indicates the City Treasurer, or an authorized
designee, shall prepare warrants covering claims or demands against the City which are to be
presented to City Council for its audit and approval. Pursuant to the aforementioned code section,
the City Treasurer has prepared City Payroll Account Warrant Register No. 808 covering claims
and demands presented during the period of September 1 through September 30, 2023, drawn,
or to be drawn, from East West Bank for City Council approval.
Fiscal Impact
The fiscal impact of approving City Payroll Warrant Register No. 808, totals $2,989,186.50. The
Finance Department has determined that sufficient funds to pay such claims/demands, are
available in the respective accounts referenced on City Payroll Warrant Register No. 808.
Attachments
1. City Payroll Account Warrant Register No. 808
PAYROLL WARRANT REGISTERCity of VernonNo.808Month ofSeptember 2023I hereby Certify: that claims or demands covered by the This is to certify that the claims or demandsabove listed warrants have been audited as to accuracycovered by the above listed warrants have beenand availability of funds for payments thereof; and thataudited by the City Council of the City of Vernonsaid claims or demands are accurate and that funds areand that all of said warrants are approved for pay-available for payments thereof.mentsScott A. WilliamsDATEDirector of Finance / City TreasurerDATEDate:Page 1 of 1Payroll Warrant Register Memo September 2023 : Warrant10/03/2023
Payrolls reported for the month of September
08/13/2023 - 08/26/2023, Paydate 09/07/2023
08/13/2023 - 08/26/2023, Paydate 09/07/2023 (SP873)
08/24/2023 - 08/24/2023, Paydate 09/07/2023 (SP874)
08/27/2023 - 09/09/2023, Paydate 09/21/2023
Payment
Method Date Payment Description Amount
ACH 09/07/23 Net payroll, checks 10,261.19$
ACH 09/07/23 Net payroll, direct deposits 797,631.37
ACH 09/07/23 Payroll taxes 227,866.65
ACH 09/21/23 Net payroll, checks 6,326.07
ACH 09/21/23 Net payroll, direct deposits 740,128.01
ACH 09/21/23 Payroll taxes 197,525.32
Total net payroll and payroll taxes 1,979,738.61
15850 09/07/23 Mission Square 57,422.64
15849 09/08/23 IBEW Dues 4,620.59
15848 09/08/23 Vernon Police Officers' Benefit Association 2,186.09
15853 09/08/23 CalPERS 236,956.51
15854 09/08/23 California State Disbursement Unit 41.53
15862 09/08/23 Blue Shield of California (active)274,708.15
15863 09/08/23 Blue Shield of California (retiree)96,273.52
15864 09/08/23 Blue Shield of California (cobra)1,452.32
15865 09/08/23 Metlife - Group Benefits 26,694.19
15866 09/13/23 EyeMed 3,851.65
15867 09/14/23 AFLAC 12,062.01
15868 09/13/23 Mutual of Omaha 13,675.02
15869 09/13/23 Colonial 6,420.05
15857 09/21/23 Mission Square 27,300.44
15856 09/22/23 Teamsters Local 911 2,880.00
15855 09/22/23 Vernon Police Officers' Benefit Association 2,186.09
15860 09/22/23 CalPERS 240,675.56
15861 09/21/23 California State Disbursement Unit 41.53
Payroll related disbursements, paid through
Operating bank account 1,009,447.89
Total net payroll, taxes, and related disbursements 2,989,186.50$
Page 1 of 1
City Council Agenda Report
Meeting Date:October 17, 2023
From:Scott Williams, Director of Finance
Department:Finance
Submitted by:Efren Peregrina Renteria, Finance Specialist
Subject
Operating Account Warrant Register
Recommendation
Approve Operating Account Warrant Register No. 118, for the period of September 3 through
September 16, 2023, totaling $4,516,762.48 and consisting of ratification of electronic payments
totaling $4,123,445.19 and ratification of the issuance of early checks totaling $393,317.29.
Background
Section 2.32.060 of the Vernon Municipal Code indicates the City Treasurer, or an authorized
designee, shall prepare warrants covering claims or demands against the City which are to be
presented to City Council for its audit and approval. Pursuant to the aforementioned code section,
the City Treasurer has prepared Operating Account Warrant Register No. 118 covering claims
and demands presented during the period of September 3 through September 16, 2023, drawn,
or to be drawn, from East West Bank for City Council approval.
Fiscal Impact
The fiscal impact of approving Operating Account Warrant Register No. 118, totals
$4,516,762.48. The Finance Department has determined that sufficient funds to pay such
claims/demands, are available in the respective accounts referenced on Operating Account
Warrant Register No. 118.
Attachments
1. Operating Account Warrant Register No. 118
OPERATING ACCOUNT WARRANT REGISTERCity of VernonNo.118I hereby Certify: that claims or demands covered by the This is to certify that the claims or demandsabove listed warrants have been audited as to accuracycovered by the above listed warrants have beenand availability of funds for payments thereof; and thataudited by the City Council of the City of Vernonsaid claims or demands are accurate and that funds areand that all of said warrants are approved for pay-available for payments thereof.ments except Warrant Numbers:Scott A. WilliamsDATEDirector of Finance / City TreasurerDATEDate:Page 1 of 1Operating Account Warrant Register 117 : Warrant10/3/2023
393,317.299/7/2023 86.00Invoice Description Account PO or Contract Line Item Amount081823 LIVE SCAN REIMBURSEMENT 011-010-120-529215 86.00Invoice Total: 86.009/7/2023 53.64Invoice Description Account PO or Contract Line Item Amount081623 EXPENSE REIMBURSEMENT 011-030-300-524000 53.64Invoice Total: 53.649/7/2023 4,581.05Invoice Description Account PO or Contract Line Item Amount20352282 BAN 9391053026 PERIOD 07/10/23-08/09/23 011-010-110-526010 20230186 48.80Invoice Total: 48.8020352283 BAN 9391053027 PERIOD 07/10/23-08/09/23 011-010-110-526010 20230186 251.91Invoice Total: 251.9120352284 BAN 9391053028 PERIOD 07/10/23-08/9/23 011-010-110-526010 20230186 1,941.76Invoice Total: 1,941.7620352285 BAN 9391053029 PERIOD 07/10/23-08/09/23 011-010-110-526010 20230186 1,367.05Invoice Total: 1,367.0520352286 BAN 9391053030 PERIOD 07/10/23-08/09/23 011-010-110-526010 20230186 702.99Invoice Total: 702.9920352385 BAN 9391055763 PERIOD 07/10/23-08/09/23 011-010-110-526010 20230186 24.40Invoice Total: 24.40CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023VENDOR - 1948 - AT&TPAYMENT # 611679EARLY CHECKS TOTAL:VENDOR - 7677 - AARON PERRYPAYMENT # 611677VENDOR - 3285 - ALEXY ESCOBEDOPAYMENT # 611678Page 1 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/202320352717 BAN 9391060354 PERIOD 07/10/23-08/09/23 011-010-110-526010 20230186 218.35Invoice Total: 218.3520397028 BAN 9391053440 PERIOD 07/15/23-08/14/23 011-010-110-526010 20230186 25.79Invoice Total: 25.799/7/2023 110.39Invoice Description Account PO or Contract Line Item Amount38962309051004VEHICLE BATTERY (ADJUSTMENT) 011-040-420-522000 240021 110.39Invoice Total: 110.399/7/2023 173.16Invoice Description Account PO or Contract Line Item Amount32248 AUTO PARTS 011-040-420-522000 240016 173.16Invoice Total: 173.169/7/2023 27,162.29Invoice Description Account PO or Contract Line Item Amount106626CS STREET SWEEPING SERVICES 07/23 011-040-430-529000 CS-1434 27,162.29Invoice Total: 27,162.299/7/2023 4,514.45Invoice Description Account PO or Contract Line Item Amount200482996 NEW TIRES 011-040-420-522000 20240052 4,514.45Invoice Total: 4,514.459/7/2023 2,960.43Invoice Description Account PO or Contract Line Item Amount125496845 AUTO PARTS 011-040-420-522000 240012 1,240.97VENDOR - 4860 - CLEANSTREET, LLCPAYMENT # 611682VENDOR - 4613 - DANIELS TIRE SERVICEPAYMENT # 611683VENDOR - 6696 - ELLIOTT AUTO SUPPLY CO, INCPAYMENT # 611684VENDOR - 4448 - BATTERY SYSTEMS, INCPAYMENT # 611680VENDOR - 4163 - CENTRAL FORD AUTOMOTIVE, INC.PAYMENT # 611681Page 2 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023Invoice Total: 1,240.97125505936 AUTO PARTS 011-040-420-522000 240012 1,356.08Invoice Total: 1,356.08164289131 AUTO PARTS 011-040-420-522000 240012 363.38Invoice Total: 363.389/7/2023 29.45Invoice Description Account PO or Contract Line Item Amount1028401 COPIER COUNT 055-050-586-522000- 29.45Invoice Total: 29.459/7/2023 161.00Invoice Description Account PO or Contract Line Item Amount090523 LIVE SCAN REIMBURSEMENT 011-010-120-529215 161.00Invoice Total: 161.009/7/2023 750.50Invoice Description Account PO or Contract Line Item AmountIN355485 GPS SERVICES 011-040-420-529000 20240030 750.50Invoice Total: 750.509/7/2023 52.00Invoice Description Account PO or Contract Line Item Amount083123 LIVE SCAN REIMBURSEMENT 011-010-120-529215 52.00Invoice Total: 52.009/7/2023 40,500.00Invoice Description Account PO or Contract Line Item Amount083023 HSA QUARTERLY CONTRIBUTIONS 011-010-105-513030 1,000.00083023 HSA QUARTERLY CONTRIBUTIONS 011-010-110-513030 1,500.00VENDOR - 7678 - GLORIA GARCIAPAYMENT # 611688VENDOR - 4239 - HSA BANKPAYMENT # 611689VENDOR - 7352 - FISHER'S DOCUMENT SYSTEMS, INCPAYMENT # 611685VENDOR - 7676 - FRAMARKARUS JOHNSONPAYMENT # 611686VENDOR - 7107 - GEOTAB USA, INCPAYMENT # 611687Page 3 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023083023 HSA QUARTERLY CONTRIBUTIONS 011-010-115-513030 1,000.00083023 HSA QUARTERLY CONTRIBUTIONS 011-010-120-513030 1,000.00083023 HSA QUARTERLY CONTRIBUTIONS 011-010-125-513030 1,500.00083023 HSA QUARTERLY CONTRIBUTIONS 011-010-130-513030 2,000.00083023 HSA QUARTERLY CONTRIBUTIONS 011-020-200-513030 1,000.00083023 HSA QUARTERLY CONTRIBUTIONS 011-030-300-513030 10,500.00083023 HSA QUARTERLY CONTRIBUTIONS 011-040-400-513030 2,000.00083023 HSA QUARTERLY CONTRIBUTIONS 011-040-405-513030 1,500.00083023 HSA QUARTERLY CONTRIBUTIONS 011-040-415-513030 500.00083023 HSA QUARTERLY CONTRIBUTIONS 011-040-420-513030 500.00083023 HSA QUARTERLY CONTRIBUTIONS 011-040-430-513030 4,000.00083023 HSA QUARTERLY CONTRIBUTIONS 055-050-555-513030 500.00083023 HSA QUARTERLY CONTRIBUTIONS 055-050-575-513030 2,000.00083023 HSA QUARTERLY CONTRIBUTIONS 055-050-580-513030 1,500.00083023 HSA QUARTERLY CONTRIBUTIONS 055-050-585-513030 1,500.00083023 HSA QUARTERLY CONTRIBUTIONS 055-050-586-513030- 3,500.00083023 HSA QUARTERLY CONTRIBUTIONS 055-050-590-513030 500.00083023 HSA QUARTERLY CONTRIBUTIONS 056-060-600-513030 1,000.00083023 HSA QUARTERLY CONTRIBUTIONS 058-070-700-513030 2,000.00Invoice Total: 40,500.009/7/2023 3,300.00Invoice Description Account PO or Contract Line Item Amount090623RETIREE HEALTH INSURANCE REIMBURSMENT011-010-120-513035 3,300.00Invoice Total: 3,300.009/7/2023 250.00Invoice Description Account PO or Contract Line Item AmountVENDOR - 6399 - JOE DELIAPAYMENT # 611691VENDOR - 1315 - JEFFREY GRAVESPAYMENT # 611690Page 4 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023202309004VPD POLYGRAPH EXAMINATION 011-030-300-529215 20230053 250.00Invoice Total: 250.009/7/2023 9.40Invoice Description Account PO or Contract Line Item Amount11092319 TRANSLATION SERVICES 011-030-300-529220 20230162 9.40Invoice Total: 9.409/7/2023 20,644.00Invoice Description Account PO or Contract Line Item Amount2968 COUNTER TOP INSTALLATION 011-040-415-660000 20230172 20,644.00Invoice Total: 20,644.009/7/2023 491.17Invoice Description Account PO or Contract Line Item Amount199972 AUTO PARTS 011-040-420-522000 240014 26.28Invoice Total: 26.28200039 AUTO PARTS 011-040-420-522000 240014 21.72Invoice Total: 21.72200444 AUTO PARTS 011-040-420-522000 240014 377.73Invoice Total: 377.73200469 AUTO PARTS 011-040-420-522000 240014 65.44Invoice Total: 65.449/7/2023 68.00Invoice Description Account PO or Contract Line Item Amount1276 CAR WASH SERVICES 07/23 011-030-300-527000 240063 68.00Invoice Total: 68.00VENDOR - 309 - NAPA AUTO PARTSPAYMENT # 611694VENDOR - 870 - PARNUSU TOV SNCPAYMENT # 611695VENDOR - 3272 - LANGUAGE LINE SERVICES, INCPAYMENT # 611692VENDOR - 6667 - MEGA RENOVATION, INCPAYMENT # 611693Page 5 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/20239/7/2023 19,342.02Invoice Description Account PO or Contract Line Item Amount3118819TEMPORARY STAFFING WEEK ENDING 6/18/23055-050-595-529215 20230183 3,230.40Invoice Total: 3,230.403119049TEMPORARY STAFFING WEEK ENDING 6/25/23055-050-595-529215 20230183 3,230.40Invoice Total: 3,230.403119950TEMPORARY STAFFING WEEK ENDING 07/23/23055-050-595-529215 20230183 3,230.40Invoice Total: 3,230.403120755TEMPORARY STAFFING WEEK ENDING 08/06/23055-050-595-529215 20230183 3,230.40Invoice Total: 3,230.403121154TEMPORARY STAFFING WEEK ENDING 08/13/23055-050-595-529215 20230183 3,230.40Invoice Total: 3,230.403121404TEMPORARY STAFFING WEEK ENDING 8/20/23055-050-595-529215 20230183 3,190.02Invoice Total: 3,190.029/7/2023 1,455.00Invoice Description Account PO or Contract Line Item AmountVE23013 ON-CALL TRAFFIC ENGINEERING SERVICE 011-040-430-529215 CS-1201 1,455.00Invoice Total: 1,455.009/7/2023 34.20Invoice Description Account PO or Contract Line Item Amount398910000 ASPHALT 058-070-700-529000 240045 13.44Invoice Total: 13.4439892 ASPHALT 058-070-700-529000 240045 20.76VENDOR - 6956 - QUANTUM QUALITY CONSULTING, INCPAYMENT # 611697VENDOR - 1845 - SECURITY PAVING COMPANY, INCPAYMENT # 611698VENDOR - 7584 - POCH STAFFING, INCPAYMENT # 611696Page 6 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023Invoice Total: 20.769/7/2023 550.00Invoice Description Account PO or Contract Line Item Amount9128 COMPLIANCE SUPPORT SERVICES 011-010-120-529215 20230029 550.00Invoice Total: 550.009/7/2023 629.30Invoice Description Account PO or Contract Line Item Amount74515 FRONT AXLE & ALIGNMENT REPAIR 011-040-420-522000 240008 309.3074515 FRONT AXLE & ALIGNMENT REPAIR 011-040-420-529000 240008 320.00Invoice Total: 629.309/7/2023 156.00Invoice Description Account PO or Contract Line Item Amount437465987 PEST CONTROL SERVICES 011-040-415-529000 CS-1408 156.00Invoice Total: 156.009/7/2023 2,604.26Invoice Description Account PO or Contract Line Item Amount848411648 SOFTWARE SUBSCRIPTION 011-010-110-529110 PD-0178 1,302.13Invoice Total: 1,302.13848735791 DATABASE SUBSCRIPTION 011-010-110-529110 PD-0178 1,302.13Invoice Total: 1,302.139/7/2023 211,941.72Invoice Description Account PO or Contract Line Item Amount11531C01 PAVEMENT AND STRIPING SERVICES 011-040-430-660000 20230179 211,941.72Invoice Total: 211,941.72VENDOR - 866 - WGJ ENTERPRISES, INCPAYMENT # 611703VENDOR - 1973 - STEVEN J. BURRISPAYMENT # 611700VENDOR - 6985 - THE TERMINIX INTERNATIONAL COMPANYPAYMENT # 611701VENDOR - 141 - WEST PUBLISHING CORPORATIONPAYMENT # 611702VENDOR - 6018 - SHAW HR CONSULTINGPAYMENT # 611699Page 7 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/20239/12/2023 304.69Invoice Description Account PO or Contract Line Item Amount081523 EXPENSE REIMBURSMENT 011-010-100-529500 304.69Invoice Total: 304.699/14/2023 128.33Invoice Description Account PO or Contract Line Item Amount082923 REF. CLOSED ACCT# 378 CUST# 7254 055-000-000-110010 128.33Invoice Total: 128.339/14/2023 62.00Invoice Description Account PO or Contract Line Item Amount091223 LIVE SCAN REIMBURSEMENT 011-010-120-529215 62.00Invoice Total: 62.009/14/2023 100.00Invoice Description Account PO or Contract Line Item Amount0912232023 EMPLOYEE EVENT PHOTOBOOTH (DEPOSIT)011-010-120-529690 20240123 100.00Invoice Total: 100.009/14/2023 948.15Invoice Description Account PO or Contract Line Item Amount082923REF. CLOSED ACCT# 1003 CUST# 5226 (FANTASY DYEING)055-000-000-110010 948.15Invoice Total: 948.159/14/2023 842.33Invoice Description Account PO or Contract Line Item Amount5610056 RADIO EQUIPMENT MAINTENANCE 09/23 011-030-300-529000 PD-0186 842.33VENDOR - 6054 - BEAR COMMUNICATIONS INCPAYMENT # 611709VENDOR - 7689 - ADRIAN BARRAZAPAYMENT # 611706VENDOR - 7671 - ANTHONY BALLONADOPAYMENT # 611707VENDOR - 7684 - AZIS AHMADPAYMENT # 611708VENDOR - 5863 - LETICIA LOPEZPAYMENT # 611704VENDOR - 7682 - A&H IMPORTS, INCPAYMENT # 611705Page 8 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023Invoice Total: 842.339/14/2023 9,526.37Invoice Description Account PO or Contract Line Item Amount091123 2023 EMPLOYEE RECOGNITION EVENT 011-010-120-529690 20240055 9,526.37Invoice Total: 9,526.379/14/2023 84.83Invoice Description Account PO or Contract Line Item Amount32657 AUTO PARTS 011-040-420-522000 240016 84.83Invoice Total: 84.839/14/2023 140.00Invoice Description Account PO or Contract Line Item Amount649116 WELDING SUPPLIES 055-050-586-529003- 240040 140.00Invoice Total: 140.009/14/2023 3,000.00Invoice Description Account PO or Contract Line Item Amount081423 CUSTOMER INCENTIVE PROGRAM 055-050-595-529702 3,000.00Invoice Total: 3,000.009/14/2023 1,628.02Invoice Description Account PO or Contract Line Item Amount125510434 AUTO PARTS 011-040-420-522000 240012 1,628.02Invoice Total: 1,628.029/14/2023 1,547.82Invoice Description Account PO or Contract Line Item Amount090723 GARNISHMENT 011-000-000-210260 1,547.82VENDOR - 4181 - FRANCHISE TAX BOARDPAYMENT # 611715VENDOR - 310 - CRAIG WELDING SUPPLY, COPAYMENT # 611712VENDOR - 7686 - DOUBLE BARGAIN INCPAYMENT # 611713VENDOR - 6696 - ELLIOTT AUTO SUPPLY CO, INCPAYMENT # 611714VENDOR - 7466 - CALIFORNIA COMMERCE CLUB, INCPAYMENT # 611710VENDOR - 4163 - CENTRAL FORD AUTOMOTIVE, INC.PAYMENT # 611711Page 9 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023Invoice Total: 1,547.829/14/2023 500.00Invoice Description Account PO or Contract Line Item Amount082923 REF. CLOSED ACCT# 921 CUST# 6477 055-450-575-450010 500.00Invoice Total: 500.009/14/2023 1,393.78Invoice Description Account PO or Contract Line Item Amount13669269 AMINO ACID SOLVENT 055-050-586-520235- 240079 1,393.78Invoice Total: 1,393.789/14/2023 100.00Invoice Description Account PO or Contract Line Item Amount081023ATTENDANCE STIPEND BIC MEETING 08.10.23011-010-150-529215 100.00Invoice Total: 100.009/14/2023 519.77Invoice Description Account PO or Contract Line Item Amount202762677 OFFSITE BACKUP STORAGE 011-010-110-526010 20240021 519.77Invoice Total: 519.779/14/2023 60.00Invoice Description Account PO or Contract Line Item Amount091123 REIMBURSEMENT - D2 CERTIFICATE FEE 058-070-700-529670 60.00Invoice Total: 60.009/14/2023 500.49Invoice Description Account PO or Contract Line Item AmountVENDOR - 5333 - LA COUNTY SHERIFF'S DEPT.PAYMENT # 611721VENDOR - 6927 - HECTOR MORFINPAYMENT # 611718VENDOR - 829 - IRON MOUNTAIN, INCPAYMENT # 611719VENDOR - 5308 - JOSEPH ALVARADOPAYMENT # 611720VENDOR - 7683 - G.B.Y CORPPAYMENT # 611716VENDOR - 1355 - HACH COMPANYPAYMENT # 611717Page 10 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023090723 GARNISHMENT 011-000-000-210260 500.49Invoice Total: 500.499/14/2023 100.00Invoice Description Account PO or Contract Line Item Amount071323ATTENDANCE STIPEND VERNON HOUSING 07.12.23011-040-410-529215 100.00Invoice Total: 100.009/14/2023 52.00Invoice Description Account PO or Contract Line Item Amount082923 LIVE SCAN REIMBURSEMENT 011-010-120-529215 52.00Invoice Total: 52.009/14/2023 408.86Invoice Description Account PO or Contract Line Item Amount201162 AUTO PARTS 011-040-420-522000 240014 49.84Invoice Total: 49.84201195 AUTO PARTS 011-040-420-522000 240014 160.95Invoice Total: 160.95201303 AUTO PARTS 011-040-420-522000 240014 79.94Invoice Total: 79.94201458 AUTO PARTS 011-040-420-522000 240014 118.13Invoice Total: 118.139/14/2023 100.00Invoice Description Account PO or Contract Line Item Amount081023ATTENDANCE STIPEND BIC MEETING 08.10.23011-010-150-529215 100.00Invoice Total: 100.00VENDOR - 309 - NAPA AUTO PARTSPAYMENT # 611724VENDOR - 6420 - NAVDEEP SINGH SACHDEVAPAYMENT # 611725VENDOR - 6716 - MARLENE ELSA YBARRAPAYMENT # 611722VENDOR - 7681 - MIGUEL HERNANDEZ ACOSTAPAYMENT # 611723Page 11 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/20239/14/2023 1,613.04Invoice Description Account PO or Contract Line Item Amount091123RETIREE HEALTH PLAN REIMBURSEMENT (Q3)011-010-120-513035 1,613.04Invoice Total: 1,613.049/14/2023 88.40Invoice Description Account PO or Contract Line Item Amount3049484948 AUTO PARTS 011-040-420-522000 240015 88.40Invoice Total: 88.409/14/2023 6,000.00Invoice Description Account PO or Contract Line Item Amount081423 CUSTOMER INCENTIVE PROGRAM 055-050-595-529702 6,000.00Invoice Total: 6,000.009/14/2023 9,586.58Invoice Description Account PO or Contract Line Item Amount523284 VENDOR & BID SOFTWARE FY 23-24 011-010-110-529110 IT-0178 9,586.58Invoice Total: 9,586.589/14/2023 6,460.80Invoice Description Account PO or Contract Line Item Amount3121673TEMPORARY STAFFING WEEK ENDING 08/27/23055-050-595-529215 20230183 3,230.40Invoice Total: 3,230.403121923TEMPORARY STAFFING WEEK ENDING 09/08/23055-050-595-529215 20230183 3,230.40Invoice Total: 3,230.40VENDOR - 7584 - POCH STAFFING, INCPAYMENT # 611730VENDOR - 5934 - O'REILLY AUTO ENTERPRISES, LLCPAYMENT # 611727VENDOR - 7685 - PAPER PLUS CONNECTION INCPAYMENT # 611728VENDOR - 6493 - PLANETBIDS, INCPAYMENT # 611729VENDOR - 1148 - NORMAN SUTHERLINPAYMENT # 611726Page 12 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/20239/14/2023 3,284.47Invoice Description Account PO or Contract Line Item Amount83311 FILTER SUPPLIES 055-050-560-529000 230425 697.29Invoice Total: 697.2983433 FILTER SUPPLIES 055-050-586-529000- 230426 191.4583433 FILTER SUPPLIES 055-050-586-529000- 230426 2,395.73Invoice Total: 2,587.189/14/2023 60.00Invoice Description Account PO or Contract Line Item Amount090623 REIMBURSEMENT - D2 CERTIFICATION FEE 058-070-700-529670 60.00Invoice Total: 60.009/14/2023 80.00Invoice Description Account PO or Contract Line Item Amount090623 REIMBURSEMENT - D2 CERTIFICATION FEE 058-070-700-529670 80.00Invoice Total: 80.009/14/2023 100.00Invoice Description Account PO or Contract Line Item Amount071323ATTENDANCE STIPEND VERNON HOUSING 07.12.23011-040-410-529215 100.00Invoice Total: 100.009/14/2023 85.00Invoice Description Account PO or Contract Line Item Amount74631 FRONT & BACK BRAKE INSPECTION 011-040-420-529000 240008 85.00Invoice Total: 85.00VENDOR - 5146 - ROBERTO ZEPEDAPAYMENT # 611733VENDOR - 6717 - RONIT DAHAN-EDRYPAYMENT # 611734VENDOR - 1973 - STEVEN J. BURRISPAYMENT # 611735VENDOR - 7252 - PURE PROCESS FILTRATION, INCPAYMENT # 611731VENDOR - 3763 - RAFAEL CASTELLANOSPAYMENT # 611732Page 13 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/20239/14/2023 1,302.13Invoice Description Account PO or Contract Line Item Amount848892983 DATABASE SUBSCRIPTION 011-010-110-529110 PD-0178 1,302.13Invoice Total: 1,302.13VENDOR - 141 - WEST PUBLISHING CORPORATIONPAYMENT # 611736Page 14 of 29
4,123,445.199/8/2023 3,000.00Invoice Description Account PO or Contract Line Item Amount4161216946082523FILING SB1029, WATER SYSTEMS BONDS 2020 SERIES A058-070-700-529225 FI-0033 1,000.00Invoice Total: 1,000.004161217019082523SB1029 FILING ELECTRIC BONDS 2021/2022 SERIES A055-050-580-529225 FI-0033 1,000.00Invoice Total: 1,000.004161217313082523SB1029 FILING ELECTRIC BONDS 2022 SERIES A055-050-580-529225 FI-0033 1,000.00Invoice Total: 1,000.009/8/2023 18,408.49Invoice Description Account PO or Contract Line Item AmountVERJUL23 POTABLE WATER CHARGES 07/23 058-070-700-520130 8,057.69VERJUL23 POTABLE WATER CHARGES 07/23 055-050-586-520135- 10,350.80Invoice Total: 18,408.499/8/2023 4,045.67Invoice Description Account PO or Contract Line Item Amount070123 PRODUCER MEMBER DUES FY2023-2024 058-070-700-529550 4,045.67Invoice Total: 4,045.679/8/2023 120.00Invoice Description Account PO or Contract Line Item Amount1000618435 MONITORING SERVICES 1Q FY24 055-050-586-520231- 20240086 120.00Invoice Total: 120.009/8/2023 185.00CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023VENDOR - 1917 - CENTRAL BASIN WATER ASSOCATIONPAYMENT # 15703VENDOR - 7326 - COSCO FIRE PROTECTION, INCPAYMENT # 15704VENDOR - 947 - DAILY JOURNAL CORPORATIONPAYMENT # 15705ELECTRONIC TOTAL:VENDOR - 1413 - BLX GROUP, LLCPAYMENT # 15701VENDOR - 1401 - CENTRAL BASIN MWDPAYMENT # 15702Page 15 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023Invoice Description Account PO or Contract Line Item AmountB3571325 PUBLICATION SERVICES 011-010-125-525000 185.00Invoice Total: 185.009/8/2023 67.43Invoice Description Account PO or Contract Line Item Amount155776 PARTS & SUPPLIES 011-040-420-522000 240005 67.43Invoice Total: 67.439/8/2023 798.65Invoice Description Account PO or Contract Line Item Amount127700 PARTS & SUPPLIES 058-070-700-522000 240043 105.10Invoice Total: 105.10127781 PARTS & SUPPLIES 058-070-700-529000 240043 590.98Invoice Total: 590.98127951 PARTS & SUPPLIES 058-070-700-529000 240043 102.57Invoice Total: 102.579/8/2023 33,909.09Invoice Description Account PO or Contract Line Item Amount2226820 FUEL 011-000-000-120030 240130 33,909.09Invoice Total: 33,909.099/8/2023 200.00Invoice Description Account PO or Contract Line Item Amount3094666345 SUBSCRIPTION 08/23 011-010-115-529600 LD-0045 200.00Invoice Total: 200.009/8/2023 370.31Invoice Description Account PO or Contract Line Item AmountVENDOR - 6884 - RELX, INCPAYMENT # 15709VENDOR - 6340 - S & J SUPPLY COMPANY, INCPAYMENT # 15710VENDOR - 399 - GARVEY EQUIPMENT COMPANYPAYMENT # 15706VENDOR - 804 - LB JOHNSON INDUSTRIAL HARDWAREPAYMENT # 15707VENDOR - 209 - MERRIMAC PETROLEUM, INC.PAYMENT # 15708Page 16 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023S100210967001 PARTS & SUPPLIES 058-070-700-522000 230396 370.31Invoice Total: 370.319/8/2023 9,409.18Invoice Description Account PO or Contract Line Item Amount6017211 ANALOG INPUT MODULE 055-050-586-529000- 20240065 9,409.18Invoice Total: 9,409.189/8/2023 1,250.83Invoice Description Account PO or Contract Line Item Amount27600 BUSINESS CARDS (SUN) 055-050-595-522000 230428 109.15Invoice Total: 109.1527601 ENVELOPES 055-050-595-522000 230429 1,141.68Invoice Total: 1,141.689/8/2023 93.67Invoice Description Account PO or Contract Line Item Amount119768 NAMEPLATES 011-040-400-522000 230285 16.37119768 NAMEPLATES 011-040-400-522000 230285 16.39119768 NAMEPLATES 011-040-405-522000 230285 17.55119768 NAMEPLATES 011-040-405-522000 230285 17.17Invoice Total: 67.48OE117096 NAMEPLATE - M. GARCIA 011-040-400-522000 230286 26.19Invoice Total: 26.199/8/2023 34,883.72Invoice Description Account PO or Contract Line Item Amount202313 QUARTERLY PAYMENT NO. 13 058-000-000-272010 34,883.72Invoice Total: 34,883.72VENDOR - 3775 - STAPLEMAN MEDIA SERVICES, INC.PAYMENT # 15712VENDOR - 6780 - THE HITT COMPANIES, INCPAYMENT # 15713VENDOR - 1658 - WATER REPLENISHMENT DISTRICTPAYMENT # 15714VENDOR - 7361 - SIEMENS ENERGY, INCPAYMENT # 15711Page 17 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/20239/8/2023 3,812.27Invoice Description Account PO or Contract Line Item Amount5641840 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 337.37Invoice Total: 337.375641841 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 337.37Invoice Total: 337.375641842 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 337.37Invoice Total: 337.375641843 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 337.37Invoice Total: 337.375641844 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 337.37Invoice Total: 337.375641846 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 387.97Invoice Total: 387.975644460 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 337.37Invoice Total: 337.375644461 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 387.97Invoice Total: 387.975644463 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 337.37Invoice Total: 337.375644464 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 337.37Invoice Total: 337.375644474 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 337.37Invoice Total: 337.379/8/2023 1,984.65Invoice Description Account PO or Contract Line Item Amount625768 STORAGE SERVICES 011-010-125-529215 409.00Invoice Total: 409.00626231 STORAGE SERVICES 011-010-125-529215 1,575.65VENDOR - 7110 - WATERLINE TECHNOLOGIES, INCPAYMENT # 15715VENDOR - 3584 - WILLIAMS SERVICE CORPORATIONPAYMENT # 15716Page 18 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023Invoice Total: 1,575.659/8/2023 388,821.30Invoice Description Account PO or Contract Line Item Amount202309053161099192RECALCULATION CHARGES 09/22 055-050-590-520150 2,789.43202309053161099192RECALCULATION CHARGES 09/22 055-050-590-520170 (497.81)202309053161099192RECALCULATION CHARGES 09/22 055-050-590-520180 (6,301.21)202309053161099192RECALCULATION CHARGES 09/22 055-050-590-520190 (700.21)202309053161099192RECALCULATION CHARGES 05/23 055-050-590-520150 (1,556.96)202309053161099192RECALCULATION CHARGES 05/23 055-050-590-520190 (7.01)202309053161099192RECALCULATION CHARGES 05/23 055-050-590-520170 170.54202309053161099192INITIAL CHARGES 08/23 055-050-590-520150 387,200.93202309053161099192INITIAL CHARGES 08/23 055-050-590-520170 (4,723.33)202309053161099192INITIAL CHARGES 08/23 055-050-590-520190 1,200.32202309053161099192INITIAL CHARGES 08/23 055-050-590-520210 11,246.61Invoice Total: 388,821.309/7/2023 1,750.00Invoice Description Account PO or Contract Line Item Amount100000017249950GASB 68 REPORTING SERVICES FEE 011-010-130-529225 1,750.00Invoice Total: 1,750.00VENDOR - 2412 - CALIFORNIA ISOPAYMENT # 15719VENDOR - 714 - CALPERSPAYMENT # 15753Page 19 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/20239/15/2023 3,643.76Invoice Description Account PO or Contract Line Item Amount19782764 SURVEILLANCE CAMERAS FOR CITY HALL 011-010-110-522010 240132 3,643.76Invoice Total: 3,643.769/15/2023 15,802.00Invoice Description Account PO or Contract Line Item Amount296063070 MEDICAL RETIREES 09/23 011-010-120-513035 15,802.00Invoice Total: 15,802.009/15/2023 21,762.24Invoice Description Account PO or Contract Line Item AmountIVC32187 TPA FEES 07/23 011-010-120-529220 6,508.66Invoice Total: 6,508.66IVC32617 TPA FEES 08/23 011-010-120-529220 7,999.50Invoice Total: 7,999.50IVC32851 TPA FEES 09/23 011-010-120-529220 7,254.08Invoice Total: 7,254.089/15/2023 2,582.25Invoice Description Account PO or Contract Line Item Amount4163556931 Uniform Services 055-050-586-524000- LP-0663 224.634163556931 Uniform Services 056-060-600-524000 LP-0663 79.154163556931 Uniform Services 058-070-700-524000 LP-0663 155.074163556931 Uniform Services 055-050-550-524000 LP-0663 15.364163556931 Uniform Services 055-050-555-524000 LP-0663 170.62Invoice Total: 644.834164970574 UNIFORM RENTAL SERVICE 055-050-586-524000- LP-0663 224.634164970574 UNIFORM RENTAL SERVICE 056-060-600-524000 LP-0663 79.154164970574 UNIFORM RENTAL SERVICE 058-070-700-524000 LP-0663 159.46VENDOR - 5182 - ANTHEM BLUE CROSSPAYMENT # 15755VENDOR - 4303 - ATHENS INSURANCE SERVICES, INCPAYMENT # 15756VENDOR - 5490 - CINTAS CORPORATION NO. 2PAYMENT # 15757VENDOR - 5460 - 247CCTV, INCPAYMENT # 15754Page 20 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/20234164970574 UNIFORM RENTAL SERVICE 055-050-550-524000 LP-0663 15.364164970574 UNIFORM RENTAL SERVICE 055-050-555-524000 LP-0663 170.62Invoice Total: 649.224165690132 UNIFORM RENTAL SERVICE 055-050-586-524000- LP-0663 224.634165690132 UNIFORM RENTAL SERVICE 056-060-600-524000 LP-0663 79.154165690132 UNIFORM RENTAL SERVICE 058-070-700-524000 LP-0663 153.324165690132 UNIFORM RENTAL SERVICE 055-050-550-524000 LP-0663 15.364165690132 UNIFORM RENTAL SERVICE 055-050-555-524000 LP-0663 170.62Invoice Total: 643.084166411865 UNIFORM RENTAL SERVICE 055-050-586-524000- LP-0663 224.634166411865 UNIFORM RENTAL SERVICE 056-060-600-524000 LP-0663 79.154166411865 UNIFORM RENTAL SERVICE 058-070-700-524000 LP-0663 155.364166411865 UNIFORM RENTAL SERVICE 055-050-550-524000 LP-0663 15.364166411865 UNIFORM RENTAL SERVICE 055-050-555-524000 LP-0663 170.62Invoice Total: 645.129/15/2023 274,264.00Invoice Description Account PO or Contract Line Item Amount108112 AUGUST 2023 055-050-590-520160 274,264.00Invoice Total: 274,264.009/15/2023 1,450,399.27Invoice Description Account PO or Contract Line Item AmountC0011480 FIRE PROTECTION SERVICES 10/23 011-030-305-529215 1,392,735.45C0011480 FIRE PROTECTION SERVICES 10/23 011-030-305-529215 30,142.22C0011480 FIRE PROTECTION SERVICES 10/23 011-030-305-529215 27,521.60Invoice Total: 1,450,399.279/15/2023 2,000.00Invoice Description Account PO or Contract Line Item AmountVENDOR - 7262 - CITADEL ENERGY MARKETING, LLCPAYMENT # 15758VENDOR - 1444 - COUNTY OF LOS ANGELESPAYMENT # 15759VENDOR - 7533 - DAMION PASION JONESPAYMENT # 15760Page 21 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023116094000313 PUBLIC WORKS CONFERENCE PROJECT 011-040-415-660000 20230136 2,000.00Invoice Total: 2,000.009/15/2023 7,388.00Invoice Description Account PO or Contract Line Item AmountVERN95 OCTOBER 2023 055-050-590-529215 LP-0463 7,388.00Invoice Total: 7,388.009/15/2023 112,925.00Invoice Description Account PO or Contract Line Item Amount3446723 AUGUST 2023 055-050-590-520160 112,925.00Invoice Total: 112,925.009/15/2023 1,305.00Invoice Description Account PO or Contract Line Item Amount354477 COMPLIANCE SERVICES 06/25-07/22/23 055-050-580-529225 20240064 1,305.00Invoice Total: 1,305.009/15/2023 454.70Invoice Description Account PO or Contract Line Item Amount17852 ADDITIONAL PRI LINE 011-010-110-529110 IT-0172 454.70Invoice Total: 454.709/15/2023 5,260.51Invoice Description Account PO or Contract Line Item Amount340366 COMPLIANCE SERVICES 04/02-04/29/23 055-050-580-529225 LP-0570 5,260.51Invoice Total: 5,260.519/15/2023 461.86Invoice Description Account PO or Contract Line Item AmountVENDOR - 7353 - EXTENDED OFFICE SOLUTIONS, INCPAYMENT # 15764VENDOR - 6899 - G2 INTEGRATED SOLUTIONS, LLCPAYMENT # 15765VENDOR - 1712 - GRAINGER, COPAYMENT # 15766VENDOR - 5658 - DAVID E DANPAYMENT # 15761VENDOR - 4116 - EDF, INC.PAYMENT # 15762VENDOR - 6519 - EN ENGINEERING, LLCPAYMENT # 15763Page 22 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/20239829117440 PARTS & SUPPLIES 011-040-415-522000 240117 307.90Invoice Total: 307.909830925930 PARTS & SUPPLIES 011-040-415-522000 240117 153.96Invoice Total: 153.969/15/2023 10,782.82Invoice Description Account PO or Contract Line Item Amount36X00123 DISPOSAL SERVICES 06/23 011-040-430-529215 CS-1371 3,599.24Invoice Total: 3,599.2437X00116 DISPOSAL SERVICES 07/23 011-040-430-529215 CS-1371 2,826.96Invoice Total: 2,826.9638X11665 DISPOSAL SERVICE 08/23011-040-430-529215 CS-1371 4,356.62Invoice Total: 4,356.629/15/2023 1,250.00Invoice Description Account PO or Contract Line Item Amount823001688006 AUGUST 2023 055-050-590-529215 167.50Invoice Total: 167.50823001688088 AUGUST 2023 055-050-590-529215 1,082.50Invoice Total: 1,082.509/15/2023 440.00Invoice Description Account PO or Contract Line Item Amount090623 TUITION REIMBURSEMENT 011-010-120-529680 440.00Invoice Total: 440.009/15/2023 1,234.03Invoice Description Account PO or Contract Line Item Amount10683464 PARTS & SUPPLIES 055-050-586-529000- 240126 380.39Invoice Total: 380.39VENDOR - 1150 - MCMASTER-CARR SUPPLY COMPANYPAYMENT # 15770VENDOR - 5350 - HAUL-AWAY RUBBISH SERVICE CO., INCPAYMENT # 15767VENDOR - 4500 - ICE US OTC COMMODITY MARKETS, LLCPAYMENT # 15768VENDOR - 1668 - LORENZO GAYTANPAYMENT # 15769Page 23 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/202310757886 PARTS & SUPPLIES 055-050-586-529000- 240126 61.87Invoice Total: 61.8710850573 PARTS & SUPPLIES 055-050-586-529000- 240126 757.65Invoice Total: 757.6511066811 PARTS & SUPPLIES 055-050-586-529000- 240126 34.12Invoice Total: 34.129/15/2023 5,424.68Invoice Description Account PO or Contract Line Item Amount2555 POSTAGE FEES 011-010-130-522000 FI-0041 5,000.00Invoice Total: 5,000.00823652 POSTAGE FEES 08/23 011-010-130-522000 FI-0041 424.68Invoice Total: 424.689/15/2023 68,898.75Invoice Description Account PO or Contract Line Item Amount1840 TECHNICAL DESIGN 08/23 058-070-700-660000 LP-0590-1 2,422.501840 TECHNICAL DESIGN 08/23 058-070-700-529000 LP-0590-1 7,695.001840 TECHNICAL DESIGN 08/23 058-070-700-660000 LP-0590-1 56,857.501840 TECHNICAL DESIGN 08/23 055-050-580-529225 LP-0590-1 1,923.75Invoice Total: 68,898.759/15/2023 112,575.00Invoice Description Account PO or Contract Line Item Amount239742 AUGUST 2023 055-050-590-520160 112,575.00Invoice Total: 112,575.009/15/2023 782.00Invoice Description Account PO or Contract Line Item Amount243854 PROFESSIONAL SERVICES 07/23 095-095-905-705020- 782.00VENDOR - 5908 - PACIFIC SUMMIT ENERGY, LLCPAYMENT # 15773VENDOR - 3900 - RICHARDS, WATSON & GERSHONPAYMENT # 15774VENDOR - 6687 - NEXTDAY DELIVERY SERVICE, LLCPAYMENT # 15771VENDOR - 5614 - NORTHWEST ELECTRICAL SERVICES, LLCPAYMENT # 15772Page 24 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023Invoice Total: 782.009/15/2023 103,919.00Invoice Description Account PO or Contract Line Item Amount10247 SECURITY SERVICES 07/23 055-050-555-529215 20230234 83,135.2010247 SECURITY SERVICES 07/23 055-050-580-529215 20230234 20,783.80Invoice Total: 103,919.009/15/2023 41,835.24Invoice Description Account PO or Contract Line Item AmountDH0923 SEPTEMBER 2023 055-050-590-520154 41,835.24Invoice Total: 41,835.249/15/2023 248,533.90Invoice Description Account PO or Contract Line Item AmountDS20923 SEPTEMBER 2023 055-050-590-520154 248,533.90Invoice Total: 248,533.909/15/2023 24,669.00Invoice Description Account PO or Contract Line Item Amount7501585048 SEPTEMBER 2023 055-050-590-520170 24,669.00Invoice Total: 24,669.009/15/2023 25.78Invoice Description Account PO or Contract Line Item AmountOE122629 NAMEPLATE (SANDOVAL) 011-010-105-522000 240151 12.00OE122629 NAMEPLATE (SANDOVAL) 011-010-105-522000 240151 13.78Invoice Total: 25.789/15/2023 44,898.81VENDOR - 6780 - THE HITT COMPANIES, INCPAYMENT # 15779VENDOR - 2227 - US DEPARTMENT OF ENERGYPAYMENT # 15780VENDOR - 2517 - SCPPAPAYMENT # 15776VENDOR - 2517 - SCPPAPAYMENT # 15777VENDOR - 59 - SO CAL EDISONPAYMENT # 15778VENDOR - 6198 - S&S LABOR FORCE, INCPAYMENT # 15775Page 25 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023Invoice Description Account PO or Contract Line Item AmountGG1766W0823 AUGUST 2023 CAPACITY 055-050-590-520180 29,817.21GG1766W0823 JULY 2023 ENERGY FLOW 055-050-590-520150 15,081.60Invoice Total: 44,898.819/15/2023 371.10Invoice Description Account PO or Contract Line Item Amount5644475 SODIUM HYPOCHLORITE 058-070-700-520140 20240032 371.10Invoice Total: 371.109/15/2023 500.00Invoice Description Account PO or Contract Line Item Amount090523 MONTHLY RENT 09/23 055-050-595-529703- 20240080 500.00Invoice Total: 500.009/15/2023 1,724.63Invoice Description Account PO or Contract Line Item Amount300541 SATELLITE PHONE SERVICE 011-010-110-529110 240153 1,724.63Invoice Total: 1,724.639/15/2023 581,882.93Invoice Description Account PO or Contract Line Item Amount202309123161151119RECALCULATION CHARGES 06/23 055-050-590-520150 (92.63)202309123161151119RECALCULATION CHARGES 06/23 055-050-590-520170 (8.56)202309123161151119RECALCULATION CHARGES 06/23 055-050-590-520190 (1.06)202309123161151119RECALCULATION CHARGES 11/21 055-050-590-520190 (326.39)VENDOR - 7663 - WEST SOTO STREET PARTNERSPAYMENT # 15782VENDOR - 894 - WHENEVER COMMUNICATIONS, LLCPAYMENT # 15783VENDOR - 2412 - CALIFORNIA ISOPAYMENT # 15811VENDOR - 7110 - WATERLINE TECHNOLOGIES, INCPAYMENT # 15781Page 26 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023202309123161151119RECALCULATION CHARGES 11/21 055-050-590-520170 (13.35)202309123161151119RECALCULATION CHARGES 11/21 055-050-590-520150 (215.59)202309123161151119RECALCULATION CHARGES 8/21 055-050-590-520150 (9.70)202309123161151119RECALCULATION CHARGES 8/21 055-050-590-520190 (57.76)202309123161151119RECALCULATION CHARGES 5/23 055-050-590-520150 (1,259.08)202309123161151119RECALCULATION CHARGES 5/23 055-050-590-520170 121.43202309123161151119RECALCULATION CHARGES 5/23 055-050-590-520180 120.72202309123161151119RECALCULATION CHARGES 5/23 055-050-590-520190 102.77202309123161151119INITIAL CHARGES 08/23 055-050-590-520170 (9,624.20)202309123161151119INITIAL CHARGES 08/23 055-050-590-520190 (1,941.13)202309123161151119INITIAL CHARGES 08/23 055-050-590-520210 12,688.16202309123161151119INITIAL CHARGES 08/23 055-050-590-520150 582,399.30Invoice Total: 581,882.939/15/2023 298,704.00Invoice Description Account PO or Contract Line Item AmountPV0923 SEPTEMBER 2023 CAPACITY 055-050-590-520180 236,153.00PV0923 AUGUST 2023 ENERGY 055-050-590-520150 52,551.00PV0923 PROJECT PSF 055-000-000-122100 10,000.00Invoice Total: 298,704.009/15/2023 159,850.00VENDOR - 2517 - SCPPAPAYMENT # 15812VENDOR - 7225 - TWIN EAGLE HOLDINGS N.A., LLCPAYMENT # 15813Page 27 of 29
CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023Invoice Description Account PO or Contract Line Item Amount412504 AUGUST 2023 055-050-590-520160 159,850.00Invoice Total: 159,850.009/8/2023 1,747.55Invoice Description Account PO or Contract Line Item Amount090823_MULTI PARTS & SUPPLIES 011-040-415-52200024012920240035 1,382.39090823_MULTI PARTS & SUPPLIES 011-040-430-52200024012920240035 365.16Invoice Total: 1,747.559/15/2023 12,037.12Invoice Description Account PO or Contract Line Item Amount091523_MULTI PARTS & SUPPLIES 011-040-410-52200024012920240035 8,307.44091523_MULTI PARTS & SUPPLIES 011-040-415-52200024012920240035 3,729.68Invoice Total: 12,037.12VENDOR - 1552 - HOME DEPOT CREDIT SERVICESPAYMENT # 15815VENDOR - 1552 - HOME DEPOT CREDIT SERVICESPAYMENT # 15814Page 28 of 29
FUND EARLY CHECKS TOTAL ELECTRONIC TOTALGRAND TOTAL011 - GENERAL $ 339,356.09 $ 1,564,896.25 $ 1,904,252.34 055 - LIGHT & WATER $ 50,727.00 $ 2,436,512.72 $ 2,487,239.72 056 - NATURAL GAS $ 1,000.00 $ 316.60 $ 1,316.60 058 - WATER $ 2,234.20 $ 120,937.62 $ 123,171.82 095 - SEWC JPA $ 782.00 $ 782.00 $ 393,317.29 $ 4,123,445.19 $ 4,516,762.48 CITY OF VERNONOPERATING ACCOUNTWARRANT REGISTER NO. 118DATE 10/17/2023TotalPage 29 of 29
City Council Agenda Report
Meeting Date:October 17, 2023
From:Carlos Fandino, City Administrator
Department:City Administration
Submitted by:Diana Figueroa, Administrative Analyst
Subject
Fire Department Activity Report
Recommendation
Receive and file the August 2023 Fire Department Activity Report.
Background
Attached is a copy of a Fire Department Activity Report which covers the period of August 1
through August 31, 2023. The report is provided by Los Angeles County Fire and consists of
incident details and a summary for the month.
Fiscal Impact
There is no fiscal impact associated with this report.
Attachments
1. Fire Department Activity Report – August 2023
City Council Agenda Report
Meeting Date:October 17, 2023
From:Robert Sousa, Chief of Police
Department:Police
Submitted by:Donna Aggers, Records Manager
Subject
Police Department Activity Report
Recommendation
Receive and file the August 2023 Police Department Activity Report.
Background
The Vernon Police Department’s activity report consists of activity during the specified reporting
period, including a summary of calls for service, and statistical information regarding arrests,
traffic collisions, stored and impounded vehicles, recovered stolen vehicles, the number of
citations issued, and the number of reports filed.
Fiscal Impact
There is no fiscal impact associated with this report.
Attachments
1. August 2023 Police Department Activity Report
City Council Agenda Report
Meeting Date:October 17, 2023
From:Todd Dusenberry, General Manager of Public Utilities
Department:Public Utilities
Submitted by:Adriana Ramos, Administrative Analyst
Subject
Service Level Performance Agreements with USIP Communications, LLC
Recommendation
A. Approve and authorize the City Administrator to execute a Service Level Performance
Agreement and issue Change Orders with USIP Communications, LLC (USIPCOM), in
substantially the same form as submitted, in an amount not-to-exceed $333,252 and up to a 15%
contingency of $49,988, to provide the primary feed for Upstream Internet Access Services for
three years; and
B. Approve and authorize the City Administrator to execute a Service Level Performance
Agreement and issue Change Orders with USIPCOM, in substantially the same form as
submitted, in an amount not-to-exceed $289,704 and up to a 15% contingency of $43,456, to
provide the backup feed for Upstream Internet Access Services for three years.
Background
Vernon Public Utilities (VPU) Fiber Optic based Internet Access Service receives dedicated
wholesale internet circuits from upstream service providers. These internet circuits are then
provisioned through networking equipment at City Hall and other utility facilities to provide reliable
internet services to Vernon's businesses and residents.
Currently, VPU has contracts with two broadband providers, Lumen and USIPCOM, that are the
source lines used by VPU to provide internet services to residential and business customers. On
June 21, 2023, a Purchase Contract with Lumen was approved for an annual cost of $52,720.14
to provide the primary feed for Upstream Internet Access Services to VPU. The Lumen contract
is set to expire on June 18, 2024, but would be terminated upon completion of the Fujitsu
networking equipment project detailed below. Concurrently, on June 21, 2023, a Purchase
Contract with USIPCOM was approved for an annual cost of $66,373.16 to provide the backup
feed for Upstream Internet Access Services to VPU. The USIPCOM contract is set to expire on
June 14, 2024 and would be replaced should the transition to the proposed agreements be
approved. VPU’s existing fiber optic service is limited by the total bandwidth of these two
contracts. Bandwidth thresholds limit the number of new customers VPU can reliably add to the
fiber optics system and restrict the internet speeds offered to existing customers.
VPU’s fiber optic service was limited by the existing Fujitsu Network Communication networking
equipment (Fujitsu). To resolve this issue, on March 21, 2023, the City Council approved a Labor
and Materials Contract with Fujitsu for $717,765.97 to upgrade the existing fiber optic network
system and perform network migration services to facilitate the reliability and future growth of
VPU’s fiber optic system. The new networking equipment is expected to be completed by the
end of the calendar year 2023.
To meet the installation timeframe of the new Fujitsu networking equipment, VPU has identified
the need for new broadband service contracts to accommodate customers looking for higher
internet speeds and cost-effective options from the City. The proposed upgrade will provide a
more reliable, higher quality service, and various internet speed options for VPU's customers.
More importantly, the contracts will provide the ability to market and sustain the future growth of
the fiber system. With the increased bandwidth and upgrade of the existing networking
equipment, VPU plans to update its existing offerings and service packages for customers and
re-design the network distribution system to grow and serve more customers.
VPU contacted vendors who could meet its broadband requirements, including future growth
plans. VPU staff determined that USIPCOM can meet the service level requirements and
expectations. VPU recommends City Council approve a three-year Service Level Agreement with
USIPCOM. USIPCOM will provide the primary and backup feeds to the VPU fiber optic system.
The monthly cost for the primary feed is $9,257 ($333,252 for three years), plus a 15%
contingency or $49,988 for unforeseen changes in fees, taxes, etc., and the monthly cost for the
backup feed is $8,039 ($289,704 for three years which includes a $300 one-time installation fee)
plus a 15% contingency or $43,456 for unforeseen changes in fees, taxes, etc. USIPCOM will
secure each service line from different sources to provide the reliability and redundancy
necessary to meet VPU’s current and future requirements. The new services will each be offered
at 100G, which provides VPU and its customers with 100 times the bandwidth compared to
existing services.
Staff recommends upgrading the new service provider contract to facilitate the existing and future
growth of the VPU fiber optic system and offer high internet speeds to the City's residential and
business customers. Upon City Council approval and completion of the Fujitsu networking
equipment project, the existing contract with Lumen will be terminated at an approximate cost of
$28,000 in accordance with the agreed upon Terms and Conditions. Since the bid from Lumen
for a comparable new 100G service was priced at $19,851 per month ($238,212 for one year), it
is more cost-effective to terminate the service with Lumen and move forward with a secondary
service from USIPCOM.
The proposed agreements are exempt from the competitive bidding and competitive selection
requirements pursuant to Vernon Municipal Code Sections 3.32.110(A)(6) and 3.32.110(B)(1),
as these contracts are for the acquisition, sale or transmission of electrical power, natural gas,
water, or telecommunications for the Public Utilities Department, and would be commercially
unreasonable to procure these services through the standard procurement procedures.
USIPCOM’s Sale Order Forms have been reviewed and approved as to form by the City
Attorney’s Office.
Fiscal Impact
The fiscal impact is not-to-exceed $744,400, including contingencies, for the term of the
agreements. Sufficient funds are available in the Fiber Fund and approval of this action requires
a transfer of $68,000 from Fiber Fund, Professional Services – Other Account No. 059-080-800-
529215 to Fiber Fund, Transport Services – Telecom Account No. 059-080-800-520173 for the
current fiscal year and funds will be budgeted in subsequent years.
Attachments
1. USIP Communications, LLC – Sales Order (Primary Feed)
2. USIP Communications, LLC – Sales Order (Backup Feed)
3. Lumen Technologies – Order Form Terms and Conditions
Customer Name
City of Vernon
Sales Order: SO5690
Issued Date: 07-27-2023
03:43 PM
Due Date : 10-31-2023
USIPCommunications
3201 Northside Dr STE 109
RALEIGH, North Carolina 27615
Phone 800-972-5004
Contact
Tim Bass
Billing Address Shipping Address
4305 santa fe Avenue
Vernon, CA 90058
4305 santa fe Avenue
Vernon, CA 90058
Item Code Item Name Quantity List Price Item Total Discount Total After
Discount Total
PRO114 GigE
Dedicated Symmetrical 100G Fiber
service with SLAs. BGP routing will be
supported
1 $9,257 $9,257 0 (0 %)$9,257 $9,257
Items Total $9,257
Discount(0%)0
GRAND TOTAL($)$9,257
Contract Term Monthly Charge One-Time Charge
36 $9,257 $0
Customer Acceptance USIPCOM Acceptance
Print Name:Print Name:
Signature:Signature:
Title:Title:
Date:Date:
Terms and Conditions can be found at www.usipcom.com/legal
Important Information
Billing
Billing for Service will begin no later than two days after service is deemed ready for Billing and Invoicing by USIPCOM. Customer’s failure to
promptly schedule and activate the service will result in billing beginning before service can be utilized by the Customer. In addition, the
Customer is solely responsible for canceling any service with previous Provider.
Termination
Upon termination of the Service Agreement and/or the Service(s) not due to default, USIPCOM will disconnect, or will cause to be
disconnected, the Service(s) if notified by the Customer in writing via E-mail to support@usipcom.com with no less that forty calendar (40)
days’ notice prior to termination of the Agreement and/or Service(s). Please review Terms & Conditions and Legal Documents @
http://www.usipcom.com/legal
Customer Care & Support Contact Information
• Phone: 800-972-5004
• E-mail: support@usipcom.com
Sales Contact
• Name: Joe Willett
• E-mail: jwillett@usipcom.com
• Direct Phone: 919-439-3563
• Main Phone: 800-972-5004
Terms & Conditions
Terms & Conditions along with other important documents can be found at http://www.usipcom.com/legal/. Please review the Terms &
Conditions along with the Acceptable Use Policy, Service Level Agreement before signing for service. It is solely the customer's responsibility
to review the Terms & Conditions, Acceptable Use Policy, and Service Level Agreement located @ http://www.usipcom.com/legal
Customer Acceptance USIPCOM Acceptance
Print Name:Print Name:
Signature:Signature:
Title:Title:
Date:Date:
Payment Form
Please choose the desired payment method:
Direct Deposit/ACH Credit Card Paper Check
One-Time Charge Monthly Reoccurring Charge
Credit Card Authorization
Card Type: Card Number:
CVC (3 or 4 digit security code on back or front of credit card)
Expiration Date: Name on Card:
Billing Address:
City: State: ZIP: Country:
Customer Acceptance USIPCOM Acceptance
Print Name:Print Name:
Signature:Signature:
Title:Title:
Date:Date:
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Data Installation Guide
Product Installation Overview
Customers ordering a T1, NxT1, EOC, or Cable should expect installation to occur within an average 30-45 business days from the date of
order submission by USIPCOM to the underlying Carrier.
Customers ordering MPLS, DS3, OCx and Fiber Buildout should expect installation to occur within an average of 60-90
business days from the date of order submission by USIPCOM to the underlying Carrier(s).
All order submission will occur only after a completed contract has been presented and received by USIPCOM and the
Customer has been approved for any/all applicable credit.
It is important to understand that the average times to installation presented above are based on industry standards and
USIPCOM experience. Individual circumstances may dictate that these installation timeframes could be shorter or longer
than the aforementioned averages.
Orders may be expedited and are contingent upon Carrier capability and acceptance. A one-time non-recurring expedite
fee will be assessed on a Customer’s invoice. However, payment of this fee by the Customer does not guarantee a
specific timeframe or completion date.
Throughout the installation process a Customer will work with USIPCOM Installation Specialists and Activation Engineers.
The Installation Specialist will manage the installation process up to Service Activation and is responsible for interacting
with the Carrier to ensure all milestones are met, escalations and confirming with the Carrier and Customer that
contracted service is provisioned correctly. The Activation Engineer is responsible for activating and verifying service.
Installation Timeline
Day 1-3: Order is placed with the Carrier
USIPCOM will place the order with the underlying Carrier for Data service. The following requirements must be met by the
Customer prior to order placement:
Basic Requirements:
• Accurate address including suite number and onsite phone number
• Valid onsite contact with appropriate phone number
• Main point of entry (MPOE) location where the Local Exchange Carrier (LEC) will deliver service the building (i.e.
basement on first floor)
• DMARC location, the actual location within the building where the service is to be delivered (i.e. suite 100)
• Number of IPs desired and completed IP justification form if required by the Carrier
Important Note:
USIPCOM is not responsible for extending the circuit to the DMARC location unless the extension has been explicitly ordered and is listed as a
line item on the USIPCOM Service Order Form (SOF). Unless the DMARC extension is listed on the SOF the circuit will only be delivered to the
MPOE (as determined by the LEC) and any extension is the sole responsibility of the Customer. In general, any changes to the above
information or to the service order during the installation process could result in delays and additional fees.
After the order is placed with the Carrier a USIPCOM Installation Specialist will contact the Customer point of contact on record and complete
an introduction call to review the ordered service solution, address, contact information, and will confirm the Customer has access to the
customer portal.
Day 4-9: Carrier places order with Local Exchange Carrier (LEC)
The Installation Specialist will ensure the Carrier has initiated the design and engineering of the circuit so the order can be passed to the LEC.
The LEC will then begin the design and engineering of the local loop.
Day 10-20: Installation Date (Firm Order Commitment Date) Established
The LEC will provide a Firm Order Commitment (FOC) date for installation of the local loop. At this time, if a FOC date has not been
established the reason for delay will be relayed to the Customer.
Day 21-30: Local Loop is installed (Firm Order Commitment Date)
A technician from the LEC will install the local loop to the service location.The following requirements must be met in order for the technician to
complete installation:
Requirements:
• A customer contact must be onsite to allow the LEC technician access to the location and telco closet as applicable for an entire business
day.
Day 31-45: Service Activation
After the local loop has been installed and the LEC has tested and accepted with the Carrier, the Installation Specialist will schedule
an activation appointment with the Customer. The following requirements must be fulfilled prior to the activation appointment:
Requirements:
• Space and power must be allocated for all equipment components applicable to Data service and any necessary mounting boards or racks
shall be provided by the Customer
• Sufficient power outlets must be available for the power unit which requires a standard 120V AC plug. The power outlet must not be
overloaded and must be within 6’ of the Data Router
• Any DMARC extensions not ordered through USIPCOM must be complete
• All LAN devices and the Data Router must be wired/connected – USIPCOM does not provide patch cables or dispatch technicians to connect
any equipment to the circuit.
• The Data Router requires an operating environment with temperature ranges between 35-85° F and humidity of less than 90%,
noncondensing
• The environment must be free of excessive dust
• Customer must call in to USIPCOM at the scheduled time of the activation appointment
The USIPCOM Activation Engineer will bridge the Carrier on the phone with the Customer and conduct testing to ensure Data service is
working properly.
Day 60: Service Activation - DS3’s/OCX’s/Ethernet/Colocation/MPLS
DS3 and OCX Solutions have an installation interval of 60-90 business days. Actual installation timeline will vary as these
solutions may require build outs, special equipment, or other special requirements from the Carrier, LEC, and the
Customer.
The following Data Solutions may have additional requirements and specifications:
CO-LOCATION
In order to avoid any delays, it is the Customer’s responsibility to inform USIPCOM prior to order placement on what floor
their equipment is located. Customers needs to work with their existing vendors (hosting company / cross connect
provider) to determine where the circuit should be terminated and how the circuit shall be provided (i.e. open port on
MPOE, open port on Carrier POP, channel on existing facility). In some cases, a CFA/LOA will need to be provided by the
Customer. In addition, the Customer is also responsible for ordering the appropriate cross-connect from the MPOE to their
equipment.
ETHERNET
When purchasing an Ethernet solution from a Carrier, it is the Customer’s responsibility to ensure that the Carrier has
facilities going to the Customer’s floor. The Customer is responsible for extending this service either from the MPOE or
the Telco closet on their floor to their suite if desired.
MPLS
The Customer must work with USIPCOM on an implementation plan to ensure the appropriate sites are installed in the
order of importance. Customer must also provide their private IP addressing scheme and routing requirements. If the
Customer is getting voice, their bandwidth requirements for voice across this network must be understood and provided
to USIPCOM along with QOS requirements so the appropriate settings are implemented on the Carrier’s network.
Billing
Billing for Data Services will begin no later than two (2) business days after service is deemed ready for Billing and
Invoicing by USIPCOM. Customer failure to promptly schedule and activate the circuit will result in billing beginning
before service can be utilized by the Customer. In addition, the Customer is solely responsible for canceling any service
with previous Carrier, and for updating any email or web hosting IP addresses with the current provider. USIPCOM does
not support email or web hosting applications but can update any email or DNS records once the activation appointment
has been completed.
Multi-Site Solutions
Multi-site solutions such as MPLS are billed site by site and not when all sites are installed. If all sites are ordered at the
same time, each site will be billed as they are installed, tested, and accepted by the Carrier, regardless of whether
Customer has completed all necessary steps to activate Service or whether other sites in the MPLS network are ready for
activation.
Move Orders
In the event the Customer wishes to move service to a new location USIPCOM must be notified by an authorized contact
by emailing support@usipcom.com a minimum of sixty (60) business days prior to the move. USIPCOM will coordinate the
move of services once the new location is secure, has power, has a backboard or rack for equipment, and a new contract
with USIPCOM has been signed and processed. Please note that Customers that do not have a minimum of twelve (12)
months left on their existing contract will be re-termed for one (1) year upon completion of the move. The general
timeframe for Data service move orders is the same as the timeline noted above.
Customer Acceptance
Customer acknowledges that the preceding installation timeline is provided as a general timeline only and that USIPCOM
does not guarantee any specific date or timeframe for installation. Customer has read all of the requirement or
specification for Data Service installation. Customer further acknowledges that failure to meet any requirement or
specification may result in delays in the installation process. Customer further acknowledges that Billing/Invoicing for
Data Service(s) will begin no later than two (2) business days after service is deemed ready for activation by USIPCOM.
By signing below, Customer signatory certifies that (s)he is an officer or certified representative of the above listed
Company authorized to enter into a binding agreement(s) on behalf of said company and affirmed by seal below as of the
date below.
Customer Acceptance USIPCOM Acceptance
Print Name:Print Name:
Signature:Signature:
Title:Title:
Date:Date:
pg. 1
Terms & Conditions
Internet Services Terms and Conditions
These Service Terms and Conditions (the “Terms and Conditions”) apply to the Services (as
defined below) described in the Service Order Form (“SOF”) by and between USIPCOM, LLC.
(“Provider”) and the customer named in the SOF (“Customer”). Provider may amend these
Terms and Conditions from time to time by posting an amended version at
www/usipcom.com/legal/ and sending Customer written notice thereof. Such amendment will be
deemed accepted and become effective thirty (30) days after such notice (the “Proposed
Amendment Date”) unless Customer first gives Provider written notice of rejection of the
amendment. If Customer rejects such amendment, these Terms and Conditions will continue
pursuant to its original provisions and the amendment will become effective at the
commencement of the next Renewal Term (as defined below) following the Proposed
Amendment Date. Customer’s continued use of the Services following the effective date
of an amendment will confirm Customer’s consent thereto.
1. Service Description. Provider will provide Customer with the Services described in the SOF
for the Service Term so long as no Default (as defined below) has occurred. Customer has the
sole and exclusive responsibility for the installation, configuration, security (including, without
limitation, firewall security policies, even if Customer uses a third party to configure and
implement such measures), and integrity of all Customer facilities, systems, equipment, proxy
servers, software, networks, network configurations and the like (the “CPE” ) used in
conjunction with or related to the Services provided by Provider, unless Customer obtains such
CPE from Provider pursuant to a written agreement between Customer and Provider and
Provider expressly assumes any of such duties in writing.
2. Service Activation Date. The “Service Activation Date” means the date two (2) business
days after Provider deems the applicable Services ready for activation, which customarily will
follow Provider’s receipt of confirmation from any applicable underlying carrier(s) that the
Services are ready for activation; provided, however, with respect to MPLS Services (as defined
below) only (as identified on the SOF), the “Service Activation Date” means the earlier of (i) the
date two (2) business days after Provider deems the Services ready for activation, which
customarily will follow Provider’s receipt of confirmation from any applicable underlying
carrier(s) that the Services are ready for activation; and (ii) the date the Service is successfully
activated by the underlying carrier and confirmed tested and accepted by Customer and Provider.
Provider will notify Customer (via phone, email or other means) of the Service Activation Date.
For clarity, the Service Activation Date established by Provider will apply regardless of whether
Customer has completed all necessary steps to activate the Services.
3. Service Term. The initial Service Term will be as specified in any applicable SOF
(the “Initial Service Term”). The Initial Service Term will automatically extend thereafter upon
the same terms and conditions applicable during the Initial Service Term for additional
consecutive term(s) of one (1) year unless earlier terminated pursuant to these Terms and
pg. 2
Conditions or unless either party provides notice of nonrenewal to the other at least sixty (60)
days prior to the expiration of the then existing Service Term.
4. Service Availability. Provider may from time-to-time interrupt or otherwise impact Services
for routine maintenance. Provider will make commercially reasonable efforts to provide to
Customer reasonable advance notification (via phone, email or other means) of such
maintenance. Provider will use commercially reasonable efforts to perform such maintenance in
a manner that will not unreasonably interrupt Services. Provider normally will perform
maintenance between the hours of 11:30 PM and 6:00 AM Eastern. If Provider determines that
emergency maintenance is necessary for any reason, Provider will make commercially
reasonable efforts to notify Customer with respect to the anticipated down-time and/or other
information pertinent to the affected Services.
5. Support Provider. provides support for the Services only as described at
www.usipcom.com/legal/ pursuant to any applicable Service Level Agreement (“SLA”) posted
at (“www.usipcom/legal/USIPCOM-SLA. NOTWITHSTANDING ANY TERM OF THESE
TERMS AND CONDITIONS OR ANY APPLICABLE SLA TO THE CONTRARY,
PROVIDER DOES NOT SUPPORT ANY SERVICES BEYOND THE PROVIDER POINT OF
DEMARCATION, DEFINED AT WWW.USIPCOM.COM/LEGAL/. (e) theft, or (f) disaster. If
USIPCOM CPE requires maintenance not caused by one of the events set out in the sentence
above, USIPCOM or its agents shall either arrange to repair the CPE at Customer’s premises or
ship an equivalent pre-configured replacement to Customer. If replacement CPE is shipped to
Customer, Customer shall return the faulty CPE to USIPCOM within ten (10) days of receiving
the replacement CPE or pay for such CPE. Customer will not receive compensation for
downtime associated with CPE replacement or repair. In addition, if Customer has rented CPE,
Customer shall return (at Customer’s own expense) USIPCOM CPE to USIPCOM within ten
(10) days of termination. If this CPE is not returned in good working condition to USIPCOM
Customer shall be invoiced and pay for this CPE. Should reject to the terms and conditions set
forth in the Manufacturer’s or Publisher’s warranty, End-User license or agreement applicable to
such CPE or CPE Provider Service, with no warranty of any kind from USIPCOM. Should
customer receive purchased CPE that is damaged or dead on arrival Customer must notify
USIPCOM Customer Care within ten (10) days of receipt. Returns will only be accepted on
brand new factory-packaged products within thirty (30) days of the date CPE was shipped. All
products must be fully complete including all original manufacturer boxes with the UPC code
and packing materials, all manuals, blank warranty cards, accessories and any other
documentation included with the original shipment. Products returned in used or altered
condition will not be accepted. After thirty (30) days from initial product ship date, all sales are
final. Customer is responsible for shipping charges to the USIPCOM distribution center for all
products being shipped for return or exchange. Customer is responsible for all risk of loss and
damage to products being shipped for return or exchange. Should Customer desire to return or
exchange purchased CPE, pursuant to the above conditions, then Customer must e-mail
Customer Care at customercare@usipcom.com to request a Return Materials Authorization
(RMA). All returns and exchanges will incur a twenty percent (20%) restocking fee, as
calculated according to the original purchase price. If the RMA is in response to CPE delivered
pg. 3
dead on arrival or damaged, and said CPE is found to be operating within manufacturer
specifications upon return, said CPE shall be subject to the restocking fee outlined above.
6. Applicable Only If Customer Purchases CPE from Provider: CPE purchased by Customer
from Provider may be covered under a limited warranty provided by any applicable
manufacturer or provider, which Provider will extend to Customer without charge to the extent
Provider can do so pursuant to our agreements with any applicable manufacturer or provider;
however, Provider provides no warranty with respect to any such purchased CPE (and/or CPE
provider service). All sales of CPE purchased by Customer from Provider are final; provided,
however, if Customer receives purchased CPE that is damaged or nonfunctional upon arrival, (i)
within ten (10) days of receipt of such damaged or nonfunctional CPE, Customer must notify
Provider via email to Customer Care at customercare@usipcom.com to request an RMA; (ii)
Provider only will accept returns of any such damaged or nonfunctional products within thirty
(30) days of the date of the shipment to Customer by Provider; (iii) any such damaged or
nonfunctional CPE timely returned to Provider by Customer must be fully complete, including
all original manufacturer boxes with the UPC code and packing materials, all manuals, blank
warranty cards, accessories and any other documentation included with the original shipment to
Customer; (iv) Provider will not accept CPE returned in used or altered condition; (v) Customer
is solely responsible for all costs and expenses connected to the shipment to Provider of any such
damaged or nonfunctional products shipped to Provider pursuant to this Section 7; (vi) Customer
is responsible for all risk of loss and damage to products being shipped to Provider pursuant to
this Section 7; and (vii) if Provider determines that the CPE operates within manufacturer
specifications upon return pursuant to any applicable RMA, the affected CPE will be returned to
Customer at Customer’s sole cost and expense, the sale of such CPE will remain final, and
Provider may charge Customer a restocking fee equal to twenty percent (20%) of the original
purchase price of such CPE. Notwithstanding any terms or conditions of any SLA to the
contrary, except as otherwise expressly provided in this Section 7, Provider does not maintain,
support or manage any CPE, which will be the obligation of Customer solely. Customer is solely
responsible for unauthorized access to or use of any Services by any third-party through CPE,
regardless of whether such unauthorized access is unintentional, accidental, intentional or
fraudulent and regardless of whether Customer had knowledge of such unauthorized access.
7. Applicable Only If Customer Obtains Managed Network Services Pursuant to Any
Applicable SOF: “Managed Network Services” are Services that may be specified in writing as
“Managed Network Services” pursuant to any applicable SOF and is a solution in which the
Internet access CPE (whether provided by Customer or Provider) is managed by Provider. If
Customer chooses to provide its own Internet access CPE, Customer hereby assigns full
operational management responsibility, including, but not limited to, full management of the
logical configuration for such CPE, solely to Provider. Except as expressly provided in any
applicable SOF, no Managed Network Services apply.
8.Applicable Only If Customer Obtains Professional Services Pursuant to Any Applicable
SOF: “Professional Services” are any services that may be specified in writing as “Professional
Services” pursuant to any applicable SOF and is a service in which Provider provides certain
pg. 4
professional services to Customer as specified in such SOF. Except as expressly provided in any
applicable SOF, no Professional Services apply. All Professional Services will be provided by
phone, email or other similar means from Provider’s facilities.
9. Charges for Service. The monthly recurring charge(s) (“MRC”) and any non-recurring
charge(s) (“NRC”) for Service are stated in said Service Order Form. Service charges are
exclusive of applicable taxes and surcharges, including the Federal Universal Service Fund
surcharge that USIPCOM passes on to its customers. At its sole discretion, USIPCOM may
require a security deposit to continue provisioning of Service. After the initial term, USIPCOM
may increase pricing upon at least thirty (30) days written notice. At any time, USIPCOM may
pass on to Customer any circuit price increases from underlying carriers with at least thirty (30)
days written notice. All rates and charges are subject to change immediately in the event there
are mandated surcharges or taxes imposed by federal, state or governmental agencies.
Notwithstanding the foregoing, in the event of any Regulatory Activity, or governmental taxation
changes, USIPCOM reserves the right, at any time with as much advance notice as reasonably
possible and without liability, to: (i) pass through to Customer all, or a portion of, any changes or
surcharges directly or indirectly related to such governmental or Regulatory Activity; (ii) modify
the Service, rates (including any rate guarantees), promotions, terms and/or conditions of this
Agreement in order to conform to such action; or (iii) if such Regulatory Activity materially and
adversely impairs the provision of Service under the Agreement, as reasonably determined by
USIPCOM, terminate the Agreement.
10. Billing and Payment. USIPCOM shall bill Customer for Service rendered at the rates stated
in said Service Order Form. Invoices shall include all applicable federal, state, and local taxes.
all such taxes, and all use, sales, commercial, gross receipts, privilege, surcharges, or other
similar taxes, license fees, miscellaneous fees, and surcharges, whether charged to or against
USIPCOM, Inc., which shall be payable by the Customer. However, if Customer provides proof
of its specific tax-exempt status, Provider shall not charge applicable taxes due to such
exemption. Customer shall supply Provider a valid and properly executed tax exemption
certificate(s). In such cases the Customer remains responsible for, and agrees to pay, any and all
remaining non-exempt charges; tax exemption status validation is solely the responsibility of the
Customer and Provider will not be obligated to consider any retroactive tax exemption.
USIPCOM shall commence billing for the monthly recurring charges and usage (the Service) on
the Service Commencement Date. First and second month charges for the recurring Service(s)
are billed upon Service Commencement. Where applicable, service charges for the first partial
month of service will be pro-rated and billed. Call usage charges are billed after the actual calls
and usage has occurred. Payments are due within fifteen (15) days of the invoice date. After
fifteen (15) days of non-payment, all fees will accrue interest at a rate of one and one-half
percent (1.5%) per month or any part thereof, or the highest rate allowed by applicable law, and
customer shall pay all collection costs incurred by USIPCOM (including, without limitation,
reasonable attorney’s fees). Some Customers installed prior to two-thousand-and-eight (2008)
may be subject to payment terms whereby payments are due within thirty (30) days from the
invoice date; USIPCOM reserves the right to amend said Customers to a fifteen (15) day
payment term should they fail to make satisfactory payments pursuant to their current account
pg. 5
payment term. At any point beyond provided invoice due date, where Customer has failed to
make satisfactory payment as so judged by USIPCOM, then USIPCOM may give Customer
written notification, by email, that Customer has committed a material breach of the Agreement
due to non-payment. Said notification will be provided five (5) business days prior to Service
suspension or termination. Customer must pay all outstanding charges, within said notice period,
to avoid suspension or termination of Service. If Service is terminated due to non-payment, then
the Termination fees described in the Material Breach Section shall apply. In its sole discretion,
USIPCOM may: (i) require a security deposit to continue the provisioning of Service(s) if
Customer’s approved level of credit is deemed insufficient; (ii) change payment terms, billing
cycle, and/or Due Date; (iii) demand immediate payment by wire or other means and discontinue
Service(s) without notice should Provider determine Customer’s usage exceeds their approved
level of credit; (iv) immediately block Customer’s Service(s) if a Customer’s pre-paid balance is
depleted or is at a level that cannot cover Customer’s estimated traffic during the time required
for the Customer to replenish their prepaid balance, or if Customer refuses to make any requested
payments. USIPCOM retains the right to bill, including any amended or corrected billing, for the
Service(s) for a period of up to twelve (12) months, commencing from the date the billed
Service(s) were provided to Customer. USIPCOM shall retain such billing rights for this twelve
(12) month period notwithstanding any prior billing to Customer for the same period(s) and
regardless of any otherwise conflicting billing conditions in this Agreement. Customer agrees
that for the duration of this twelve (12) month period, USIPCOM shall not be deemed to have
waived any rights with regard to billing for the provided Service(s) that are subject to this period,
nor shall any legal or equitable doctrines apply, including estoppel or laches.
11. Billing Disputes. In the event Customer disputes any invoiced charges, Customer shall pay
in full all charges invoiced by the Due Date and submit written notification in the form of an
email sent to customercare@usipcom.com, with “Notice of Billing Dispute” in the subject line of
the email. Such email notification must include the Customer’s contact information, the specific
dollar amount in dispute, detailed supporting reasons for the dispute, and any supporting
documentation if available. USIPCOM shall respond to Customer, in writing, within thirty (30)
calendar days of receiving a dispute notification from Customer. Any dispute resolved in favor
of Customer shall be credited as appropriate on the next available invoice. In the event that any
disputed amounts are deemed to be correct as billed and in compliance with this Agreement,
Customer shall be notified in writing that the charges have been deemed valid and legitimate,
and the dispute will be considered resolved by both parties; in such cases, if there should be any
amount due from Customer related to the dispute, then all such amounts shall be due and payable
immediately. Provider reserves the right to deny or delay any and all billing disputes and/or
credits if the Customer’s account is in arrears or otherwise not in good standing.
12. Resumption of Service. If Customer requests that Service be restored after a suspension or
termination, USIPCOM has the sole and absolute discretion to restore such Service and may
condition restoration upon satisfaction of such conditions as USIPCOM determines necessary for
its protection, including requiring Customer to execute a new agreement, pay all past due
invoices in full, pass USIPCOM’s credit approval, and/or make advance payments. New
nonrecurring charges also may apply to restore Service.
pg. 6
13. Additional NRC (if applicable). In addition to the standard NRC listed above, the following
NRC, if applicable, will apply
(i) Changes of IP Addresses: $100.00;
(ii) Service Reinstatement /Resumption Fee: $200.00 (plus any charges imposed by underlying
carrier(s) and/or pursuant to Section 12 above);
(iii) Missed Appointment Fee: $200.00;
(iv) Rejected Credit Card/Unpaid Check: $40.00 (or legal limit, if lower);
(v) Relocation Fee: varies upon address;
(vi) Upgrade Charge: varies upon specific upgrade requested;
(vii) Downgrade Charge: varies upon specific downgrade requested.
Inside Wiring.
The availability of inside wiring installation is dependent upon a number of factors, including,
without limitation, any applicable service address and/or LEC availability. Any inside wiring
provided by Provider’s underlying carrier(s) may incur additional fees to the charges listed in the
SOF. Any request for inside wiring or wiring extension for any applicable Services will be
provided on a best-effort basis only. In many cases, Customer's LEC will not extend wiring
beyond the Minimum Point of Entry (“MPOE”) as determined by the LEC. In all such cases,
Customer will provide any needed internal wiring or extensions (and required conduit, facilities,
power, etc.) to the circuit required to provision service unless Provider has agreed in writing to
provide this service to Customer.
Special Construction Charge.
When a Customer’s location has insufficient facilities needed to support any applicable Service,
the underlying carrier(s) may add facilities that may impose an additional “special construction
charge" or other similar charge. If this occurs, Provider will notify Customer (via phone, email or
other means) of the cost of these additional special construction charges, if available and if any,
as well as the estimated time to complete the construction. Customer must agree in writing to pay
these additional special construction costs within three (3) business days. If Customer fails to do
so, Provider will cancel the SOF for lack of facilities and the SOF will terminate without liability
to either Customer or Provider. Miscellaneous Charges. Miscellaneous charges and/or fees
imposed by any third party carrier or any underlying provider from time to time, whether
charged to or against Provider, will be payable by Customer, including, without limitation, any
cost recovery fee which shall represent an accurate and non-inflated recovery of the
miscellaneous charges and/or fees to or against Provider associated with the provision of
Service(s) by Provider to Customer. Usage charges (Applicable to burstable dedicated Internet
Access Service Only): Additional usage charges stated in any applicable SOF will be calculated
based on Customer’s monthly usage, which Provider will calculate as follows: Provider will take
usage samples approximately every five (5) minutes throughout the applicable month and will
retain the higher of two (2) samples taken during each five (5) minute period– one (1) sample
that will reflect inbound usage/utilization and one (1) sample that will reflect outbound usage/
utilization. At the end of the applicable billing period, the samples will be arranged from highest
to lowest. Provider will discard the top five percent (5%) of the samples for the purposes of
pg. 7
calculating Customer’s monthly usage. Provider will utilize the highest remaining sample (i.e.,
the ninety‐fifth percentile (95%) peak Mbps port utilization) (the “Mbps Port Utilization”) to
calculate Customer’s monthly usage. Provider will measure the Mbps Port Utilization to the
100th decimal place, but the invoice will reflect the Mbps Port Utilization only to the 10th
decimal place. Provider will multiply the Mbps Port Utilization by the per-‐Meg rate listed on
any applicable SOF to calculate any applicable additional usage charges. Provider will charge
Customer such additional usage charges as well as any applicable base rate provided in any
applicable SOF.
14.IP Addresses. USIPCOM assigns IP addresses to its customers for use with certain IP/data-
based Service. USIPCOM shall retain any assigned public IP addresses when a customer’s
service is terminated. USIPCOM and Customer agree that assigned addresses are “non-portable”
and other providers are not allowed to route these addresses. Customer, who has its own IP
addresses, which are allocated directly from American Registry for Internet Numbers (ARIN),
will be ported/routed by USIPCOM where reasonably possible. USIPCOM cannot guarantee the
portability/routability of these addresses beyond its own backbone and to the Internet in general.
USIPCOM reserves the right to modify its IP Address Allocation Policy without notice.
15. Material Breach. USIPCOM or Customer may terminate this Agreement and the Service(s)
provided hereunder in the event of a material breach that is not cured within thirty (30) days
following the delivery of written notice specifying said breach, except in the case of serious
material breaches, so judged by USIPCOM. Such notice from Customer must be in the form of
an email sent to customercare@usipcom.com with “Notice of Material Breach” in the subject
line of the email and Customer’s contact information and detailed explanation, including
supporting documentation if available, in the body of the email. Such notice from USIPCOM
shall be in the form of an email to the Customer. In the event of an uncured material breach by
USIPCOM, the Agreement and Service(s) shall be terminated without further liability to the
Customer, however, in such cases Customer shall remain responsible for: (a) charges for
Service(s) actually and properly received prior to the date of Breach notification, (b) one hundred
percent (100%) of the past due balance at the time of termination, and (c) any non-recurring
charges originally waived by USIPCOM. In the event of an uncured material breach by
Customer, such as early termination of this Agreement, the following termination fees shall
apply: (a) charges for Service(s) actually and properly received prior to the date of Breach
notification, (b) the total of monthly minimum commitments for all components of the Service(s)
for the remainder of the Service Order Term(s) and any additional early Termination fees
included in any and all relevant Service Order Form(s), (c) one hundred percent (100%) of the
past due balance at the time of termination, and (d) any nonrecurring charges originally waived
by USIPCOM.
16. Termination. Upon termination of the Service Agreement and/or the Service(s) not due to a
material breach, USIPCOM will disconnect, or will cause to be disconnected, the Service(s) if
notified by the Customer in writing via email to customercare@usipcom.com with no less than
forty calendar (40) days notice prior to termination of the Agreement and/or Service(s). In all
such cases, Customer retains the sole responsibility for notifying USIPCOM of any and all
requests for termination or disconnection of Service(s), including but not limited to the porting
pg. 8
out of billable telephone numbers (also referred to as “DIDs”), whether port outs are known or
unknown by Customer; and, Customer remains responsible for all billable charges related to
terminated Service(s) until USIPCOM is notified in writing as specified. Any request by
Customer for cancellation or termination at any time within the Service Agreement Term and/or
Service Term set forth in this Agreement, including: prior to installation, or at any time prior to
the Service Commencement or Activation Date, or in the case of early termination by Customer,
will be considered a Material Breach by the Customer and shall be subject to the applicable
Material Breach provisions as outlined in the Material Breach section of this agreement.
17. Termination by Provider. In addition to any other right that Provider may have to terminate
or suspend these Terms and Conditions and/or any applicable SOF, if Provider determines, in its
sole discretion, that Customer’s ongoing use of any or all Services, and/or the specific method or
technology utilized by Customer places the network operated by Provider, other customers,
partners or the overall business(es) of each in jeopardy, Provider reserves the right to terminate
these Terms and Conditions and/or any applicable SOF and Customer’s access to any or all
applicable Services immediately and without notification.
18. Cooperation with Investigations. USIPCOM will cooperate with appropriate law
enforcement agencies and other parties involved in investigating claims of illegal or
inappropriate activity on the USIPCOM Network. USIPCOM reserves the right to disclose
customer information to the extent authorized or required by federal or state law. In those
instances, involving child pornography, USIPCOM complies with all applicable federal and state
laws including providing notice to the National Center for the Missing and Exploited Children or
other designated agencies.
19. Acceptable Use Policy. All use of Service must comply with USIPCOM’s Acceptable Use
Policy (“AUP”), which is posted at www.usipcom.com and is incorporated herein by reference.
By accepting USIPCOM Service, Customer agrees to comply with this AUP and any subsequent
modifications thereto. USIPCOM reserves the right to modify this AUP from time to time,
effective upon posting the AUP as modified at the URL shown above. Violation of the AUP
shall be considered a material breach of this Agreement pursuant to Section 14.
20. Dispute Resolution Process and Applicable Law.
(a) It is the mutual desire of the parties to promptly and fully resolve any dispute arising in
connection with these Terms and Conditions and/or any applicable SOF in good faith,
confidentially, and informally with minimal transaction costs; no public statement may be made
by any party regarding any such dispute. If either party determines that the dispute cannot be
resolved informally, then such party will initiate an escalation process by giving written
notice (“Escalation Notice”) to the other party. Each party will name one executive as its
representative, to be a person knowledgeable of the subject matter in dispute and someone with
authority to discuss the dispute (“Officers”). The Officers will meet in person or by conference
call, together with any persons assisting them, within fifteen (15) days after delivery of the
Escalation Notice. All negotiations conducted by the Officers are confidential and will be treated
as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and
any state rules of evidence. The Officers will conduct such additional meetings as they deem
pg. 9
necessary to exchange relevant information, will appoint staff to engage in resolution of any
disputed facts, and will attempt to resolve the dispute. Should the Officers be unable to resolve
the dispute within such fifteen (15) days, or within such additional time as the parties may
otherwise agree to in writing, either party may demand mediation, whereupon the parties will, in
good faith, mediate the dispute no later than thirty (30) days after such demand through the
services of a mutually selected mediator, the cost of whom will be borne equally by the parties,
at a date and location selected by the mediator after consultation with the parties. IF THE
DISPUTE IS NOT RESOLVED AFTER APPLYING THE ESCALATION PROCEDURES
SET FORTH ABOVE, THE PARTIES AGREE TO WAIVE ANY RIGHT TO TRIAL BY
JURY IN ANY JUDICIAL PROCEEDING ARISING UNDER OR RELATED TO THE
SUBJECT MATTER OF THIS AGREEMENT, AND AGREE TO SUBMIT ALL
CONTROVERSIES, CLAIMS AND MATTERS OF DIFFERENCE TO ARBITRATION
ACCORDING TO THE COMMERCIAL RULES AND PRACTICES OF THE AMERICAN
ARBITRATION ASSOCIATION (“AAA”). Arbitration here under will occur within sixty (60)
days of the date of submission before a single neutral arbitrator having significant experience in
the subject matter of this Agreement and who will selected in accordance with AAA rules.
Arbitration proceedings will take place in Wake County, North Carolina. Discovery will be
permitted, including the use of interrogatories, requests for admission and production of
documents and depositions. If the amount claimed to be in dispute is less than $500,000, all
applicable expedited procedures of the AAA will apply. The arbitrator’s fees and costs of the
arbitration will be borne by the party against whom the award is rendered, except that if the
arbitrator issues a split decision, granting partial relief to both parties, the arbitrator will
equitably allocate the arbitrator’s fees and other costs. Each party will pay its attorney’s fees
related to any dispute related to this Agreement. The arbitration award will be final and binding
on both parties of this Agreement, will not be subject to any appeal and will be enforceable in
any court of competent jurisdiction. (b) ANY DISPUTE RESOLUTION PROCEEDINGS,
WHETHER IN ARBITRATION OR IN COURT, WILL BE CONDUCTED ONLY ON
AN INDIVIDUAL BASIS AND NOT IN A CLASS ACTION OR REPRESENTATIVE
ACTION OR AS A MEMBER IN A CLASS, CONSOLIDATED OR REPRESENTATIVE
ACTION. CUSTOMER WILL NOT BE A CLASS REPRESENTATIVE, CLASS
MEMBER OR OTHERWISE PARTICIPATE IN A CLASS, CONSOLIDATED OR
REPRESENTATIVE PROCEEDING. (c) This Agreement will be governed by, construed
under and enforced in accordance with the laws of the State of North Carolina without
reference to its choice of law principles or the United Nations Convention on the
International Sale of Goods. In the event any party brings a civil action or initiates judicial
proceedings of any kind related to this Agreement (except for actions to enter or collect on
judgments), the parties consent to the exclusive personal jurisdiction and venue of the
federal and state courts located in Wake County, North Carolina and the prevailing party
will be entitled to recover its costs, including reasonable attorney’s fees.
21. Limitation of Liability. EXCEPT AS PROVIDED IN SECTION 19, IN NO EVENT WILL
USIPCOM OR CUSTOMER BE LIABLE FOR ANY INDIRECT, INCIDENTAL, PUNITIVE
OR CONSEQUENTIAL DAMAGES (INCLUDING, WITHOUT LIMITATION, LOST
pg. 10
PROFITS) ARISING OUT OF OR IN RELATION TO THE SERVICE(S), CPE, AND/OR
ANY PRODUCTS OR SERVICE PROVIDED BY THIRD PARTIES UNDER THIS
AGREEMENT. USIPCOM’S MAXIMUM LIABILITY UNDER THIS AGREEMENT IS
LIMITED TO SERVICE CREDITS NOT TO EXCEED THE FEES PAID TO USIPCOM BY
CUSTOMER FOR THE SERVICE PROVIDED.
22. Indemnity. Customer shall indemnify and hold harmless USIPCOM, its Officers,
Employees, Agents, and Affiliates from and against any and all alleged or actual losses, costs,
claims, liability of any kind, damages (including to any tangible property or bodily injury to or
death of any person), or expense of whatever nature, (including reasonable attorneys' fees) to or
by any third party, relating to or arising from (a) the use of the Service provided to Customer,
whether or not Customer has knowledge of or has authorized access for such use, (b) any
damage to or destruction of CPE not caused by USIPCOM or its agents, and (c) any material
breach of this Agreement by Customer. Customer has the sole and exclusive responsibility for
the installation, configuration, security, and integrity of all Customer systems, equipment,
software, and networks (the “Customer Equipment”) used in conjunction with or related to the
Service(s) provided by USIPCOM. Customer therefore shall indemnify and hold harmless
USIPCOM from and against any actual or alleged losses, costs, claims, liability of any kind,
damages, or expenses or fees (including reasonable attorneys' fees) on the part of or which may
be incurred by Customer or a third-party relating to or arising from the use or operation of the
Customer Equipment. Customer’s indemnification in this subsection includes any alleged or
actual losses or claims in connection with unauthorized access to or use of the Service(s) by any
third-party through Customer Equipment, regardless of whether such unauthorized access is
unintentional, accidental, intentional or by fraud and regardless of whether Customer had
knowledge of such unauthorized access. In all such cases of unauthorized access Customer
agrees that it retain full and sole responsibility for any and all charges for the Service(s) provided
by USIPCOM. In the event USIPCOM grants Customer access, either by online access, by
application programming interface (API), or access by any other means, to a service
ordering/management system and other related electronic tools (collectively, the “Electronic
Tools”), Customer agrees that it is fully and exclusively responsible for all information accuracy,
charges, costs, transactions, and activities conducted through such Electronic Tools. Customer
agrees that it is fully and exclusively responsible to safeguard, monitor, manage, and maintain
access to the Electronic Tools, and to only allow authorized use of the Electronic Tools to
persons that Customer designates. Customer therefore agrees that it shall indemnify and hold
harmless USIPCOM from and against any actual or alleged losses, costs, claims, liability of any
kind, damages, or expenses or fees (including reasonable attorneys' fees) on the part of or
which may be incurred by Customer, or a third-party, relating to or arising from the use or
operation of the Electronic Tools. Customer’s indemnification in this subsection includes any
alleged or actual losses or claims in connection with unauthorized access to, use, transactions, or
activity conducted through the Electronic Tools, regardless of whether such unauthorized access
is unintentional, accidental, intentional, or by fraud, and regardless of whether Customer had
knowledge of such unauthorized access. In all such cases of unauthorized access Customer
pg. 11
agrees that it retains full and sole responsibility for any and all charges for the Service(s)
provided by USIPCOM.
23. No Warranties and Customer Assumption of Risk. EXCEPT AS OTHERWISE
EXPRESSLY PROVIDED IN AN APPLICABLE SLA, ANY APPLICABLE SERVICE AND
ANY CPE, EQUIPMENT, AND/OR RELATED SERVICES EACH IS PROVIDED “AS IS”
AND “AS AVAILABLE” AND WITHOUT WARRANTIES OF ANY KIND EITHER
EXPRESS OR IMPLIED. TO THE FULLEST EXTENT PERMISSIBLE PURSUANT TO
APPLICABLE LAW, EACH OF PROVIDER, ITS AFFILIATES, SUPPLIERS AND, IF
APPLICABLE, RESELLERS DISCLAIMS ALL WARRANTIES, EXPRESS OR IMPLIED,
INCLUDING, WITHOUT LIMITATION, IMPLIED WARRANTIES OF
MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, OR ANY
WARRANTY OF NONINFRINGEMENT. WITHOUT LIMITING THE FOREGOING,
PROVIDER, ITS AFFILIATES, SUPPLIERS AND, IF APPLICABLE, RESELLERS DO
NOT WARRANT THAT ANY FUNCTIONS OF ANY SERVICES, ANY CPE,
EQUIPMENT, AND/OR RELATED SERVICES WILL BE UNINTERRUPTED OR
ERROR-FREE, THAT DEFECTS WILL BE CORRECTED, OR THAT ANY SERVICES
(OR ANY SERVER THAT MAKES ANY SERVICES AVAILABLE) WILL BE FREE OF
VIRUSES OR OTHER HARMFUL COMPONENTS. PROVIDER DOES NOT
WARRANT OR MAKE ANY REPRESENTATIONS REGARDING THE USE OR
RESULTS OF ANY SERVICES OR ANY ELECTRONIC TOOL IN TERMS OF ITS
CORRECTNESS, ACCURACY, RELIABILITY, UNAUTHORIZED ACCESS BY
THIRD PARTIES OR OTHERWISE. CUSTOMER (AND NOT PROVIDER) ASSUMES
THE ENTIRE COST OF ALL NECESSARY SERVICING, REPAIR OR CORRECTION.
CUSTOMER ACKNOWLEDGES THAT ANY DATA OR INFORMATION
DOWNLOADED OR OTHERWISE OBTAINED OR ACQUIRED THROUGH THE USE
OF ANY SERVICES AND/OR ELECTRONIC TOOL IS AT CUSTOMER’S SOLE RISK
AND DISCRETION AND PROVIDER WILL NOT BE LIABLE OR RESPONSIBLE
FOR ANY DAMAGE TO CUSTOMER OR CUSTOMER’S PROPERTY. CUSTOMER
HEREBY EXPRESSLY ASSUMES THE RISK OF ITS USE OF ANY INFORMATION
TRANSMITTED VIA ANY SERVICES AND/OR ANY ELECTRONIC TOOL. NO
ADVICE OR INFORMATION, WHETHER ORAL OR WRITTEN, OBTAINED BY
CUSTOMER FROM PROVIDER, ITS EMPLOYEES OR THROUGH OR FROM ANY
SERVICE AND/OR ELECTRONIC TOOL WILL CREATE ANY WARRANTY NOT
EXPRESSLY STATED IN THIS AGREEMENT. APPLICABLE LAW MAY NOT
ALLOW THE EXCLUSION OF IMPLIED WARRANTIES, SO THE FOREGOING
EXCLUSION MAY NOT APPLY. PROVIDER WILL HAVE NO OBLIGATION TO
DEFEND OR INDEMNIFY CUSTOMER FROM OR AGAINST ANY THIRD PARTY
CLAIMS ALLEGING THAT CUSTOMER’S USE OF ANY SERVICES OR ANY
ELECTRONIC TOOL OR THE EXERCISE OF ANY RIGHTS GRANTED HEREIN
INFRINGES ON ANY INTELLECTUAL PROPERTY OF ANY THIRD PARTY. IF A
CLAIM IS MADE, OR IN PROVIDER’S REASONABLE OPINION IS LIKELY TO BE
MADE, AGAINST PROVIDER, CUSTOMER OR ANY THIRD PARTY ALLEGING
pg. 12
THAT ANY APPLICABLE SERVICES OR ELECTRONIC TOOL OR ANY USE
THEREOF INFRINGES ANY INTELLECTUAL PROPERTY OF ANY THIRD PARTY,
PROVIDER MAY, IN PROVIDER’S SOLE DISCRETION, TERMINATE THESE
TERMS AND CONDITIONS AND/OR ANY APPLICABLE SOF AND ALL RIGHTS
AND OBLIGATIONS PURSUANT TO THESE TERMS AND CONDITIONS AND/OR
ANY APPLICABLE SOF.
24. Third Party Beneficiaries. The Parties do not intend by the execution, delivery, or
performance of this Agreement to confer any benefit, direct or incidental, upon any person or
entity not a party to this Agreement.
25. Miscellaneous. Customer acknowledges and understands that Customer is to receive the
Service detailed in this Agreement and the Customer is not relying on any affirmation of fact,
promise or description from any person or entity, nor any other oral or written representation
other than what is contained in this Agreement. Handwritten alterations or additions to this
agreement made by Customer will not be considered part of this Agreement. This Agreement
may only be modified, or any rights under it waived, by a separate written document executed by
both parties. This Agreement shall be governed by, construed under, and enforced in accordance
with, the laws of the State of North Carolina without reference to its choice of law principles. For
any action or suit to enforce any right or remedy of this Agreement, (except for actions to enter
or collect on judgments) the parties’ consent to exclusive jurisdiction and venue in the courts for
Wake County, North Carolina and the prevailing party shall be entitled to recover its costs,
including reasonable attorney’s fees. In the event of a conflict between this Agreement and any
applicable tariff, the tariff shall prevail. Customer may not assign this Agreement without
USIPCOM’s prior written consent. This Agreement shall be binding on the parties hereto and
their respective personal and legal representatives, successors, and permitted assigns. If any
provision of this Agreement is held to be invalid or unenforceable, the validity and enforceability
of the remaining provisions of this Agreement shall not be affected thereby. By signing the
unique, or any, Service Order Form, or any Attachments, Addendums, or any other documents
incorporated herein by reference. Customer signatory certifies that (s)he is an officer or certified
representative of the Customer, and as such is authorized to enter into this binding Agreement. In
the event any specified time frame or deadline denotes calendar days, it is agreed that when the
last date of required action or response falls on a weekend or holiday, the action and/or deadline
shall automatically extend to the next business day. Agreement headings are provided for
reference purposes only.
THIS AGREEMENT, TOGETHER WITH ANY ATTACHMENTS, INCLUDING ANY
SCHEDULES, ADDENDUMS, PRICE LISTS, SERVICE ORDERS, TERMS AND
CONDITIONS, SERVICE LEVEL AGREEMENTS, AND ACCEPTABLE USE
POLICIES, WHICH MAY BE POSTED AT:
WWW.USIPCOM.COM/CONTENT/LEGAL, AND WHICH ARE INCORPORATED
HEREIN BY REFERENCE, CONSTITUTE THE ENTIRE UNDERSTANDING
BETWEEN THE CUSTOMER AND USIPCOM, INC, WITH RESPECT TO THE
SERVICE(S) PROVIDED HEREIN. CUSTOMER ACKNOWLEDGES AND
UNDERSTANDS THAT CUSTOMER IS NOT RELYING ON ANY AFFIRMATION OF
pg. 13
FACT, PROMISE OR DESCRIPTION FROM ANY PERSON OR ENTITY, NOR ANY
OTHER ORAL OR WRITTEN REPRESENTATION OTHER THAN WHAT IS
CONTAINED IN THIS AGREEMENT AND ANY INCORPORATED DOCUMENTS.
26. Definitions. For the purposes of these Terms and Conditions and/or any applicable SOF, the
following terms will have the following meanings: “Default” occurs: (i) if Customer fails to
make any payment for Services more than two (2) business days immediately after the applicable
Due Date, or any other payment contemplated by these Terms and Conditions and/or any
applicable SOF on or before the date two (2) business days immediately after any applicable
required date; (ii) if Customer violates the AUP; (iii) if Customer fails to perform or observe any
term or obligation of these Terms and Conditions and/or any applicable SOF, including, without
limitation, any document incorporated by reference into these Terms and Conditions, not
otherwise specified in clauses (i) or (ii) above and applicable to the Services, which failure
remains uncured thirty (30) calendar days after Customer’s receipt of written notification from
Provider informing Customer of such failure; (iv) upon the institution of bankruptcy,
receivership, insolvency, reorganization or other similar proceedings, by or against Customer,
unless such proceedings have been dismissed or discharged not later than the date thirty (30)
calendar days immediately after the commencement of such proceeding; (v) upon the making of
an assignment for the benefit of creditors, adjudication of insolvency, or institution of any
reorganization arrangement or other readjustment of debt plan, of or by Customer;
and/or (vi) upon the appointment of a receiver for all or substantially all of Customer’s
assets. “LEC” means local exchange carrier. “MPLS Services” means those multiprotocol layer
switching services described in the SOF by and between Provider and Customer. “MRC” means
monthly recurring charge. “NRC” means non-recurring charge. “Regulatory Activity” means
any laws, regulations or other similar mandates (including, without limitation, any fees,
surcharges or other like charges imposed or mandated) by any federal, state or other
governmental agency at any time. “RMA” means a Return Materials Authorization. “Service
Term” will mean the period commencing on the Service Activation Date during which any
applicable SOF remains in effect with respect to any Services. For clarity, the “Service Term”
will expire and/or terminate immediately upon the date when all SOFs entered into with respect
to any Services from time to time will have expired and/or terminated by their terms. “Services”
means those services described in the SOF by and between Provider and Customer, which
services may include Burstable Dedicated Internet Access Services, dedicated Internet access
services, Managed Network Services, MPLS Services, Professional Services, and/or private line
services.
Customer Name
City of Vernon
Sales Order: SO5691
Issued Date: 07-27-2023
03:46 PM
Due Date : 10-31-2023
USIPCommunications
3201 Northside Dr STE 109
RALEIGH, North Carolina 27615
Phone 800-972-5004
Contact
Tim Bass
Billing Address Shipping Address
4305 santa fe Avenue
Vernon, CA 90058
4305 santa fe Avenue
Vernon, CA 90058
Item Code Item Name Quantity List Price Item Total Discount Total After
Discount Total
PRO114 GigE
Dedicated Symmetrical 100G Fiber service
with SLAs. BGP routing will be supported
1 $8,039 $8,039 0 (0 %)$8,039 $8,039
PRO24 Installation 1 $300 $300 0 (0 %)$300 $300
Items Total $8,339
Discount(0%)0
GRAND TOTAL($)$8,339
Contract Term Monthly Charge One-Time Charge
36 $8,039 $300
Customer Acceptance USIPCOM Acceptance
Print Name:Print Name:
Signature:Signature:
Title:Title:
Date:Date:
Terms and Conditions can be found at www.usipcom.com/legal
Important Information
Billing
Billing for Service will begin no later than two days after service is deemed ready for Billing and Invoicing by USIPCOM. Customer’s failure to
promptly schedule and activate the service will result in billing beginning before service can be utilized by the Customer. In addition, the
Customer is solely responsible for canceling any service with previous Provider.
Termination
Upon termination of the Service Agreement and/or the Service(s) not due to default, USIPCOM will disconnect, or will cause to be
disconnected, the Service(s) if notified by the Customer in writing via E-mail to support@usipcom.com with no less that forty calendar (40)
days’ notice prior to termination of the Agreement and/or Service(s). Please review Terms & Conditions and Legal Documents @
http://www.usipcom.com/legal
Customer Care & Support Contact Information
• Phone: 800-972-5004
• E-mail: support@usipcom.com
Sales Contact
• Name: Joe Willett
• E-mail: jwillett@usipcom.com
• Direct Phone: 919-439-3563
• Main Phone: 800-972-5004
Terms & Conditions
Terms & Conditions along with other important documents can be found at http://www.usipcom.com/legal/. Please review the Terms &
Conditions along with the Acceptable Use Policy, Service Level Agreement before signing for service. It is solely the customer's responsibility
to review the Terms & Conditions, Acceptable Use Policy, and Service Level Agreement located @ http://www.usipcom.com/legal
Customer Acceptance USIPCOM Acceptance
Print Name:Print Name:
Signature:Signature:
Title:Title:
Date:Date:
Payment Form
Please choose the desired payment method:
Direct Deposit/ACH Credit Card Paper Check
One-Time Charge Monthly Reoccurring Charge
Credit Card Authorization
Card Type: Card Number:
CVC (3 or 4 digit security code on back or front of credit card)
Expiration Date: Name on Card:
Billing Address:
City: State: ZIP: Country:
Customer Acceptance USIPCOM Acceptance
Print Name:Print Name:
Signature:Signature:
Title:Title:
Date:Date:
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Data Installation Guide
Product Installation Overview
Customers ordering a T1, NxT1, EOC, or Cable should expect installation to occur within an average 30-45 business days from the date of
order submission by USIPCOM to the underlying Carrier.
Customers ordering MPLS, DS3, OCx and Fiber Buildout should expect installation to occur within an average of 60-90
business days from the date of order submission by USIPCOM to the underlying Carrier(s).
All order submission will occur only after a completed contract has been presented and received by USIPCOM and the
Customer has been approved for any/all applicable credit.
It is important to understand that the average times to installation presented above are based on industry standards and
USIPCOM experience. Individual circumstances may dictate that these installation timeframes could be shorter or longer
than the aforementioned averages.
Orders may be expedited and are contingent upon Carrier capability and acceptance. A one-time non-recurring expedite
fee will be assessed on a Customer’s invoice. However, payment of this fee by the Customer does not guarantee a
specific timeframe or completion date.
Throughout the installation process a Customer will work with USIPCOM Installation Specialists and Activation Engineers.
The Installation Specialist will manage the installation process up to Service Activation and is responsible for interacting
with the Carrier to ensure all milestones are met, escalations and confirming with the Carrier and Customer that
contracted service is provisioned correctly. The Activation Engineer is responsible for activating and verifying service.
Installation Timeline
Day 1-3: Order is placed with the Carrier
USIPCOM will place the order with the underlying Carrier for Data service. The following requirements must be met by the
Customer prior to order placement:
Basic Requirements:
• Accurate address including suite number and onsite phone number
• Valid onsite contact with appropriate phone number
• Main point of entry (MPOE) location where the Local Exchange Carrier (LEC) will deliver service the building (i.e.
basement on first floor)
• DMARC location, the actual location within the building where the service is to be delivered (i.e. suite 100)
• Number of IPs desired and completed IP justification form if required by the Carrier
Important Note:
USIPCOM is not responsible for extending the circuit to the DMARC location unless the extension has been explicitly ordered and is listed as a
line item on the USIPCOM Service Order Form (SOF). Unless the DMARC extension is listed on the SOF the circuit will only be delivered to the
MPOE (as determined by the LEC) and any extension is the sole responsibility of the Customer. In general, any changes to the above
information or to the service order during the installation process could result in delays and additional fees.
After the order is placed with the Carrier a USIPCOM Installation Specialist will contact the Customer point of contact on record and complete
an introduction call to review the ordered service solution, address, contact information, and will confirm the Customer has access to the
customer portal.
Day 4-9: Carrier places order with Local Exchange Carrier (LEC)
The Installation Specialist will ensure the Carrier has initiated the design and engineering of the circuit so the order can be passed to the LEC.
The LEC will then begin the design and engineering of the local loop.
Day 10-20: Installation Date (Firm Order Commitment Date) Established
The LEC will provide a Firm Order Commitment (FOC) date for installation of the local loop. At this time, if a FOC date has not been
established the reason for delay will be relayed to the Customer.
Day 21-30: Local Loop is installed (Firm Order Commitment Date)
A technician from the LEC will install the local loop to the service location.The following requirements must be met in order for the technician to
complete installation:
Requirements:
• A customer contact must be onsite to allow the LEC technician access to the location and telco closet as applicable for an entire business
day.
Day 31-45: Service Activation
After the local loop has been installed and the LEC has tested and accepted with the Carrier, the Installation Specialist will schedule
an activation appointment with the Customer. The following requirements must be fulfilled prior to the activation appointment:
Requirements:
• Space and power must be allocated for all equipment components applicable to Data service and any necessary mounting boards or racks
shall be provided by the Customer
• Sufficient power outlets must be available for the power unit which requires a standard 120V AC plug. The power outlet must not be
overloaded and must be within 6’ of the Data Router
• Any DMARC extensions not ordered through USIPCOM must be complete
• All LAN devices and the Data Router must be wired/connected – USIPCOM does not provide patch cables or dispatch technicians to connect
any equipment to the circuit.
• The Data Router requires an operating environment with temperature ranges between 35-85° F and humidity of less than 90%,
noncondensing
• The environment must be free of excessive dust
• Customer must call in to USIPCOM at the scheduled time of the activation appointment
The USIPCOM Activation Engineer will bridge the Carrier on the phone with the Customer and conduct testing to ensure Data service is
working properly.
Day 60: Service Activation - DS3’s/OCX’s/Ethernet/Colocation/MPLS
DS3 and OCX Solutions have an installation interval of 60-90 business days. Actual installation timeline will vary as these
solutions may require build outs, special equipment, or other special requirements from the Carrier, LEC, and the
Customer.
The following Data Solutions may have additional requirements and specifications:
CO-LOCATION
In order to avoid any delays, it is the Customer’s responsibility to inform USIPCOM prior to order placement on what floor
their equipment is located. Customers needs to work with their existing vendors (hosting company / cross connect
provider) to determine where the circuit should be terminated and how the circuit shall be provided (i.e. open port on
MPOE, open port on Carrier POP, channel on existing facility). In some cases, a CFA/LOA will need to be provided by the
Customer. In addition, the Customer is also responsible for ordering the appropriate cross-connect from the MPOE to their
equipment.
ETHERNET
When purchasing an Ethernet solution from a Carrier, it is the Customer’s responsibility to ensure that the Carrier has
facilities going to the Customer’s floor. The Customer is responsible for extending this service either from the MPOE or
the Telco closet on their floor to their suite if desired.
MPLS
The Customer must work with USIPCOM on an implementation plan to ensure the appropriate sites are installed in the
order of importance. Customer must also provide their private IP addressing scheme and routing requirements. If the
Customer is getting voice, their bandwidth requirements for voice across this network must be understood and provided
to USIPCOM along with QOS requirements so the appropriate settings are implemented on the Carrier’s network.
Billing
Billing for Data Services will begin no later than two (2) business days after service is deemed ready for Billing and
Invoicing by USIPCOM. Customer failure to promptly schedule and activate the circuit will result in billing beginning
before service can be utilized by the Customer. In addition, the Customer is solely responsible for canceling any service
with previous Carrier, and for updating any email or web hosting IP addresses with the current provider. USIPCOM does
not support email or web hosting applications but can update any email or DNS records once the activation appointment
has been completed.
Multi-Site Solutions
Multi-site solutions such as MPLS are billed site by site and not when all sites are installed. If all sites are ordered at the
same time, each site will be billed as they are installed, tested, and accepted by the Carrier, regardless of whether
Customer has completed all necessary steps to activate Service or whether other sites in the MPLS network are ready for
activation.
Move Orders
In the event the Customer wishes to move service to a new location USIPCOM must be notified by an authorized contact
by emailing support@usipcom.com a minimum of sixty (60) business days prior to the move. USIPCOM will coordinate the
move of services once the new location is secure, has power, has a backboard or rack for equipment, and a new contract
with USIPCOM has been signed and processed. Please note that Customers that do not have a minimum of twelve (12)
months left on their existing contract will be re-termed for one (1) year upon completion of the move. The general
timeframe for Data service move orders is the same as the timeline noted above.
Customer Acceptance
Customer acknowledges that the preceding installation timeline is provided as a general timeline only and that USIPCOM
does not guarantee any specific date or timeframe for installation. Customer has read all of the requirement or
specification for Data Service installation. Customer further acknowledges that failure to meet any requirement or
specification may result in delays in the installation process. Customer further acknowledges that Billing/Invoicing for
Data Service(s) will begin no later than two (2) business days after service is deemed ready for activation by USIPCOM.
By signing below, Customer signatory certifies that (s)he is an officer or certified representative of the above listed
Company authorized to enter into a binding agreement(s) on behalf of said company and affirmed by seal below as of the
date below.
Customer Acceptance USIPCOM Acceptance
Print Name:Print Name:
Signature:Signature:
Title:Title:
Date:Date:
pg. 1
Terms & Conditions
Internet Services Terms and Conditions
These Service Terms and Conditions (the “Terms and Conditions”) apply to the Services (as
defined below) described in the Service Order Form (“SOF”) by and between USIPCOM, LLC.
(“Provider”) and the customer named in the SOF (“Customer”). Provider may amend these
Terms and Conditions from time to time by posting an amended version at
www/usipcom.com/legal/ and sending Customer written notice thereof. Such amendment will be
deemed accepted and become effective thirty (30) days after such notice (the “Proposed
Amendment Date”) unless Customer first gives Provider written notice of rejection of the
amendment. If Customer rejects such amendment, these Terms and Conditions will continue
pursuant to its original provisions and the amendment will become effective at the
commencement of the next Renewal Term (as defined below) following the Proposed
Amendment Date. Customer’s continued use of the Services following the effective date
of an amendment will confirm Customer’s consent thereto.
1. Service Description. Provider will provide Customer with the Services described in the SOF
for the Service Term so long as no Default (as defined below) has occurred. Customer has the
sole and exclusive responsibility for the installation, configuration, security (including, without
limitation, firewall security policies, even if Customer uses a third party to configure and
implement such measures), and integrity of all Customer facilities, systems, equipment, proxy
servers, software, networks, network configurations and the like (the “CPE” ) used in
conjunction with or related to the Services provided by Provider, unless Customer obtains such
CPE from Provider pursuant to a written agreement between Customer and Provider and
Provider expressly assumes any of such duties in writing.
2. Service Activation Date. The “Service Activation Date” means the date two (2) business
days after Provider deems the applicable Services ready for activation, which customarily will
follow Provider’s receipt of confirmation from any applicable underlying carrier(s) that the
Services are ready for activation; provided, however, with respect to MPLS Services (as defined
below) only (as identified on the SOF), the “Service Activation Date” means the earlier of (i) the
date two (2) business days after Provider deems the Services ready for activation, which
customarily will follow Provider’s receipt of confirmation from any applicable underlying
carrier(s) that the Services are ready for activation; and (ii) the date the Service is successfully
activated by the underlying carrier and confirmed tested and accepted by Customer and Provider.
Provider will notify Customer (via phone, email or other means) of the Service Activation Date.
For clarity, the Service Activation Date established by Provider will apply regardless of whether
Customer has completed all necessary steps to activate the Services.
3. Service Term. The initial Service Term will be as specified in any applicable SOF
(the “Initial Service Term”). The Initial Service Term will automatically extend thereafter upon
the same terms and conditions applicable during the Initial Service Term for additional
consecutive term(s) of one (1) year unless earlier terminated pursuant to these Terms and
pg. 2
Conditions or unless either party provides notice of nonrenewal to the other at least sixty (60)
days prior to the expiration of the then existing Service Term.
4. Service Availability. Provider may from time-to-time interrupt or otherwise impact Services
for routine maintenance. Provider will make commercially reasonable efforts to provide to
Customer reasonable advance notification (via phone, email or other means) of such
maintenance. Provider will use commercially reasonable efforts to perform such maintenance in
a manner that will not unreasonably interrupt Services. Provider normally will perform
maintenance between the hours of 11:30 PM and 6:00 AM Eastern. If Provider determines that
emergency maintenance is necessary for any reason, Provider will make commercially
reasonable efforts to notify Customer with respect to the anticipated down-time and/or other
information pertinent to the affected Services.
5. Support Provider. provides support for the Services only as described at
www.usipcom.com/legal/ pursuant to any applicable Service Level Agreement (“SLA”) posted
at (“www.usipcom/legal/USIPCOM-SLA. NOTWITHSTANDING ANY TERM OF THESE
TERMS AND CONDITIONS OR ANY APPLICABLE SLA TO THE CONTRARY,
PROVIDER DOES NOT SUPPORT ANY SERVICES BEYOND THE PROVIDER POINT OF
DEMARCATION, DEFINED AT WWW.USIPCOM.COM/LEGAL/. (e) theft, or (f) disaster. If
USIPCOM CPE requires maintenance not caused by one of the events set out in the sentence
above, USIPCOM or its agents shall either arrange to repair the CPE at Customer’s premises or
ship an equivalent pre-configured replacement to Customer. If replacement CPE is shipped to
Customer, Customer shall return the faulty CPE to USIPCOM within ten (10) days of receiving
the replacement CPE or pay for such CPE. Customer will not receive compensation for
downtime associated with CPE replacement or repair. In addition, if Customer has rented CPE,
Customer shall return (at Customer’s own expense) USIPCOM CPE to USIPCOM within ten
(10) days of termination. If this CPE is not returned in good working condition to USIPCOM
Customer shall be invoiced and pay for this CPE. Should reject to the terms and conditions set
forth in the Manufacturer’s or Publisher’s warranty, End-User license or agreement applicable to
such CPE or CPE Provider Service, with no warranty of any kind from USIPCOM. Should
customer receive purchased CPE that is damaged or dead on arrival Customer must notify
USIPCOM Customer Care within ten (10) days of receipt. Returns will only be accepted on
brand new factory-packaged products within thirty (30) days of the date CPE was shipped. All
products must be fully complete including all original manufacturer boxes with the UPC code
and packing materials, all manuals, blank warranty cards, accessories and any other
documentation included with the original shipment. Products returned in used or altered
condition will not be accepted. After thirty (30) days from initial product ship date, all sales are
final. Customer is responsible for shipping charges to the USIPCOM distribution center for all
products being shipped for return or exchange. Customer is responsible for all risk of loss and
damage to products being shipped for return or exchange. Should Customer desire to return or
exchange purchased CPE, pursuant to the above conditions, then Customer must e-mail
Customer Care at customercare@usipcom.com to request a Return Materials Authorization
(RMA). All returns and exchanges will incur a twenty percent (20%) restocking fee, as
calculated according to the original purchase price. If the RMA is in response to CPE delivered
pg. 3
dead on arrival or damaged, and said CPE is found to be operating within manufacturer
specifications upon return, said CPE shall be subject to the restocking fee outlined above.
6. Applicable Only If Customer Purchases CPE from Provider: CPE purchased by Customer
from Provider may be covered under a limited warranty provided by any applicable
manufacturer or provider, which Provider will extend to Customer without charge to the extent
Provider can do so pursuant to our agreements with any applicable manufacturer or provider;
however, Provider provides no warranty with respect to any such purchased CPE (and/or CPE
provider service). All sales of CPE purchased by Customer from Provider are final; provided,
however, if Customer receives purchased CPE that is damaged or nonfunctional upon arrival, (i)
within ten (10) days of receipt of such damaged or nonfunctional CPE, Customer must notify
Provider via email to Customer Care at customercare@usipcom.com to request an RMA; (ii)
Provider only will accept returns of any such damaged or nonfunctional products within thirty
(30) days of the date of the shipment to Customer by Provider; (iii) any such damaged or
nonfunctional CPE timely returned to Provider by Customer must be fully complete, including
all original manufacturer boxes with the UPC code and packing materials, all manuals, blank
warranty cards, accessories and any other documentation included with the original shipment to
Customer; (iv) Provider will not accept CPE returned in used or altered condition; (v) Customer
is solely responsible for all costs and expenses connected to the shipment to Provider of any such
damaged or nonfunctional products shipped to Provider pursuant to this Section 7; (vi) Customer
is responsible for all risk of loss and damage to products being shipped to Provider pursuant to
this Section 7; and (vii) if Provider determines that the CPE operates within manufacturer
specifications upon return pursuant to any applicable RMA, the affected CPE will be returned to
Customer at Customer’s sole cost and expense, the sale of such CPE will remain final, and
Provider may charge Customer a restocking fee equal to twenty percent (20%) of the original
purchase price of such CPE. Notwithstanding any terms or conditions of any SLA to the
contrary, except as otherwise expressly provided in this Section 7, Provider does not maintain,
support or manage any CPE, which will be the obligation of Customer solely. Customer is solely
responsible for unauthorized access to or use of any Services by any third-party through CPE,
regardless of whether such unauthorized access is unintentional, accidental, intentional or
fraudulent and regardless of whether Customer had knowledge of such unauthorized access.
7. Applicable Only If Customer Obtains Managed Network Services Pursuant to Any
Applicable SOF: “Managed Network Services” are Services that may be specified in writing as
“Managed Network Services” pursuant to any applicable SOF and is a solution in which the
Internet access CPE (whether provided by Customer or Provider) is managed by Provider. If
Customer chooses to provide its own Internet access CPE, Customer hereby assigns full
operational management responsibility, including, but not limited to, full management of the
logical configuration for such CPE, solely to Provider. Except as expressly provided in any
applicable SOF, no Managed Network Services apply.
8.Applicable Only If Customer Obtains Professional Services Pursuant to Any Applicable
SOF: “Professional Services” are any services that may be specified in writing as “Professional
Services” pursuant to any applicable SOF and is a service in which Provider provides certain
pg. 4
professional services to Customer as specified in such SOF. Except as expressly provided in any
applicable SOF, no Professional Services apply. All Professional Services will be provided by
phone, email or other similar means from Provider’s facilities.
9. Charges for Service. The monthly recurring charge(s) (“MRC”) and any non-recurring
charge(s) (“NRC”) for Service are stated in said Service Order Form. Service charges are
exclusive of applicable taxes and surcharges, including the Federal Universal Service Fund
surcharge that USIPCOM passes on to its customers. At its sole discretion, USIPCOM may
require a security deposit to continue provisioning of Service. After the initial term, USIPCOM
may increase pricing upon at least thirty (30) days written notice. At any time, USIPCOM may
pass on to Customer any circuit price increases from underlying carriers with at least thirty (30)
days written notice. All rates and charges are subject to change immediately in the event there
are mandated surcharges or taxes imposed by federal, state or governmental agencies.
Notwithstanding the foregoing, in the event of any Regulatory Activity, or governmental taxation
changes, USIPCOM reserves the right, at any time with as much advance notice as reasonably
possible and without liability, to: (i) pass through to Customer all, or a portion of, any changes or
surcharges directly or indirectly related to such governmental or Regulatory Activity; (ii) modify
the Service, rates (including any rate guarantees), promotions, terms and/or conditions of this
Agreement in order to conform to such action; or (iii) if such Regulatory Activity materially and
adversely impairs the provision of Service under the Agreement, as reasonably determined by
USIPCOM, terminate the Agreement.
10. Billing and Payment. USIPCOM shall bill Customer for Service rendered at the rates stated
in said Service Order Form. Invoices shall include all applicable federal, state, and local taxes.
all such taxes, and all use, sales, commercial, gross receipts, privilege, surcharges, or other
similar taxes, license fees, miscellaneous fees, and surcharges, whether charged to or against
USIPCOM, Inc., which shall be payable by the Customer. However, if Customer provides proof
of its specific tax-exempt status, Provider shall not charge applicable taxes due to such
exemption. Customer shall supply Provider a valid and properly executed tax exemption
certificate(s). In such cases the Customer remains responsible for, and agrees to pay, any and all
remaining non-exempt charges; tax exemption status validation is solely the responsibility of the
Customer and Provider will not be obligated to consider any retroactive tax exemption.
USIPCOM shall commence billing for the monthly recurring charges and usage (the Service) on
the Service Commencement Date. First and second month charges for the recurring Service(s)
are billed upon Service Commencement. Where applicable, service charges for the first partial
month of service will be pro-rated and billed. Call usage charges are billed after the actual calls
and usage has occurred. Payments are due within fifteen (15) days of the invoice date. After
fifteen (15) days of non-payment, all fees will accrue interest at a rate of one and one-half
percent (1.5%) per month or any part thereof, or the highest rate allowed by applicable law, and
customer shall pay all collection costs incurred by USIPCOM (including, without limitation,
reasonable attorney’s fees). Some Customers installed prior to two-thousand-and-eight (2008)
may be subject to payment terms whereby payments are due within thirty (30) days from the
invoice date; USIPCOM reserves the right to amend said Customers to a fifteen (15) day
payment term should they fail to make satisfactory payments pursuant to their current account
pg. 5
payment term. At any point beyond provided invoice due date, where Customer has failed to
make satisfactory payment as so judged by USIPCOM, then USIPCOM may give Customer
written notification, by email, that Customer has committed a material breach of the Agreement
due to non-payment. Said notification will be provided five (5) business days prior to Service
suspension or termination. Customer must pay all outstanding charges, within said notice period,
to avoid suspension or termination of Service. If Service is terminated due to non-payment, then
the Termination fees described in the Material Breach Section shall apply. In its sole discretion,
USIPCOM may: (i) require a security deposit to continue the provisioning of Service(s) if
Customer’s approved level of credit is deemed insufficient; (ii) change payment terms, billing
cycle, and/or Due Date; (iii) demand immediate payment by wire or other means and discontinue
Service(s) without notice should Provider determine Customer’s usage exceeds their approved
level of credit; (iv) immediately block Customer’s Service(s) if a Customer’s pre-paid balance is
depleted or is at a level that cannot cover Customer’s estimated traffic during the time required
for the Customer to replenish their prepaid balance, or if Customer refuses to make any requested
payments. USIPCOM retains the right to bill, including any amended or corrected billing, for the
Service(s) for a period of up to twelve (12) months, commencing from the date the billed
Service(s) were provided to Customer. USIPCOM shall retain such billing rights for this twelve
(12) month period notwithstanding any prior billing to Customer for the same period(s) and
regardless of any otherwise conflicting billing conditions in this Agreement. Customer agrees
that for the duration of this twelve (12) month period, USIPCOM shall not be deemed to have
waived any rights with regard to billing for the provided Service(s) that are subject to this period,
nor shall any legal or equitable doctrines apply, including estoppel or laches.
11. Billing Disputes. In the event Customer disputes any invoiced charges, Customer shall pay
in full all charges invoiced by the Due Date and submit written notification in the form of an
email sent to customercare@usipcom.com, with “Notice of Billing Dispute” in the subject line of
the email. Such email notification must include the Customer’s contact information, the specific
dollar amount in dispute, detailed supporting reasons for the dispute, and any supporting
documentation if available. USIPCOM shall respond to Customer, in writing, within thirty (30)
calendar days of receiving a dispute notification from Customer. Any dispute resolved in favor
of Customer shall be credited as appropriate on the next available invoice. In the event that any
disputed amounts are deemed to be correct as billed and in compliance with this Agreement,
Customer shall be notified in writing that the charges have been deemed valid and legitimate,
and the dispute will be considered resolved by both parties; in such cases, if there should be any
amount due from Customer related to the dispute, then all such amounts shall be due and payable
immediately. Provider reserves the right to deny or delay any and all billing disputes and/or
credits if the Customer’s account is in arrears or otherwise not in good standing.
12. Resumption of Service. If Customer requests that Service be restored after a suspension or
termination, USIPCOM has the sole and absolute discretion to restore such Service and may
condition restoration upon satisfaction of such conditions as USIPCOM determines necessary for
its protection, including requiring Customer to execute a new agreement, pay all past due
invoices in full, pass USIPCOM’s credit approval, and/or make advance payments. New
nonrecurring charges also may apply to restore Service.
pg. 6
13. Additional NRC (if applicable). In addition to the standard NRC listed above, the following
NRC, if applicable, will apply
(i) Changes of IP Addresses: $100.00;
(ii) Service Reinstatement /Resumption Fee: $200.00 (plus any charges imposed by underlying
carrier(s) and/or pursuant to Section 12 above);
(iii) Missed Appointment Fee: $200.00;
(iv) Rejected Credit Card/Unpaid Check: $40.00 (or legal limit, if lower);
(v) Relocation Fee: varies upon address;
(vi) Upgrade Charge: varies upon specific upgrade requested;
(vii) Downgrade Charge: varies upon specific downgrade requested.
Inside Wiring.
The availability of inside wiring installation is dependent upon a number of factors, including,
without limitation, any applicable service address and/or LEC availability. Any inside wiring
provided by Provider’s underlying carrier(s) may incur additional fees to the charges listed in the
SOF. Any request for inside wiring or wiring extension for any applicable Services will be
provided on a best-effort basis only. In many cases, Customer's LEC will not extend wiring
beyond the Minimum Point of Entry (“MPOE”) as determined by the LEC. In all such cases,
Customer will provide any needed internal wiring or extensions (and required conduit, facilities,
power, etc.) to the circuit required to provision service unless Provider has agreed in writing to
provide this service to Customer.
Special Construction Charge.
When a Customer’s location has insufficient facilities needed to support any applicable Service,
the underlying carrier(s) may add facilities that may impose an additional “special construction
charge" or other similar charge. If this occurs, Provider will notify Customer (via phone, email or
other means) of the cost of these additional special construction charges, if available and if any,
as well as the estimated time to complete the construction. Customer must agree in writing to pay
these additional special construction costs within three (3) business days. If Customer fails to do
so, Provider will cancel the SOF for lack of facilities and the SOF will terminate without liability
to either Customer or Provider. Miscellaneous Charges. Miscellaneous charges and/or fees
imposed by any third party carrier or any underlying provider from time to time, whether
charged to or against Provider, will be payable by Customer, including, without limitation, any
cost recovery fee which shall represent an accurate and non-inflated recovery of the
miscellaneous charges and/or fees to or against Provider associated with the provision of
Service(s) by Provider to Customer. Usage charges (Applicable to burstable dedicated Internet
Access Service Only): Additional usage charges stated in any applicable SOF will be calculated
based on Customer’s monthly usage, which Provider will calculate as follows: Provider will take
usage samples approximately every five (5) minutes throughout the applicable month and will
retain the higher of two (2) samples taken during each five (5) minute period– one (1) sample
that will reflect inbound usage/utilization and one (1) sample that will reflect outbound usage/
utilization. At the end of the applicable billing period, the samples will be arranged from highest
to lowest. Provider will discard the top five percent (5%) of the samples for the purposes of
pg. 7
calculating Customer’s monthly usage. Provider will utilize the highest remaining sample (i.e.,
the ninety‐fifth percentile (95%) peak Mbps port utilization) (the “Mbps Port Utilization”) to
calculate Customer’s monthly usage. Provider will measure the Mbps Port Utilization to the
100th decimal place, but the invoice will reflect the Mbps Port Utilization only to the 10th
decimal place. Provider will multiply the Mbps Port Utilization by the per-‐Meg rate listed on
any applicable SOF to calculate any applicable additional usage charges. Provider will charge
Customer such additional usage charges as well as any applicable base rate provided in any
applicable SOF.
14.IP Addresses. USIPCOM assigns IP addresses to its customers for use with certain IP/data-
based Service. USIPCOM shall retain any assigned public IP addresses when a customer’s
service is terminated. USIPCOM and Customer agree that assigned addresses are “non-portable”
and other providers are not allowed to route these addresses. Customer, who has its own IP
addresses, which are allocated directly from American Registry for Internet Numbers (ARIN),
will be ported/routed by USIPCOM where reasonably possible. USIPCOM cannot guarantee the
portability/routability of these addresses beyond its own backbone and to the Internet in general.
USIPCOM reserves the right to modify its IP Address Allocation Policy without notice.
15. Material Breach. USIPCOM or Customer may terminate this Agreement and the Service(s)
provided hereunder in the event of a material breach that is not cured within thirty (30) days
following the delivery of written notice specifying said breach, except in the case of serious
material breaches, so judged by USIPCOM. Such notice from Customer must be in the form of
an email sent to customercare@usipcom.com with “Notice of Material Breach” in the subject
line of the email and Customer’s contact information and detailed explanation, including
supporting documentation if available, in the body of the email. Such notice from USIPCOM
shall be in the form of an email to the Customer. In the event of an uncured material breach by
USIPCOM, the Agreement and Service(s) shall be terminated without further liability to the
Customer, however, in such cases Customer shall remain responsible for: (a) charges for
Service(s) actually and properly received prior to the date of Breach notification, (b) one hundred
percent (100%) of the past due balance at the time of termination, and (c) any non-recurring
charges originally waived by USIPCOM. In the event of an uncured material breach by
Customer, such as early termination of this Agreement, the following termination fees shall
apply: (a) charges for Service(s) actually and properly received prior to the date of Breach
notification, (b) the total of monthly minimum commitments for all components of the Service(s)
for the remainder of the Service Order Term(s) and any additional early Termination fees
included in any and all relevant Service Order Form(s), (c) one hundred percent (100%) of the
past due balance at the time of termination, and (d) any nonrecurring charges originally waived
by USIPCOM.
16. Termination. Upon termination of the Service Agreement and/or the Service(s) not due to a
material breach, USIPCOM will disconnect, or will cause to be disconnected, the Service(s) if
notified by the Customer in writing via email to customercare@usipcom.com with no less than
forty calendar (40) days notice prior to termination of the Agreement and/or Service(s). In all
such cases, Customer retains the sole responsibility for notifying USIPCOM of any and all
requests for termination or disconnection of Service(s), including but not limited to the porting
pg. 8
out of billable telephone numbers (also referred to as “DIDs”), whether port outs are known or
unknown by Customer; and, Customer remains responsible for all billable charges related to
terminated Service(s) until USIPCOM is notified in writing as specified. Any request by
Customer for cancellation or termination at any time within the Service Agreement Term and/or
Service Term set forth in this Agreement, including: prior to installation, or at any time prior to
the Service Commencement or Activation Date, or in the case of early termination by Customer,
will be considered a Material Breach by the Customer and shall be subject to the applicable
Material Breach provisions as outlined in the Material Breach section of this agreement.
17. Termination by Provider. In addition to any other right that Provider may have to terminate
or suspend these Terms and Conditions and/or any applicable SOF, if Provider determines, in its
sole discretion, that Customer’s ongoing use of any or all Services, and/or the specific method or
technology utilized by Customer places the network operated by Provider, other customers,
partners or the overall business(es) of each in jeopardy, Provider reserves the right to terminate
these Terms and Conditions and/or any applicable SOF and Customer’s access to any or all
applicable Services immediately and without notification.
18. Cooperation with Investigations. USIPCOM will cooperate with appropriate law
enforcement agencies and other parties involved in investigating claims of illegal or
inappropriate activity on the USIPCOM Network. USIPCOM reserves the right to disclose
customer information to the extent authorized or required by federal or state law. In those
instances, involving child pornography, USIPCOM complies with all applicable federal and state
laws including providing notice to the National Center for the Missing and Exploited Children or
other designated agencies.
19. Acceptable Use Policy. All use of Service must comply with USIPCOM’s Acceptable Use
Policy (“AUP”), which is posted at www.usipcom.com and is incorporated herein by reference.
By accepting USIPCOM Service, Customer agrees to comply with this AUP and any subsequent
modifications thereto. USIPCOM reserves the right to modify this AUP from time to time,
effective upon posting the AUP as modified at the URL shown above. Violation of the AUP
shall be considered a material breach of this Agreement pursuant to Section 14.
20. Dispute Resolution Process and Applicable Law.
(a) It is the mutual desire of the parties to promptly and fully resolve any dispute arising in
connection with these Terms and Conditions and/or any applicable SOF in good faith,
confidentially, and informally with minimal transaction costs; no public statement may be made
by any party regarding any such dispute. If either party determines that the dispute cannot be
resolved informally, then such party will initiate an escalation process by giving written
notice (“Escalation Notice”) to the other party. Each party will name one executive as its
representative, to be a person knowledgeable of the subject matter in dispute and someone with
authority to discuss the dispute (“Officers”). The Officers will meet in person or by conference
call, together with any persons assisting them, within fifteen (15) days after delivery of the
Escalation Notice. All negotiations conducted by the Officers are confidential and will be treated
as compromise and settlement negotiations for purposes of the Federal Rules of Evidence and
any state rules of evidence. The Officers will conduct such additional meetings as they deem
pg. 9
necessary to exchange relevant information, will appoint staff to engage in resolution of any
disputed facts, and will attempt to resolve the dispute. Should the Officers be unable to resolve
the dispute within such fifteen (15) days, or within such additional time as the parties may
otherwise agree to in writing, either party may demand mediation, whereupon the parties will, in
good faith, mediate the dispute no later than thirty (30) days after such demand through the
services of a mutually selected mediator, the cost of whom will be borne equally by the parties,
at a date and location selected by the mediator after consultation with the parties. IF THE
DISPUTE IS NOT RESOLVED AFTER APPLYING THE ESCALATION PROCEDURES
SET FORTH ABOVE, THE PARTIES AGREE TO WAIVE ANY RIGHT TO TRIAL BY
JURY IN ANY JUDICIAL PROCEEDING ARISING UNDER OR RELATED TO THE
SUBJECT MATTER OF THIS AGREEMENT, AND AGREE TO SUBMIT ALL
CONTROVERSIES, CLAIMS AND MATTERS OF DIFFERENCE TO ARBITRATION
ACCORDING TO THE COMMERCIAL RULES AND PRACTICES OF THE AMERICAN
ARBITRATION ASSOCIATION (“AAA”). Arbitration here under will occur within sixty (60)
days of the date of submission before a single neutral arbitrator having significant experience in
the subject matter of this Agreement and who will selected in accordance with AAA rules.
Arbitration proceedings will take place in Wake County, North Carolina. Discovery will be
permitted, including the use of interrogatories, requests for admission and production of
documents and depositions. If the amount claimed to be in dispute is less than $500,000, all
applicable expedited procedures of the AAA will apply. The arbitrator’s fees and costs of the
arbitration will be borne by the party against whom the award is rendered, except that if the
arbitrator issues a split decision, granting partial relief to both parties, the arbitrator will
equitably allocate the arbitrator’s fees and other costs. Each party will pay its attorney’s fees
related to any dispute related to this Agreement. The arbitration award will be final and binding
on both parties of this Agreement, will not be subject to any appeal and will be enforceable in
any court of competent jurisdiction. (b) ANY DISPUTE RESOLUTION PROCEEDINGS,
WHETHER IN ARBITRATION OR IN COURT, WILL BE CONDUCTED ONLY ON
AN INDIVIDUAL BASIS AND NOT IN A CLASS ACTION OR REPRESENTATIVE
ACTION OR AS A MEMBER IN A CLASS, CONSOLIDATED OR REPRESENTATIVE
ACTION. CUSTOMER WILL NOT BE A CLASS REPRESENTATIVE, CLASS
MEMBER OR OTHERWISE PARTICIPATE IN A CLASS, CONSOLIDATED OR
REPRESENTATIVE PROCEEDING. (c) This Agreement will be governed by, construed
under and enforced in accordance with the laws of the State of North Carolina without
reference to its choice of law principles or the United Nations Convention on the
International Sale of Goods. In the event any party brings a civil action or initiates judicial
proceedings of any kind related to this Agreement (except for actions to enter or collect on
judgments), the parties consent to the exclusive personal jurisdiction and venue of the
federal and state courts located in Wake County, North Carolina and the prevailing party
will be entitled to recover its costs, including reasonable attorney’s fees.
21. Limitation of Liability. EXCEPT AS PROVIDED IN SECTION 19, IN NO EVENT WILL
USIPCOM OR CUSTOMER BE LIABLE FOR ANY INDIRECT, INCIDENTAL, PUNITIVE
OR CONSEQUENTIAL DAMAGES (INCLUDING, WITHOUT LIMITATION, LOST
pg. 10
PROFITS) ARISING OUT OF OR IN RELATION TO THE SERVICE(S), CPE, AND/OR
ANY PRODUCTS OR SERVICE PROVIDED BY THIRD PARTIES UNDER THIS
AGREEMENT. USIPCOM’S MAXIMUM LIABILITY UNDER THIS AGREEMENT IS
LIMITED TO SERVICE CREDITS NOT TO EXCEED THE FEES PAID TO USIPCOM BY
CUSTOMER FOR THE SERVICE PROVIDED.
22. Indemnity. Customer shall indemnify and hold harmless USIPCOM, its Officers,
Employees, Agents, and Affiliates from and against any and all alleged or actual losses, costs,
claims, liability of any kind, damages (including to any tangible property or bodily injury to or
death of any person), or expense of whatever nature, (including reasonable attorneys' fees) to or
by any third party, relating to or arising from (a) the use of the Service provided to Customer,
whether or not Customer has knowledge of or has authorized access for such use, (b) any
damage to or destruction of CPE not caused by USIPCOM or its agents, and (c) any material
breach of this Agreement by Customer. Customer has the sole and exclusive responsibility for
the installation, configuration, security, and integrity of all Customer systems, equipment,
software, and networks (the “Customer Equipment”) used in conjunction with or related to the
Service(s) provided by USIPCOM. Customer therefore shall indemnify and hold harmless
USIPCOM from and against any actual or alleged losses, costs, claims, liability of any kind,
damages, or expenses or fees (including reasonable attorneys' fees) on the part of or which may
be incurred by Customer or a third-party relating to or arising from the use or operation of the
Customer Equipment. Customer’s indemnification in this subsection includes any alleged or
actual losses or claims in connection with unauthorized access to or use of the Service(s) by any
third-party through Customer Equipment, regardless of whether such unauthorized access is
unintentional, accidental, intentional or by fraud and regardless of whether Customer had
knowledge of such unauthorized access. In all such cases of unauthorized access Customer
agrees that it retain full and sole responsibility for any and all charges for the Service(s) provided
by USIPCOM. In the event USIPCOM grants Customer access, either by online access, by
application programming interface (API), or access by any other means, to a service
ordering/management system and other related electronic tools (collectively, the “Electronic
Tools”), Customer agrees that it is fully and exclusively responsible for all information accuracy,
charges, costs, transactions, and activities conducted through such Electronic Tools. Customer
agrees that it is fully and exclusively responsible to safeguard, monitor, manage, and maintain
access to the Electronic Tools, and to only allow authorized use of the Electronic Tools to
persons that Customer designates. Customer therefore agrees that it shall indemnify and hold
harmless USIPCOM from and against any actual or alleged losses, costs, claims, liability of any
kind, damages, or expenses or fees (including reasonable attorneys' fees) on the part of or
which may be incurred by Customer, or a third-party, relating to or arising from the use or
operation of the Electronic Tools. Customer’s indemnification in this subsection includes any
alleged or actual losses or claims in connection with unauthorized access to, use, transactions, or
activity conducted through the Electronic Tools, regardless of whether such unauthorized access
is unintentional, accidental, intentional, or by fraud, and regardless of whether Customer had
knowledge of such unauthorized access. In all such cases of unauthorized access Customer
pg. 11
agrees that it retains full and sole responsibility for any and all charges for the Service(s)
provided by USIPCOM.
23. No Warranties and Customer Assumption of Risk. EXCEPT AS OTHERWISE
EXPRESSLY PROVIDED IN AN APPLICABLE SLA, ANY APPLICABLE SERVICE AND
ANY CPE, EQUIPMENT, AND/OR RELATED SERVICES EACH IS PROVIDED “AS IS”
AND “AS AVAILABLE” AND WITHOUT WARRANTIES OF ANY KIND EITHER
EXPRESS OR IMPLIED. TO THE FULLEST EXTENT PERMISSIBLE PURSUANT TO
APPLICABLE LAW, EACH OF PROVIDER, ITS AFFILIATES, SUPPLIERS AND, IF
APPLICABLE, RESELLERS DISCLAIMS ALL WARRANTIES, EXPRESS OR IMPLIED,
INCLUDING, WITHOUT LIMITATION, IMPLIED WARRANTIES OF
MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, OR ANY
WARRANTY OF NONINFRINGEMENT. WITHOUT LIMITING THE FOREGOING,
PROVIDER, ITS AFFILIATES, SUPPLIERS AND, IF APPLICABLE, RESELLERS DO
NOT WARRANT THAT ANY FUNCTIONS OF ANY SERVICES, ANY CPE,
EQUIPMENT, AND/OR RELATED SERVICES WILL BE UNINTERRUPTED OR
ERROR-FREE, THAT DEFECTS WILL BE CORRECTED, OR THAT ANY SERVICES
(OR ANY SERVER THAT MAKES ANY SERVICES AVAILABLE) WILL BE FREE OF
VIRUSES OR OTHER HARMFUL COMPONENTS. PROVIDER DOES NOT
WARRANT OR MAKE ANY REPRESENTATIONS REGARDING THE USE OR
RESULTS OF ANY SERVICES OR ANY ELECTRONIC TOOL IN TERMS OF ITS
CORRECTNESS, ACCURACY, RELIABILITY, UNAUTHORIZED ACCESS BY
THIRD PARTIES OR OTHERWISE. CUSTOMER (AND NOT PROVIDER) ASSUMES
THE ENTIRE COST OF ALL NECESSARY SERVICING, REPAIR OR CORRECTION.
CUSTOMER ACKNOWLEDGES THAT ANY DATA OR INFORMATION
DOWNLOADED OR OTHERWISE OBTAINED OR ACQUIRED THROUGH THE USE
OF ANY SERVICES AND/OR ELECTRONIC TOOL IS AT CUSTOMER’S SOLE RISK
AND DISCRETION AND PROVIDER WILL NOT BE LIABLE OR RESPONSIBLE
FOR ANY DAMAGE TO CUSTOMER OR CUSTOMER’S PROPERTY. CUSTOMER
HEREBY EXPRESSLY ASSUMES THE RISK OF ITS USE OF ANY INFORMATION
TRANSMITTED VIA ANY SERVICES AND/OR ANY ELECTRONIC TOOL. NO
ADVICE OR INFORMATION, WHETHER ORAL OR WRITTEN, OBTAINED BY
CUSTOMER FROM PROVIDER, ITS EMPLOYEES OR THROUGH OR FROM ANY
SERVICE AND/OR ELECTRONIC TOOL WILL CREATE ANY WARRANTY NOT
EXPRESSLY STATED IN THIS AGREEMENT. APPLICABLE LAW MAY NOT
ALLOW THE EXCLUSION OF IMPLIED WARRANTIES, SO THE FOREGOING
EXCLUSION MAY NOT APPLY. PROVIDER WILL HAVE NO OBLIGATION TO
DEFEND OR INDEMNIFY CUSTOMER FROM OR AGAINST ANY THIRD PARTY
CLAIMS ALLEGING THAT CUSTOMER’S USE OF ANY SERVICES OR ANY
ELECTRONIC TOOL OR THE EXERCISE OF ANY RIGHTS GRANTED HEREIN
INFRINGES ON ANY INTELLECTUAL PROPERTY OF ANY THIRD PARTY. IF A
CLAIM IS MADE, OR IN PROVIDER’S REASONABLE OPINION IS LIKELY TO BE
MADE, AGAINST PROVIDER, CUSTOMER OR ANY THIRD PARTY ALLEGING
pg. 12
THAT ANY APPLICABLE SERVICES OR ELECTRONIC TOOL OR ANY USE
THEREOF INFRINGES ANY INTELLECTUAL PROPERTY OF ANY THIRD PARTY,
PROVIDER MAY, IN PROVIDER’S SOLE DISCRETION, TERMINATE THESE
TERMS AND CONDITIONS AND/OR ANY APPLICABLE SOF AND ALL RIGHTS
AND OBLIGATIONS PURSUANT TO THESE TERMS AND CONDITIONS AND/OR
ANY APPLICABLE SOF.
24. Third Party Beneficiaries. The Parties do not intend by the execution, delivery, or
performance of this Agreement to confer any benefit, direct or incidental, upon any person or
entity not a party to this Agreement.
25. Miscellaneous. Customer acknowledges and understands that Customer is to receive the
Service detailed in this Agreement and the Customer is not relying on any affirmation of fact,
promise or description from any person or entity, nor any other oral or written representation
other than what is contained in this Agreement. Handwritten alterations or additions to this
agreement made by Customer will not be considered part of this Agreement. This Agreement
may only be modified, or any rights under it waived, by a separate written document executed by
both parties. This Agreement shall be governed by, construed under, and enforced in accordance
with, the laws of the State of North Carolina without reference to its choice of law principles. For
any action or suit to enforce any right or remedy of this Agreement, (except for actions to enter
or collect on judgments) the parties’ consent to exclusive jurisdiction and venue in the courts for
Wake County, North Carolina and the prevailing party shall be entitled to recover its costs,
including reasonable attorney’s fees. In the event of a conflict between this Agreement and any
applicable tariff, the tariff shall prevail. Customer may not assign this Agreement without
USIPCOM’s prior written consent. This Agreement shall be binding on the parties hereto and
their respective personal and legal representatives, successors, and permitted assigns. If any
provision of this Agreement is held to be invalid or unenforceable, the validity and enforceability
of the remaining provisions of this Agreement shall not be affected thereby. By signing the
unique, or any, Service Order Form, or any Attachments, Addendums, or any other documents
incorporated herein by reference. Customer signatory certifies that (s)he is an officer or certified
representative of the Customer, and as such is authorized to enter into this binding Agreement. In
the event any specified time frame or deadline denotes calendar days, it is agreed that when the
last date of required action or response falls on a weekend or holiday, the action and/or deadline
shall automatically extend to the next business day. Agreement headings are provided for
reference purposes only.
THIS AGREEMENT, TOGETHER WITH ANY ATTACHMENTS, INCLUDING ANY
SCHEDULES, ADDENDUMS, PRICE LISTS, SERVICE ORDERS, TERMS AND
CONDITIONS, SERVICE LEVEL AGREEMENTS, AND ACCEPTABLE USE
POLICIES, WHICH MAY BE POSTED AT:
WWW.USIPCOM.COM/CONTENT/LEGAL, AND WHICH ARE INCORPORATED
HEREIN BY REFERENCE, CONSTITUTE THE ENTIRE UNDERSTANDING
BETWEEN THE CUSTOMER AND USIPCOM, INC, WITH RESPECT TO THE
SERVICE(S) PROVIDED HEREIN. CUSTOMER ACKNOWLEDGES AND
UNDERSTANDS THAT CUSTOMER IS NOT RELYING ON ANY AFFIRMATION OF
pg. 13
FACT, PROMISE OR DESCRIPTION FROM ANY PERSON OR ENTITY, NOR ANY
OTHER ORAL OR WRITTEN REPRESENTATION OTHER THAN WHAT IS
CONTAINED IN THIS AGREEMENT AND ANY INCORPORATED DOCUMENTS.
26. Definitions. For the purposes of these Terms and Conditions and/or any applicable SOF, the
following terms will have the following meanings: “Default” occurs: (i) if Customer fails to
make any payment for Services more than two (2) business days immediately after the applicable
Due Date, or any other payment contemplated by these Terms and Conditions and/or any
applicable SOF on or before the date two (2) business days immediately after any applicable
required date; (ii) if Customer violates the AUP; (iii) if Customer fails to perform or observe any
term or obligation of these Terms and Conditions and/or any applicable SOF, including, without
limitation, any document incorporated by reference into these Terms and Conditions, not
otherwise specified in clauses (i) or (ii) above and applicable to the Services, which failure
remains uncured thirty (30) calendar days after Customer’s receipt of written notification from
Provider informing Customer of such failure; (iv) upon the institution of bankruptcy,
receivership, insolvency, reorganization or other similar proceedings, by or against Customer,
unless such proceedings have been dismissed or discharged not later than the date thirty (30)
calendar days immediately after the commencement of such proceeding; (v) upon the making of
an assignment for the benefit of creditors, adjudication of insolvency, or institution of any
reorganization arrangement or other readjustment of debt plan, of or by Customer;
and/or (vi) upon the appointment of a receiver for all or substantially all of Customer’s
assets. “LEC” means local exchange carrier. “MPLS Services” means those multiprotocol layer
switching services described in the SOF by and between Provider and Customer. “MRC” means
monthly recurring charge. “NRC” means non-recurring charge. “Regulatory Activity” means
any laws, regulations or other similar mandates (including, without limitation, any fees,
surcharges or other like charges imposed or mandated) by any federal, state or other
governmental agency at any time. “RMA” means a Return Materials Authorization. “Service
Term” will mean the period commencing on the Service Activation Date during which any
applicable SOF remains in effect with respect to any Services. For clarity, the “Service Term”
will expire and/or terminate immediately upon the date when all SOFs entered into with respect
to any Services from time to time will have expired and/or terminated by their terms. “Services”
means those services described in the SOF by and between Provider and Customer, which
services may include Burstable Dedicated Internet Access Services, dedicated Internet access
services, Managed Network Services, MPLS Services, Professional Services, and/or private line
services.
4
3
9
City Council Agenda Report
Meeting Date:October 17, 2023
From:Freddie Agyin, Director of Health and Environmental Control
Department:Health and Environmental Control
Submitted by:Veronica Petrosyan, Deputy Director of Health and Environmental
Control
Subject
Lease Agreement with WEA CA, PC (WEA)
Recommendation
Approve and authorize the City Administrator to execute a Lease Agreement with WEA, in
substantially the same form as submitted, for a one-year term.
Background
The City of Vernon executed a Master Affiliation Services Agreement with WEA effective July 1,
2023, for the Wellness and Equity Alliance to provide public health and clinical services. Public
health and clinical services will be administered using mobile healthcare vans and at the Vernon
Health and Wellness Center located at the southwest corner of Civic Center grounds off Baker
Way and Vernon Avenue.
In preparation for providing health care services at the Vernon Health and Wellness Center, WEA
submitted an application to the California Department of Health Care Services (DHCS) to become
a Medi-Cal provider. Providers credentialed with DHCS are eligible to provide service to Medi-
Cal Fee for Service beneficiaries. Medi-Cal is California's Medicaid health care program which
pays for a variety of medical services for children and adults with limited income and resources.
Medi-Cal is supported by federal and state taxes.
The DHCS Medi-Cal provider application requires a lease agreement for the provider’s service
location. Since the City owns the Vernon Health and Wellness Center service location, WEA is
required to execute a lease agreement with the City. To facilitate the DHCS application process,
staff is recommending approval of the lease agreement with WEA. The lease agreement has
been approved as to form by the City Attorney’s Office.
Fiscal Impact
Approval and execution of the lease agreement will result in $12 in additional revenue to the
General Fund for the 12-month term of the lease and $1 per month with extension of the term to
a month-to-month basis.
Attachments
1. Lease Agreement with WEA
LEASE AGREEMENT BETWEEN THE
CITY OF VERNON AND
WEA CA, PC (WEA)
THIS LEASE (“LEASE”) is made and executed this 17th day of October 2023, between
CITY OF VERNON, a California municipal corporation and California charter city (“CITY”),
and WEA CA, PC, a national alliance of population and public health professional corporation,
(“WEA” or “LESSEE”), who agree as follows:
1. RECITALS: This Lease is made with reference to the following facts and objectives:
A. LESSEE desires to rent two (2) medical office trailers and two (2) Sprinter
Mobile Vans situated on Vernon City Hall property located at 4305 South Santa
Fe Avenue in the City of Vernon, to house staff and facilities in furtherance of
CITY’s partnership with WEA to provide public health and clinical services to the
local population.
B. LESSEE acknowledges that it has inspected the Premises (as defined in Section 2,
below), and that the same are in good and tenantable condition on the date hereof,
LESSEE agrees to accept the premises, access and improvements “WHERE-IS”
and “AS-IS”, and LESSEE acknowledges and agrees that the CITY makes no
warranty or representation of any kind respecting the condition, safety or
suitability of the Premises, except as otherwise expressly stated in this LEASE.
2. DESCRIPTION OF PREMISES. CITY leases to LESSEE to use, on the terms and
conditions of this LEASE, two (2) medical office trailers and two (2) Sprinter Mobile Vans
situated on Vernon City Hall property located at 4305 South Santa Fe Avenue in the City of
Vernon, consisting of approximately 600 square feet, located on Vernon City Hall property, 4305
South Santa Fe Avenue in the City of Vernon, (“Premises”). The Premises subject to this Lease
is limited to the space identified herein and does not include other areas of City Hall property,
including conference spaces.
3. TERM. Unless extended or sooner terminated as provided in this Lease, the term of this
Lease is for twelve (12) months, commencing on November 1, 2023 and ending October 31,
2024. LESSEE may request to extend the term of this Lease on a month-to-month basis,
commencing November 1, 2024, upon giving CITY written notice of such election not later than
September 1, 2024. Upon receipt of such written notice, CITY may, but is under no obligation
to, agree to extend the term of this Lease on a month-to-month basis. If CITY agrees to extend
the term of this Lease on a month-to-month basis, then CITY will give LESSEE written notice of
such agreement no later than October 1, 2024. CITY’s failure to give such written notice of
agreement by October 1, 2024 will be deemed to be CITY’s disapproval of LESSEE’S request,
and the term of this Lease will expire on November 1, 2024.
4. LEASE FEE. During the term of this Lease (November 1, 2023 – October 31, 2024), the
CITY agrees to charge LESSEE one dollar ($1) per month. The Lease fee during any extension
WEA Lease Agreement
Page 2 of 9
____________________
term shall be one dollar ($1) per month and shall be paid on the first day of each calendar month,
commencing November 1, 2024.
5. USE OF PREMISES. Except as otherwise provided in this Lease, LESSEE will use the
Premises to house personnel and equipment to provide public health and clinical services in
conjunction with the partnership and then-current agreements between CITY and WEA. The
Premises may not be used for any other purpose. LESSEE understands and agrees that LESSEE
will not have the use of any conference space located on the Vernon City Hall property, other
than that which is currently located in the Premises.
6. UTILITIES. CITY will provide all reasonable utilities and services required for the use of
the Premises, including electricity, gas, internet, telephone services, trash, water, and janitorial
services.
7. TERMINATION. This LEASE may be terminated as follows:
A. At the expiration of the term;
B. Upon mutual written agreement between the parties;
C. Upon the date a condemning authority takes possession of all or any part of the
Premises or the building of which the Premises are a part; or
D. As provided in Section 18.
E. If the term of this LEASE is extended on a month-to-month basis as provided in
section 3, upon the giving by either party to the other of 30 (thirty) days prior written
notice of termination.
8. CONDITION OF PREMISES UPON TERMINATION. Upon termination of this
LEASE for any reason, LESSEE will vacate the Premises and deliver it to CITY in good order
and condition, damage by the elements, earthquake, and ordinary wear and tear which could not
have been avoided by reasonable maintenance practices excepted.
9. CONDEMNATION. If all or part of the building in which the Premises are located is
acquired by eminent domain or purchase in lieu thereof, CITY shall be entitled to receive all
awards and compensation in connection therewith, and LESSEE acknowledges that it will have
no claim to any compensation awarded for the taking or for loss of or damage to LESSEE’s
improvements, provided that LESSEE shall have the right to make a separate claim for loss of its
trade fixtures and personal property and for relocation expenses so long as the same does not
reduce LESSOR’S award and compensation.
10. FORCE MAJEURE. Except for the payment of monetary sums, no party to this LEASE shall
be chargeable with, or liable for, or responsible to the other for anything or in any amount due to,
WEA Lease Agreement
Page 3 of 9
____________________
and the time for performance hereunder by such party shall be extended for, any delay caused by
fire, earthquake, explosion, flood, the elements, acts of terrorism, acts of God, insurrection,
rebellion, riots, strikes, lockouts, unforeseeable labor or material shortages, litigation, or any other
cause whether similar or dissimilar to the foregoing which is beyond the reasonable control of such
party, and any delay due to said causes or any of them shall not be deemed a default under this
LEASE.
11. LESSEE’S PERSONAL PROPERTY. All personal property of LESSEE located at the
Premises will remain the property of LESSEE during the term of this LEASE and may be
removed by LESSEE at any time and shall be removed by LESSEE prior to the expiration or
other termination of the term of this LEASE. LESSEE, at LESSEE’S cost and expense, must
promptly repair all damage to the Premises occasioned by the removal of its personal property.
12. ALTERATIONS, MECHANICS’ LIENS. LESSEE will not make, or cause to be made,
any alterations or modifications to the Premises, or any part thereof, without CITY’s prior
written consent, which consent CITY is under no obligation to give. LESSEE will keep the
Premises free from any liens arising out of any permitted work performed, material furnished, or
obligations incurred by LESSEE.
13. ASSIGNMENT AND SUBLETTING. This LEASE may not be assigned, transferred, or
sublet by LESSEE, whether voluntarily or involuntarily. Any such purported transfer will be
null and void.
14. CITY’S ACCESS.
A. Access for Inspection. CITY and CITY’s agents shall have the right to enter the
Premises at reasonable times, upon not less than twenty-four (24) hours prior notice to
LESSEE or less in case of an emergency), for the purpose of inspecting same, and
making such alterations, repairs, improvements or additions to the Premises as CITY may
deem necessary.
CITY will conduct Premises inspections on a quarterly basis to identify
maintenance issues that require attention. CITY will provide to LESSEE a report
specifying such maintenance issues as are identified that are Lessee’s responsibility under
this Lease, and if appropriate, CITY will provide the estimated cost for services to
perform the maintenance.
B. No Warranty. Except as otherwise stated in this Lease, LESSEE hereby
acknowledges that neither the CITY nor any employees or agents of the CITY has made
any oral or written warranties or representations to Lessee relative to the condition or use
by LESSEE of said Premises and LESSEE acknowledges that LESSEE assumes all
responsibility regarding the Occupational Safety and Health Act, the legal use and
adaptability of the Premises and compliance with all applicable laws and regulations in
effect during the term of this Lease.
WEA Lease Agreement
Page 4 of 9
____________________
C. Security Measures. CITY shall have the right to require a reasonable security system,
device, operation or plan be installed and implemented to protect the Premises or any
alterations.
15. HOLDOVER. If LESSEE continues to occupy the Premises after the Lease expires, with
CITY’s written consent, such continued occupancy shall be on a month to month basis and such
tenancy otherwise will be subject to all of the terms and conditions of this LEASE excluding
rights to extend the term of this LEASE.
16. INDEMNIFICATION. Except to the extent directly caused by CITY’s negligence, LESSEE
agrees to indemnify, protect, defend (by counsel reasonably satisfactory to CITY) and hold
CITY harmless from and against all claims, losses, liabilities, actions, judgments, costs and
expenses (including reasonable attorneys’ fees and costs) which CITY may suffer or incur
arising from or relating to (a) LESSEE’s use of the Premises, (b) any negligence, act or omission
of LESSEE in or about the Premises or (c) any default by LESSEE under this LEASE. For
purposes of this section “CITY” includes CITY’s officers, officials, employees, agents,
contractors, representatives, guests, invitees, and volunteers, and “LESSEE” includes LESSEE’s
officers, officials, employees, agents, contractors, representatives, guests, invitees, and
volunteers.
A. LESSEE expressly agrees that this hold harmless and indemnification provision is
intended to be as broad and inclusive as is permitted by the law of the State of California
and that if any portion is held invalid, it is agreed that the balance will, notwithstanding,
continue in full legal force and effect.
B. It is expressly understood and agreed that the provisions of this Section will
survive termination or expiration of this LEASE.
C. The requirements as to the types and limits of insurance coverage to be
maintained by LESSEE as required by this LEASE, and any approval of such insurance
by CITY, are not intended to and will not in any manner limit or qualify the liabilities and
obligations otherwise assumed by LESSEE pursuant to this LEASE, including but not
limited to the provisions concerning indemnification.
17. INSURANCE. LESSEE must procure and maintain, at its sole cost and expense, insurance
required by the CITY in commercially reasonable amounts and in accordance with all applicable
state and federal laws and regulations. LESSEE shall provide CITY policies of insurance types
in the amount set forth below for the duration of the LEASE and provide CITY certificates
evidencing such coverage, which must be in a form approved by the CITY. In addition, the
insurance policies required shall be issued by insurance companies licensed to do business in the
state with an A.M. Best rating of at least A-VIII.
A. General Liability coverage with limits of not less than $2,000,000 per occurrence and
$4,000,000 aggregate. Premises/Operations and Personal injury coverage is required.
WEA Lease Agreement
Page 5 of 9
____________________
The City of Vernon, its directors, commissioners, officers, employees, agents, and
volunteers must be endorsed on the policy as additional insured under the LESSEE
insurance policy; it shall be primary and non-contributory without seeking
contribution from the CITY’s insurance or self-insurance.
B. Automobile Liability coverage with limits of not less than $1,000,000 per occurrence
and $2,000,000 annual aggregate. LESSEE agrees to subrogate automobile liability
resulting from performance under this LEASE. The City of Vernon, its directors,
commissioners, officers, employees, agents, and volunteers must be endorsed on the
policy as additional insured under LESSEE’s insurance policy; it shall be primary and
non-contributory without seeking contribution from the CITY’s insurance or self-
insurance.
C. Professional Errors and Omissions coverage with limits of not less than $5,000,000
per claim and the annual aggregate, covering all acts, errors, omissions, negligence,
infringement, of intellectual property (except patent and trade secret), network and
privacy risks (including coverage for unauthorized access, failure of security, breach
of privacy perils, wrongful disclosure of information, as well as notification costs and
regulatory defense) in the performance of services for the CITY or on behalf of the
CITY hereunder. LESSEE shall maintain such coverage for at least five years after
the termination of this LEASE.
D. Workers’ Compensation coverage with limits of not less than $1,000,000 per
occurrence. The policy shall be endorsed to waive all rights of subrogation against
the CITY, its directors, commissioners, officers, employees, and volunteers for losses
arising from the performance of this LEASE.
E. Excess Liability Coverage. Any umbrella or excess insurance coverage shall contain
or be endorsed to include a provision that such coverage shall also apply on a primary
and non-contributory basis for the benefit of the CITY before the CITY’s insurance
or self-insurance shall be called upon. If the underlying aggregate is exhausted, the
excess coverage will drop down as primary insurance.
F. Fire Insurance on Premises. CITY shall maintain insurance (or applicable self-
insurance) for fire damage covering the Premises.
18. COMPLIANCE WITH LAW. LESSEE will, at its sole cost and expense, comply with all
of the requirements of all federal, state, and local authorities now in force, or which may
hereafter be in force, pertaining to the Premises and will faithfully observe in the use of the
Premises all applicable laws, rules and regulations, including, without limitation, laws, rules and
regulations relating to the use, storage and disposal of toxic or hazardous substances. The
judgment of any court of competent jurisdiction that LESSEE has violated any such requirement,
law, rule or regulation in the use of the Premises will be conclusive of that fact as between CITY
and LESSEE.
WEA Lease Agreement
Page 6 of 9
____________________
19. AMENDMENT; WAIVER. No term or provision of this LEASE may be amended, altered,
modified or waived orally or by a course of conduct, but only by an instrument in writing signed by
a duly authorized officer or representative of the party against which enforcement of such
amendment, alteration, modification or waiver is sought. Any amendment, alteration, modification
or waiver shall be for such period and subject to such conditions as shall be specified in the written
instrument evidencing the same. Any waiver shall be effective only in the specific instance and for
the specific purpose for which given.
20. DEFAULT. The occurrence of any one or more of the following shall constitute a default by
LESSEE:
(a) Failure by LESSEE to make any payment required to be made by LESSEE hereunder as
and when due.
(b) Failure by LESSEE to observe or perform any of the covenants or provisions of this
LEASE, other than as provided in subsection (a) above, when such failure continues for a period of
ten (10) days after written notice of such failure is given by CITY to LESSEE; provided, that if the
nature of LESSEE's failure is such that more than ten (10) days are reasonably required for its cure,
then LESSEE will not be deemed to be in default if LESSEE commences such cure within said ten
(10) day period and thereafter diligently prosecutes such cure to completion.
(c) The making by LESSEE of any general arrangement or general assignment for the
benefit of creditors; (ii) LESSEE becoming a “debtor” as defined in the federal Bankruptcy Code
or any successor statute thereto (unless, in the case of a petition filed against LESSEE, the same
is dismissed within sixty (60) days; (iii) the appointment of a trustee or receiver to take
possession of substantially all of LESSEE’s assets located at the Premises or of LESSEE’s
interest in this LEASE, where possession is not restored to LESSEE within thirty (30) days; or
(iv) the attachment, execution or other judicial seizure of substantially all of LESSEE’s assets
located at the Premises or of LESSEE’s interest in this LEASE, where such seizure is not
discharged within thirty (30) days.
21. REMEDIES. If LESSEE is in default, then, in addition to all other rights and remedies which
CITY may have at law or in equity, CITY has the following rights and remedies which are not
exclusive but are cumulative:
(a) CITY can, with or without terminating this LEASE, reenter the Premises and remove all
property and persons therefrom, and any such property may be removed and stored in a public
warehouse or elsewhere at the cost and for the account of LESSEE. If CITY elects to reenter or
shall take possession of the Premises pursuant to legal proceedings or pursuant to any notice
provided by law, and if CITY has not elected to terminate this LEASE, CITY may either recover all
rent as it becomes due under this LEASE or relet the Premises or any part or parts thereof for such
term or terms and upon such provisions as CITY may deem advisable and will have the right to
make repairs to and alterations of the Premises. No reentry or taking possession of the Premises by
CITY is to be construed as an election to terminate this LEASE unless a written notice of such
WEA Lease Agreement
Page 7 of 9
____________________
intention is given to LESSEE by CITY. Notwithstanding any reletting without termination by
CITY because of LESSEE's default, CITY may at any time after such reletting elect to terminate
this LEASE because of such default. If CITY elects to relet the Premises without terminating this
LEASE, then rent received by CITY therefrom will be applied as follows:
(i) First, to any indebtedness from LESSEE to CITY other than rent due from
LESSEE;
(ii) Second, to all costs and expenses, including, without limitation, for
maintenance, repairs or alterations, incurred by CITY in connection with reletting the Premises; and
(iii) Third, to the payment of rent due and unpaid under this LEASE and the residue,
if any, will be held by CITY and applied in payment of future rent as the same may become due and
payable under this LEASE and to any damages and other amounts which CITY is otherwise entitled
to under this LEASE. Should that portion of such rent received from such reletting during any
month, which is applied to the payment of rent hereunder, be less than the rent payable hereunder
during that month by LESSEE, then LESSEE agrees to pay such deficiency to CITY immediately
upon demand. In no event will LESSEE be entitled to any excess rent received by CITY from such
reletting.
(b) CITY can terminate LESSEE's right to possession of the Premises at any time. No act
by CITY other than giving written notice to LESSEE will terminate this LEASE. Acts of
maintenance, efforts to relet the Premises, or the appointment of a receiver on CITY's initiative to
protect CITY's interest under this LEASE shall not constitute a termination of LESSEE's right to
possession.
(c) Without waiving the default, CITY can, at its sole option, pay such sums and/or take
such actions as are necessary in CITY’s reasonable judgment in order to cure the default, and all
sums expended or incurred by CITY in connection therewith, together with interest thereon at the
maximum rate permitted by law, shall be paid by LESSEE to CITY immediately on demand.
22. NOTICES. Except as otherwise expressly provided by law, all notices or other
communications required or permitted by this LEASE or by law to be served on or given to
either party to this LEASE by the other party will be in writing and will be deemed served when
personally delivered (including by commercial courier or next business day delivery service) to
the party to whom they are directed, or in lieu of the personal service, upon the date when
received as evidenced by the return receipt when deposited in the United States mail, certified or
registered mail, return receipt requested, postage prepaid, addressed to:
LESSEE at: WEA CA, PC
250 Quail Ridge Road
Scotts Valley, CA 95066
Attn: Nancy Anwar Evans
CITY at: City of Vernon
WEA Lease Agreement
Page 8 of 9
____________________
4305 South Santa Fe Avenue
Vernon, CA 90058
Attn: City Administration
Either party may change its address for the purpose of this section by giving written notice of the
change to the other party in the manner specified in this section.
23. ACCEPTANCE OF ELECTRONIC SIGNATURES. The Parties agree that agreements
ancillary to this LEASE and related documents to be entered into in connection with this LEASE
will be considered signed when the signature of a party is delivered by electronic transmission.
Such electronic signature will be treated in all respects as having the same effect as an original
signature.
24. GOVERNING LAW. This LEASE has been made in and will be construed in accordance
with the laws of the State of California and exclusive venue for any action involving this LEASE
will be in Los Angeles County.
25. PARTIAL INVALIDITY. Should any provision of this LEASE be held by a court of
competent jurisdiction to be either invalid or unenforceable, the remaining provisions of this
LEASE will remain in effect, unimpaired by the holding.
26. COUNTERPARTS. This LEASE may be executed in counterparts, each of which is an
original but all of which together constitute but one and the same instrument. Signature and
acknowledgment pages, if any, of this LEASE may be detached from any counterpart and re-
attached to any other counterpart of this LEASE which is identical in form hereto but having
attached to it one or more additional signature and acknowledgment pages.
27. ATTORNEYS’ FEES. If either party to this LEASE brings an action to enforce the terms
hereof or declare rights hereunder, the prevailing party in such action, on trial or appeal, shall be
entitled to reasonable attorneys' fees to be paid by the losing party as fixed by the court.
28. DISCLOSURE. Pursuant to California Civil Code section 1938, CITY states that, as of the
date of this LEASE, the Premises have not undergone inspection by a “Certified Access
Specialist” (“CASp”) to determine whether the Premises meet all applicable construction-related
accessibility standards under California Civil Code section 55.53.
29. HEADINGS; EXHIBITS. The section headings in this LEASE are for convenience of
reference only and are not to be referred to in construing or interpreting this LEASE. The
recitals to this LEASE, and all exhibits referred to in this LEASE, are a part of this LEASE.
[Signatures Begin on Next Page].
WEA Lease Agreement
Page 9 of 9
____________________
IN WITNESS WHEREOF, the parties hereto have executed this LEASE as of the day and year
first hereinabove written.
FOR WEA CA, PC
By:
Name:
Title:
Date:
By:
Name:
Title:
Date:
FOR CITY OF VERNON:
By:
Name: Carlos Fandino, Jr.
Title: City Administrator
Date:
ATTEST:
By:
Lisa Pope, City Clerk
APPROVED AS TO FORM:
By:
Zaynah N. Moussa, City Attorney
City Council Agenda Report
Meeting Date:October 17, 2023
From:Todd Dusenberry, General Manager of Public Utilities
Department:Public Utilities
Submitted by:Adriana Ramos, Administrative Analyst
Subject
Professional Services Agreement with Northwest Electrical Services, LLC to Perform Technical
Design, Controls, Automation and Analytical Services
Recommendation
A. Find that the proposed action is categorically exempt from California Environmental Quality
Act (CEQA) review, in accordance with CEQA Guidelines Section 15301, because the project
consists of the maintenance, repair or minor alteration of existing facilities/equipment and
involves negligible or no expansion of an existing use;
B. Find that the best interests of the City are served by a direct award of an agreement with
Northwest Electrical Services, LLC without a competitive selection process pursuant to Vernon
Municipal Code Section 3.32.110(B)(2);
C. Approve and authorize the City Administrator to execute a Professional Services Agreement
with Northwest Electrical Services LLC, in substantially the same form as submitted for a three-
year term from November 17, 2023, through November 16, 2026, in an amount not to exceed
$2,719,903 to provide technical design, controls, automation, construction, and analytical
services for Vernon Public Utilities Department; and
D. Authorize a contingency amount of five percent (5%), or $135,995.15, for any unforeseen
changes in fees or other expenses not included in the proposal, and grant authority to the City
Administrator to issue Change Orders for an amount up to the contingency amount, if necessary.
Background
Vernon Public Utilities (VPU) continually prioritizes improving its infrastructure and upgrading
technology while increasing efficiencies and strengthening its service offerings with the goal of
providing high-quality, reliable, and responsive service at competitive and stable rates. As part
of this effort, VPU continues to work toward upgrading, streamlining, and standardizing utility
services along with Supervisory Control and Data Acquisition (SCADA) systems in all facilities
and equipment in the electric, water, gas, and fiber divisions. The SCADA system enables VPU
to provide essential services more cost-effectively, reliably, efficiently, and safely. This is critical
for troubleshooting, especially for restoring service to customers during emergencies and
interruptions in service.
On November 17, 2020, the City Council approved a three-year Professional Services
Agreement with Northwest Electrical Services, LLC (NW) to perform technical design, controls,
automation, and analytical services. That agreement is set to expire on November 16, 2023. NW
has completed numerous successful projects during that time, including the implementation of a
new Water SCADA system, the implementation and commissioning of a fully automated water
controls system, updated water system instrumentation and controls, the design and installation
of a new water system fiber network and design and installation of a fiber ring for fully redundant
network hardware at Station A and City Hall, replacement of the H. Gonzales natural gas turbine
peaker engines (HG1 and HG2), and updated cyber security measures to comply with the
Federal Cybersecurity & Infrastructure Security Agency - Industrial Control Systems best
practices.
The proposed agreement with NW for the next three years will allow VPU to continue improving
efficiency in critical areas such as Power SCADA deployment and related hardware, MGS
Support, and Water and Power SCADA Maintenance. Several Water electrical projects were
delayed due to supply chain issues, especially for electrical equipment. As a result, Water
projects for Wells 19 and 22 and Pumping Plant 1 will be completed by late 2023 or 2024. The
training and development of operations and technical staff will also continue. There is a major
effort to enhance the H. Gonzales units to support black start capability, so VPU does not rely on
an older diesel generator.
As reflected in the proposal from NW, the company has consistently applied its expertise to many
projects as part of the three-year agreement approved by the City Council in November 2020. At
that time, there was a specific project scope planned for the water fund as outlined in the Water
Fund Capital Improvement Plan (CIP) as VPU began the much-needed deferred maintenance to
overhaul the City’s wells to supply groundwater to customers. Unfortunately, the deteriorating
condition of the water facilities and the pandemic-induced supply chain issues did not allow for
the projects to be completed as planned over the three-year period. Multiple wells failed during
the contract, forcing the City to rely on imported water for a short period of time. Imported water
has historically cost the City over $1,250,000 annually and is approximately four times more
expensive than pumping the City’s allocated groundwater allowance. Following the failure of
multiple wells within a short period, the Water Fund reprioritized and accelerated projects and
increased the workload for NW to return wells to operation swiftly, thus mitigating the need to
import costly water.
As VPU plans to complete the remaining work on the Water Fund CIP, NW will focus on
automation, controls, data collection, analysis, and upgrades to the electric transmission and
distribution system. A complete overhaul of the Power SCADA System is a significant
undertaking and a critical project to take VPU into the green commerce and renewable energy
future. The current Power SCADA system for remote control and real-time monitoring of the
electric system was implemented in 1995. Upgrading the SCADA system will support VPU
operations for the foreseeable future. As NW has already begun work to replace this legacy
SCADA system, it is critical that VPU retain the services of NW to continue the work and avoid
delays that could result in added costs or system interruptions. The transition to a more industry
standard platform will provide added flexibility for the utility on the vendors that will be able to
provide support and maintenance in the future.
Throughout the many projects that NW has been involved with, NW continuously involves VPU
field staff in every step of the process, conveying vast knowledge regarding the controls,
operation, and maintenance of electrical and control systems, thus adding tremendous value to
all VPU divisions. As a result, VPU now has some in-house capability to troubleshoot technical
issues and operate systems and facilities more efficiently and economically.
NW staff possesses a diverse technical skill set covering industrial design, utility operations,
capital project implementation, and preventative maintenance. They perform the necessary and
highly specialized tasks at a very competitive rate, assisting VPU in controlling costs. The
principal staff at NW have over 75 years of combined, direct industrial experience serving in
various positions in engineering, field services, startup and commissioning, operations, and
overall Electric and Water plant management. NW has extensive experience in oil and gas, power
generation, transmission and distribution, and machinery automation. Furthermore, NW has
been instrumental in the development, design, and implementation of the Water SCADA system.
Moreover, these specialized skills and diverse experience are critical in the utility industry and
demand for this level of technical and engineering expertise is very competitive. Additionally, for
almost ten (10) years, NW has been leading the overall design and implementation of key
SCADA and electronic systems for VPU which has been critical for overall system reliability and
the future infrastructure needed by VPU. It is important to note that these are unique skills, and
these critical projects require continuity for VPU’s current and future success as well as meeting
customer reliability.
The proposed agreement is exempt from competitive bidding pursuant to Vernon Municipal Code
(VMC) Section 3.32.110(A)(10) and can be exempt from competitive selection pursuant to
Section 3.32.110(B)(2) if a direct award is found to be in the best interests of the City. VMC
Section 3.32.110(B)(3) indicates that the City Council has the authority to make such a finding
when the proposed contract exceeds $100,000. The City’s best interests are served by a direct
award based on NW's demonstrated expertise in fields critical to VPU and their ability to provide
services in a manner that will result in significant cost savings for the City, as outlined in this staff
report.
Contracting with NW provides a significant advantage in terms of efficiency and cost.
Considering VPU’s budget, staff obtained competitive rates from other contractors and
determined that the rates proposed by NW provide a significant value. Furthermore, NW has
proposed to charge VPU a fixed hourly labor rate applicable to overtime labor as well. Equipment
purchases executed by NW will be submitted for review and authorization by City staff, with no
markup on equipment compared to other consultants who charge a markup on equipment
purchases. NW proposes to be on-site and available to VPU and responds to trouble calls at all
times throughout the day and night and can perform technical troubleshooting at any time (e.g.,
late night/early morning, weekends, holidays) without additional charges.
Award of this contract is prudent for VPU to continue to maintain, streamline, and upgrade utility
facilities, equipment, and processes to ensure reliability, maintain safety goals, lower operational
costs, and enhance the overall efficiency of operations across all utility divisions.
The proposed agreement has been reviewed and approved as to form by the City Attorney’s
Office.
Fiscal Impact
The fiscal impact is not-to-exceed $2,855,898.15 during the proposed contract term of three
years. Sufficient funds are available in the VPU Electric and Water Enterprise Funds for
applicable Divisions and Accounts for the current fiscal year and sufficient funds will be budgeted
in subsequent years.
Attachments
1. Services Agreement with Northwest Electrical Services, LLC
Page 1 of 17
SERVICES AGREEMENT BETWEEN THE CITY OF VERNON NORTHWEST
ELECTRICAL SERVICES LLC FOR TECHNICAL DESIGN, CONTROLS,
AUTOMATION AND ANALYTICAL SERVICES
COVER PAGE
Contractor: Northwest Electrical Services LLC
Responsible Principal of Contractor: John S. Blizman, General Manager
Notice Information - Contractor: Northwest Electrical Services LLC
17420 Goldenview Drive
Anchorage, AK 99516
Attention: John Blizman, General Manager
Telephone: (877) 336-3539
Notice Information - City: City of Vernon
4305 Santa Fe Avenue
Vernon, CA 90058
Attention: Todd Dusenberry,
General Manager of Public Utilities
Telephone: (323) 583-8811 ext. 579
Commencement Date: November 17, 2023
Termination Date: November 16, 2026
Consideration: Total not to exceed $2,719,903 (includes all
applicable sales tax); and more particularly
described in Exhibit B
Records Retention Period Three (3) years, pursuant to Section 11.20
Page 2 of 17
SERVICES AGREEMENT BETWEEN THE CITY OF VERNON AND NORTHWEST
ELECTRICAL SERVICES LLC FOR TECHNICAL DESIGN, CONTROLS, AUTOMATION AND
ANALYTICAL SERVICES
This Agreement is made between the City of Vernon, a California charter City and
California municipal corporation (“City”), and Northwest Electrical Services LLC, a limited liability
company (“Contractor”).
The City and Contractor agree as follows:
1.0 EMPLOYMENT OF CONTRACTOR. City agrees to engage Contractor to
perform the services as hereinafter set forth as authorized by the City Council on October 17,
2023.
2.0 SCOPE OF SERVICES.
2.1 Contractor shall perform all work necessary to complete the services set
forth in the Contractor's proposal to the City ("Proposal") dated August 16, 2023, Exhibit “A”, a
copy which is attached to and incorporated into this Agreement by reference.
2.2 All services shall be performed to the satisfaction of City.
2.3 All services shall be performed in a competent, professional, and
satisfactory manner in accordance with the prevailing industry standards for such services.
3.0 PERSONNEL.
3.1 Contractor represents that it employs, or will employ, at its own expense,
all personnel required to perform the services under this Agreement.
3.2 Contractor shall not subcontract any services to be performed by it under
this Agreement without prior written approval of City.
3.3 All of the services required hereunder will be performed by Contractor or
by City approved subcontractors. Contractor, and all personnel engaged in the work, shall be
fully qualified and authorized or permitted under State and local law to perform such services
and shall be subject to approval by the City.
4.0 TERM. The term of this Agreement shall commence on November 17, 2023, and
it shall continue until November 16, 2026, unless terminated at an earlier date pursuant to the
provisions thereof.
5.0 COMPENSATION AND FEES.
5.1 Contractor has established rates for the City of Vernon which are
comparable to and do not exceed the best rates offered to other governmental entities in and
around Los Angeles County for the same services. For satisfactory and timely performance of
Page 3 of 17
the services, the City will pay Contractor in accordance with the payment schedule set forth in
Exhibit “B” attached hereto and incorporated herein by reference.
5.2 Contractor's grand total compensation for the entire term of this
Agreement, shall not exceed $2,719,903 without the prior authorization of the City, as
appropriate, and written amendment of this Agreement.
5.3 Contractor shall, at its sole cost and expense, furnish all necessary and
incidental labor, material, supplies, facilities, equipment, and transportation which may be
required for furnishing services pursuant to this Agreement. Materials shall be of the highest
quality. The above Agreement fee shall include all staff time and all clerical, administrative,
overhead, insurance, reproduction, telephone, air travel, auto rental, subsistence, and all related
costs and expenses.
5.4 City shall reimburse Contractor only for those costs or expenses
specifically approved in this Agreement, or specifically approved in writing in advance by City.
Unless otherwise approved, such costs shall be limited and include nothing more than the
following costs incurred by Contractor:
5.4.1 The actual costs of subcontractors for performance of any of the
services that Contractor agrees to render pursuant to this Agreement, which have been
approved in advance by City and awarded in accordance with this Agreement.
5.4.2 Approved reproduction charges.
5.4.3 Actual costs and/or other costs and/or payments specifically
authorized in advance in writing and incurred by Contractor in the performance of this
Agreement.
5.5 Contractor shall not receive any compensation for extra work performed
without the prior written authorization of City. As used herein, “extra work” means any work that
is determined by City to be necessary for the proper completion of the Project, but which is not
included within the Scope of Services and which the parties did not reasonably anticipate would
be necessary at the time of execution of this Agreement. Compensation for any authorized
extra work shall be paid in accordance with the payment schedule as set forth in Exhibit “B,” if
the extra work has been approved by the City.
5.6 Licenses, Permits, Fees, and Assessments. Contractor shall obtain, at
Contractor’s sole cost and expense, such licenses, permits, and approvals as may be required
by law for the performance of the services required by this Agreement. Contractor shall have the
sole obligation to pay for any fees, assessments, and taxes, plus applicable penalties and
Page 4 of 17
interest, which may be imposed by law and which arise from or are necessary for the
performance of the Services by this Agreement.
6.0 PAYMENT.
6.1 As scheduled services are completed, Contractor shall submit to the
City an invoice for the services completed, authorized expenses, and authorized extra work
actually performed or incurred according to said schedule.
6.2 Each such invoice shall state the basis for the amount invoiced, including
a detailed description of the services completed, the number of hours spent, reimbursable
expenses incurred and any extra work performed.
6.3 Contractor shall also submit a progress report with each invoice that
describes in reasonable detail the services and the extra work, if any, performed in the
immediately preceding calendar month.
6.4 Contractor understands and agrees that invoices which lack sufficient
detail to measure performance will be returned and not processed for payment.
6.5 City will pay Contractor the amount invoiced within thirty (30) days after
the City approves the invoice.
6.6 Payment of such invoices shall be payment in full for all services,
authorized costs, and authorized extra work covered by that invoice.
7.0 CITY'S RESPONSIBILITY. City shall cooperate with Contractor as may be
reasonably necessary for Contractor to perform its services; and will give any required decisions
as promptly as practicable so as to avoid unreasonable delay in the progress of Contractor's
services.
8.0 COORDINATION OF SERVICES. Contractor agrees to work closely with City
staff in the performance of Services and shall be available to City’s staff, consultants, and other
staff at all reasonable times.
9.0 INDEMNITY. Contractor agrees to indemnify City, its officers, elected officials,
employees and agents against, and will hold and save each of them harmless from, any and all
actions, suits, claims, damages to persons or property, losses, costs, penalties, obligations,
errors, omissions or liabilities (herein “claims or liabilities”), including but not limited to
professional negligence, that may be asserted or claimed by any person, firm or entity arising
out of or in connection with the work, operations or activities of Contractor, its agents,
employees, subcontractors, or invitees, provided for herein, or arising from the acts or
omissions of Contractor hereunder, or arising from Contractor’s performance of or failure to
perform any term, provision, covenant or condition of this Agreement, except to the extent such
Page 5 of 17
claims or liabilities arise from the gross negligence or willful misconduct of City, its officers,
elected officials, agents or employees.
10.0 INSURANCE. Contractor shall, at its own expense, procure and maintain
policies of insurance of the types and in the amounts set forth below for the duration of the
Agreement, including any extensions thereto. The policies shall state that they afford primary
coverage.
i. Automobile Liability with minimum limits of at least $1,000,000 combined single
limit, including owned, hired, and non-owned liability coverage.
ii. Contractor agrees to subrogate automobile liability resulting from performance
under this Agreement by agreeing to defend, indemnify, and hold harmless the City and its
respective employees, agents, and City Council from and against all claims, liabilities, suits,
losses, damages, injuries and expenses, including all costs and reasonable attorney’s fees
(“Claims”), which are attributable to any act or omission by the City under the performance of
the services.
iii. General Liability with minimum limits of at least $1,000,000 per occurrence and
$2,000,000 aggregate written on an Insurance Services Office (ISO) Comprehensive General
Liability “occurrence” form or its equivalent for coverage on an occurrence
basis. Premises/Operations and Personal Injury coverage is required. The City of Vernon, its
directors, commissioners, officers, employees, agents, and volunteers must be endorsed on the
policy as additional insureds with respect to liability arising out of Contractor’s performance of
this Agreement.
(1) If the Contractor employs other contractors as part of the services
rendered, Contractor’s Protective Coverage is required. Contractor may
include all subcontractors as insured under its own policy or shall furnish
separate insurance for each subcontractor, meeting the requirements set
forth herein.
(2) Contractor agrees to subrogate General Liability resulting from
performance under this Agreement by agreeing to defend, indemnify, and
hold harmless the City and its respective employees, agents, and City
Council from and against all claims, liabilities, suits, losses, damages,
injuries and expenses, including all costs and reasonable attorney’s fees
(“Claims”), which are attributable to any act or omission by the City under
the performance of the services.
iv. Professional Errors and Omissions coverage in an amount not less than
Page 6 of 17
$1,000,000 per claim and the annual aggregate, covering all acts, errors, omissions,
negligence, infringement, of intellectual property (except patent and trade secret) and network
and privacy risks (including coverage for unauthorized access, failure of security, breach of
privacy perils, wrongful disclosure of information, as well as notification costs and regulatory
defense) in the performance of services for the City or on behalf of the City hereunder. Such
insurance shall be maintained in force at all times during the term of the Agreement and for a
period of 5 years thereafter for services completed during the duration of the Agreement. The
City shall be given at least 30 days’ notice of the cancellation or expiration of the
aforementioned insurance for any reason.
v. Excess Coverage – Any umbrella or excess insurance shall contain or be
endorsed to contain a provision that such coverage shall also apply on a primary and non-
contributory basis for the benefit of the City before the City’s own insurance or self-insurance
shall be called upon to project it as a named insured. Any umbrella or excess liability policy will
be in the “following form.” It will contain a provision to the effect that if the underlying aggregate
is exhausted, the excess coverage will drop down as primary insurance.
vi. Contractor shall comply with the applicable sections of the California Labor Code
concerning workers’ compensation for injuries on the job. In addition, Contractor shall require
each subcontractor to similarly maintain workers’ compensation insurance in accordance with
the laws of California for all of the subcontractor’s employees. Compliance is accomplished in
one of the following manners:
(1) Provide a copy of permissive self-insurance certificate approved by the
State of California; or
(2) Secure and maintain in force a policy of workers’ compensation insurance
with statutory limits and Employer’s Liability Insurance with a minimal limit
of $1,000,000 per accident. The policy shall be endorsed to waive all
rights of subrogation against the City, its directors, commissioners,
officers, employees, and volunteers for losses arising from the
performance of this Agreement or
(3) Provide a “waiver” form certifying that no employees subject to the Labor
Code’s Workers’ Compensation provision will be used in the performance
of this Agreement.
vii. Each insurance policy included in this clause shall be endorsed to state that
coverage shall not be canceled except after thirty (30) days prior written notice to the City.
viii. Insurance shall be placed with insurers with a Best’s rating of no less than A-VIII.
Page 7 of 17
ix. Prior to the commencement of performance, Contractor shall furnish the City with
a certificate of insurance for each policy. Each certificate must be signed by a person
authorized by that insurer to bind coverage on its behalf. The certificate(s) must be in a form
approved by the City. City may require complete, certified copies of any or all policies at any
time.
x. Failure to maintain required insurance at all times shall constitute a default and
material breach. In such event, Contractor shall immediately notify the City and cease all
performance under this Agreement until further directed by the City. In the absence of
satisfactory insurance coverage, City may, at its option: (a) procure insurance with collection
rights for premiums, attorney’s fees and costs against Contractor by way of set-off or
recoupment from sums due to Contractor, at City’s option; (b) immediately terminate this
Agreement and seek damages from the Agreement resulting from said breach; or (c) self-insure
the risk, with all damages and costs incurred, by judgment, settlement or otherwise, including
attorney’s fees and costs, being collectible from Contractor, by way of set-off or recoupment
from any sums due to Contractor.
11.0 GENERAL TERMS AND CONDITIONS.
11.1 INDEPENDENT CONTRACTOR.
11.1.1 It is understood that in the performance of the services herein
provided for, Contractor shall be, and is, an independent contractor, and is not an agent, officer
or employee of City and shall furnish such services in its own manner and method except as
required by this Agreement, or any applicable statute, rule, or regulation. Further, Contractor
has and shall retain the right to exercise full control over the employment, direction,
compensation and discharge of all persons employed by Contractor in the performance of the
services hereunder. City assumes no liability for Contractor’s actions and performance, nor
assumes responsibility for taxes, bonds, payments, or other commitments, implied or explicit, by
or for Contractor. Contractor shall be solely responsible for, and shall indemnify, defend and
save City harmless from all matters relating to the payment of its employees, subcontractors
and independent contractors, including compliance with social security, withholding and all other
wages, salaries, benefits, taxes, exactions, and regulations of any nature whatsoever.
11.1.2 Contractor acknowledges that Contractor and any subcontractors,
agents or employees employed by Contractor shall not, under any circumstances, be
considered employees of the City, and that they shall not be entitled to any of the benefits or
rights afforded employees of City, including, but not limited to, sick leave, vacation leave,
Page 8 of 17
holiday pay, Public Employees Retirement System benefits, or health, life, dental, long-term
disability or workers' compensation insurance benefits.
11.2 CONTRACTOR NOT AGENT. Except as the City may authorize
in writing, Contractor and its subcontractors shall have no authority, express or implied, to act
on behalf of or bind the City in any capacity whatsoever as agents or otherwise.
11.3 OWNERSHIP OF WORK. All documents and materials furnished by the
City to Contractor shall remain the property of the City and shall be returned to the City upon
termination of this Agreement. All reports, drawings, plans, specifications, computer tapes,
floppy disks and printouts, studies, memoranda, computation sheets, and other documents
prepared by Contractor in furtherance of the work shall be the sole property of City and shall be
delivered to City whenever requested at no additional cost to the City. Contractor shall keep
such documents and materials on file and available for audit by the City for at least three (3)
years after completion or earlier termination of this Agreement. Contractor may make duplicate
copies of such materials and documents for its own files or for such other purposes as may be
authorized in writing by the City.
11.4 CORRECTION OF WORK. Contractor shall promptly correct any
defective, inaccurate or incomplete tasks, deliverables, goods, services and other work, without
additional cost to the City. The performance or acceptance of services furnished by Contractor
shall not relieve the Contractor from the obligation to correct subsequently discovered defects,
inaccuracy, or incompleteness.
11.5 RESPONSIBILITY FOR ERRORS. Contractor shall be responsible for its
work and results under this Agreement. Contractor, when requested, shall furnish clarification
and/or explanation as may be required by the City, regarding any services rendered under this
Agreement at no additional cost to City. In the event that an error or omission attributable to
Contractor occurs, then Contractor shall, at no cost to City, provide all necessary design
drawings, estimates and other Contractor professional services necessary to rectify and correct
the matter to the sole satisfaction of City and to participate in any meeting required with regard
to the correction.
11.6 WAIVER. The City's waiver of any term, condition, breach, or default of
this Agreement shall not be considered to be a waiver of any other term, condition, default or
breach, nor of a subsequent breach of the one waived. The delay or failure of either party at any
time to require performance or compliance by the other of any of its obligations or agreements
shall in no way be deemed a waiver of those rights to require such performance or compliance.
No waiver of any provision of this Agreement shall be effective unless in writing and executed
Page 9 of 17
by a duly authorized representative of the party against whom enforcement of a waiver is
sought.
11.7 SUCCESSORS. This Agreement shall inure to the benefit of, and shall
be binding upon, the parties hereto and their respective heirs, successors, and/or assigns.
11.8 NO ASSIGNMENT. Contractor shall not assign or transfer this
Agreement or any rights hereunder without the prior written consent of the City and approval by
the City Attorney, which may be withheld in the City's sole discretion. Any unauthorized
assignment or transfer shall be null and void and shall constitute a material breach by the
Contractor of its obligations under this Agreement. No assignment shall release the original
parties from their obligations or otherwise constitute a novation.
11.9 COMPLIANCE WITH LAWS. Contractor shall comply with all Federal,
State, County and City laws, ordinances, rules and regulations, which are, as amended from
time to time, incorporated herein and applicable to the performance hereof. Violation of any law
material to performance of this Agreement shall entitle the City to terminate the Agreement and
otherwise pursue its remedies. Further, if the Contractor performs any work knowing it to be
contrary to such laws, rules, and regulations Contractor shall be solely responsible for all costs
arising therefrom.
11.10 ATTORNEY'S FEES. If any action at law or in equity is brought to
enforce or interpret the terms of this Agreement, the prevailing party shall be entitled to
reasonable attorney's fees, costs, and necessary disbursements in addition to any other relief to
which such party may be entitled.
11.11 INTERPRETATION.
11.11.1 Applicable Law. This Agreement shall be deemed an
agreement and shall be governed by and construed in accordance with the laws of the State of
California. Contractor agrees that the State and Federal courts which sit in the State of
California shall have exclusive jurisdiction over all controversies and disputes arising hereunder,
and submits to the jurisdiction thereof.
11.11.2 Entire Agreement. This Agreement, including any exhibits
attached hereto, constitutes the entire agreement and understanding between the parties
regarding its subject matter and supersedes all prior or contemporaneous negotiations,
representations, understandings, correspondence, documentation, and agreements (written or
oral).
11.11.3 Written Amendment. This Agreement may only be changed
by written amendment executed by Contractor and the City Administrator or other authorized
Page 10 of 17
representative of the City, subject to any requisite authorization by the City Council. Any oral
representations or modifications concerning this Agreement shall be of no force or effect.
11.11.4 Severability. If any provision in this Agreement is held by any
court of competent jurisdiction to be invalid, illegal, void, or unenforceable, such portion shall be
deemed severed from this Agreement, and the remaining provisions shall nevertheless continue
in full force and effect as fully as though such invalid, illegal, or unenforceable portion had never
been part of this Agreement.
11.11.5 Order of Precedence. In case of conflict between the terms of
this Agreement and the terms contained in any document attached as an Exhibit or otherwise
incorporated by reference, the terms of this Agreement shall strictly prevail.
11.11.6 Construction. In the event an ambiguity or question of intent
or interpretation arises with respect to this Agreement, this Agreement shall be construed as if
drafted jointly by the parties and in accordance with its fair meaning. There shall be no
presumption or burden of proof favoring or disfavoring any party by virtue of the authorship of
any of the provisions of this Agreement.
11.12 TIME OF ESSENCE. Time is strictly of the essence of this agreement
and each and every covenant, term, and provision hereof.
11.13 AUTHORITY OF CONTRACTOR. The Contractor hereby represents
and warrants to the City that the Contractor has the right, power, legal capacity, and authority to
enter into and perform its obligations under this Agreement, and its execution of this Agreement
has been duly authorized.
11.14 ARBITRATION OF DISPUTES. Any dispute for under $25,000
arising out of or relating to the negotiation, construction, performance, non-performance,
breach, or any other aspect of this Agreement, shall be settled by binding arbitration in
accordance with the Commercial Rules of the American Arbitration Association at Los Angeles,
California and judgment upon the award rendered by the Arbitrators may be entered in any
court having jurisdiction thereof. The City does not waive its right to object to the timeliness or
sufficiency of any claim filed or required to be filed against the City and reserves the right to
conduct full discovery.
11.15 NOTICES. Any notice or demand to be given by one party to the other
must be given in writing and by personal delivery or prepaid first-class, registered or certified
mail, addressed as follows. Notice simply to the City of Vernon or any other City department is
not adequate notice.
Page 11 of 17
If to the City:
City of Vernon
Attention: Todd Dusenberry, General Manager of Public Utilities
4305 Santa Fe Avenue
Vernon, CA 90058
If to the Contractor:
Northwest Electrical Services LLC
17420 Goldenview Drive
Anchorage, AK 99516
Attention: John Blizman, General Manager
Phone: (877) 336-3539
Any such notice shall be deemed to have been given upon delivery, if personally
delivered, or, if mailed, upon receipt, or upon expiration of three (3) business days from the date
of posting, whichever is earlier. Either party may change the address at which it desires to
receive notice upon giving written notice of such request to the other party.
11.16 NO THIRD PARTY RIGHTS. This Agreement is entered into for the sole
benefit of City and Contractor and no other parties are intended to be direct or incidental
beneficiaries of this Agreement and no third party shall have any right or remedy in, under, or to
this Agreement.
11.17 TERMINATION FOR CONVENIENCE (Without Cause). City may
terminate this Agreement in whole or in part at any time, for any cause or without cause, upon
fifteen (15) calendar days' written notice to Contractor. If the Agreement is thus terminated by
City for reasons other than Contractor's failure to perform its obligations, City shall pay
Contractor a prorated amount based on the services satisfactorily completed and accepted prior
to the effective date of termination. Such payment shall be Contractor's exclusive remedy for
termination without cause.
11.18 DEFAULT. In the event either party materially defaults in its obligations
hereunder, the other party may declare a default and terminate this Agreement by written notice
to the defaulting party. The notice shall specify the basis for the default. The Agreement shall
terminate unless such default is cured before the effective date of termination stated in such
notice, which date shall be no sooner than ten (10) days after the date of the notice. In case of
default by Contractor, the City reserves the right to procure the goods or services from other
sources and to hold the Contractor responsible for any excess costs occasioned to the City
thereby. Contractor shall not be held accountable for additional costs incurred due to delay or
default as a result of Force Majeure. Contractor must notify the City immediately upon knowing
that non-performance or delay will apply to this Agreement as a result of Force Majeure. At that
Page 12 of 17
time Contractor is to submit in writing a Recovery Plan for this Agreement. If the Recovery Plan
is not acceptable to the City or not received within 10 days of the necessary notification of Force
Majeure default, then the City may cancel this order in its entirety at no cost to the City, owing
only for goods and services completed to that point.
11.19 TERMINATION FOR CAUSE. Termination for cause shall relieve the
terminating party of further liability or responsibility under this Agreement, including the payment
of money, except for payment for services satisfactorily and timely performed prior to the service
of the notice of termination, and except for reimbursement of (1) any payments made by the City
for service not subsequently performed in a timely and satisfactory manner, and (2) costs
incurred by the City in obtaining substitute performance. If this Agreement is terminated as
provided herein, City may require, at no additional cost to City, that Contractor provide all
finished or unfinished documents, data, and other information of any kind prepared by
Contractor in connection with the performance of Services under this Agreement. Contractor
shall be required to provide such document and other information within fifteen (15) days of the
request.
11.19.1 Additional Services. In the event this Agreement is terminated in
whole or in part as provided herein, City may procure, upon such terms and in such manner as
it may determine appropriate, services similar to those terminated.
11.20 MAINTENANCE AND INSPECTION OF RECORDS.
The City, or its authorized auditors or representatives, shall have access
to and the right to audit and reproduce any of the Contractor's records to the extent the City
deems necessary to insure it is receiving all money to which it is entitled under the Agreement
and/or is paying only the amounts to which Contractor is properly entitled under the Agreement
or for other purposes relating to the Agreement.
The Contractor shall maintain and preserve all such records for a period
of at least three (3) years after termination of the Agreement.
The Contractor shall maintain all such records in the City of Vernon. If
not, the Contractor shall, upon request, promptly deliver the records to the City of Vernon or
reimburse the City for all reasonable and extra costs incurred in conducting the audit at a
location other than the City of Vernon, including, but not limited to, such additional (out of the
City) expenses for personnel, salaries, private auditors, travel, lodging, meals, and overhead.
11.21 CONFLICT. Contractor hereby represents, warrants, and certifies that no
member, officer, or employee of the Contractor is a director, officer, or employee of the City of
Page 13 of 17
Vernon, or a member of any of its boards, commissions, or committees, except to the extent
permitted by law.
11.22 HEADINGS. Paragraphs and subparagraph headings contained in this
Agreement are included solely for convenience and are not intended to modify, explain or to be
a full or accurate description of the content thereof and shall not in any way affect the meaning
or interpretation of this Agreement.
11.23 ENFORCEMENT OF WAGE AND HOUR LAWS. Eight hours labor
constitutes a legal day's work. The Contractor, or subcontractor, if any, shall forfeit twenty-five
dollars ($25) for each worker employed in the execution of this Agreement by the respective
Contractor or subcontractor for each calendar day during which the worker is required or
permitted to work more than 8 hours in any one calendar day and 40 hours in any one calendar
week in violation of the provisions of Sections 1810 through 1815 of the California Labor Code
as a penalty paid to the City; provided, however, work performed by employees of contractors in
excess of 8 hours per day, and 40 hours during any one week, shall be permitted upon
compensation for all hours worked in excess of 8 hours per day at not less than 1½ times the
basic rate of pay.
11.24 EQUAL EMPLOYMENT OPPORTUNITY PRACTICES. Contractor
certifies and represents that, during the performance of this Agreement, it and any other parties
with whom it may subcontract shall adhere to equal employment opportunity practices to assure
that applicants, employees and recipients of service are treated equally and are not
discriminated against because of their race, religion, color, national origin, ancestry, disability,
sex, age, medical condition, sexual orientation or marital status. Contractor further certifies that
it will not maintain any segregated facilities. Contractor further agrees to comply with The Equal
Employment Opportunity Practices provisions as set forth in Exhibit “C”.
[Signatures Begin on Next Page].
Page 14 of 17
IN WITNESS WHEREOF, the Parties have executed this Agreement as of the
Commencement Date stated on the cover page.
City of Vernon, a California charter City
and California municipal corporation
By: ____________________________
Carlos Fandino, City Administrator
Northwest Electrical Services LLC, a limited
liability company
By:
Name:
Title:
ATTEST:
_______________________________
Lisa Pope, City Clerk
By:
Name:
Title:
APPROVED AS TO FORM:
_______________________________
Zaynah N. Moussa,
City Attorney
Page 15 of 17
EXHIBIT A
CONTRACTOR'S PROPOSAL
Professional Services Agreement with The City of Vernon to Perform Technical Design,
Controls, Automation and Analytical Services
2023 - 2026
August 16, 2023
Forward
Northwest Electrical Services has been engaged in a three-year contract since November 2020, and it has been a
very challenging period. Despite the COVID challenges, the Vernon Public Utilities (VPU) Water Division Capital
Improvement Projects (CIP) have been largely completed. There remains some work on the water system that
has been largely delayed due to COVID-19 supply chain issues.
Major accomplishments were achieved during the last three years:
1. Water SCADA has been fully deployed.
2. The new water network and fiber ring for water communication redundancy has been completed.
3. Physically separated servers and fully redundant network hardware have been installed and operating,
with equipment located at both Station A and City Hall.
4. Cybersecurity measures and architecture fully comply with the Federal ICCS best practices.
5. Fully automatic water autonomous control system is in operation, along with automated water
production reporting.
6. All Storm Water sump controls have been updated.
7. HG1 and HG2 engines were replaced. The new engines outperform the originals and have met the
emissions testing.
8. Work has begun on the new power SCADA system and blackstart functions of the HG1/2 units to
support MGS.
Also, we are proud and grateful to continue supporting the City during emergencies. Again, we are proud of the
relationship with the Water Division team and operations staff. With the ongoing development of the new
Water SCADA System, we have been able to forge a strong working relationship with operations staff who
regularly provide critical advice and guidance. Relationships such as the one with operations have translated into
successful completion of projects and will lead to further enhancements in operational efficiency. As always, we
answer the phone 24/7.
NORTHWEST ELECTRICAL SERVICES LLC
Design-Build-Commissioning-O&M of Electrical, Mechanical,
Automation and I&C Systems for Industry 17420 Goldenview Dr.
Anchorage AK 99516
http://nwelec.com
Phone: 877-336-3539
Fax: 484-551-3370
email: jblizman@nwelec.com
Projected Scope of Work
As we survey the work over the next three years, some of the work is still in the Water System CIP. Largely due
to supply chain delays, some jobs cannot be completed until late 2023/2024. Well 22, PP1, and Well 19 are the
remaining work, with extremely long lead times for basic electrical equipment. In addition, Power SCADA
development and deployment will be a focus over the next three years.
In addition to project work, maintenance of water system controls, networks, instrumentation, and continued
development and enhancements will factor into the workload. Training and development for both operations
and technicians is planned. Remote read-only access, particularly for field staff, is to be studied. Work to explore
the possibility of water export from the City along with water treatment is expected.
There is a major effort to enhance the Gonzales units to support black start in a manner which does not rely on
the older diesel generator and, as such, be capable of supporting at least the turning gear of the MGS CTs to
avoid a 40-hour lockout in the event of a major transmission interruption. Also, the Gonzales units will require
CEMS in 2026, so this effort and engineering are also planned, along with an upgrade of the HMI graphics, as the
version is getting outdated.
An allotment of time is allocated for Emergencies, MGS support, Gonzales Support, and special projects such as
engineering studies, etc. Given the nature of our wide areas of expertise, we often can offer support for a wide
variety of topics.
Detailed Work Scope
The following table represents the known scope and labor hour estimates for projects being undertaken by the
City. The total labor hours largely represent the engineering/commissioning expected. Based on the scope, the
following three years will be heavily labor intensive, with maintenance of low voltage electrical,
instrumentation, automation, networking, and IT functions for operations increasing in scope. This represents an
average 65-72 hour work week for the three weeks we propose to be on site. Materials line item is added where
Northwest can take advantage of certain discount options and pass those along at cost to the City.
Tasks Breakdown Cost Hours
1 Power SCADA 13.00%$333,957 2344
2 Power SCADA Hardware / Network 13.50%$346,801 2434
3 Gonzales / MGS Blackstart 1.00%$25,689 180
4 MGS Support 2.00%$51,378 361
5 Well 22 4.00%$102,756 721
6 Water SCADA Maintenance, revisions, network, reports, modeling 9.00%$231,201 1622
7 Power SCADA Maintenance, revisions, network, reports 9.00%$231,201 1622
8 Water and Power SCADA Remote Access (read only)0.50%$12,844 90
9 Water System Elecrtical LV maintenance 4.00%$102,756 721
10 Water System I&C Maintenance 2.60%$66,791 469
11 Operator Training and Development 2.10%$53,947 379
12 Automation Training and Development 3.00%$77,067 541
13 Station A Diesel Simulation 5.00%$128,445 901
14 Gonzales CEMS 2.50%$64,222 451
15 Emergency Response 2.50%$64,222 451
16 Gonzales Maintenance 0.50%$12,844 90
17 Control Room Display Wall 1.50%$38,533 270
18 PP1 New Building, VFD's electrical, automation 7.00%$179,823 1262
19 Well 19 electrical and VFD Conversion 7.50%$192,667 1352
20 Water Export and Treatment 1.00%$25,689 180
21 Sump Electrical and Control Maint for Public Works 0.50%$12,844 90
22 Technical Consulting 1.00%$25,689 180
23 External Consultants as required 1.50%$38,533 270
24 Materials $300,000 NA
94.20%$2,719,903 16982
Previous Contract Services Terms:
Northwest has not applied or considered a cost-of-living rate adjustment over the past three years despite
substantial inflationary pressures. Our contract has a fixed rate for three years, and like everyone else, we work
through the challenges, as the City also works through the same challenges.
Northwest charged a flat rate, regardless of the skill set involved. Unlike other firms, skillsets and positions such
as Project Management, Senior Engineer, Design Engineer, Commissioning Engineer, Test Engineer, Technician,
Network Design and Security, drafting, etc. have various billable rates. The IEEE published typical rates for
various industries in 2022. A few key rates to consider:
1. Utilities – Median rate $180 / hour nationwide, with a mean rate of $206 / hour.
2. For the Pacific census region, the median rate is $200 / hour.
3. For experience of 35 or more years, the median rate is $193 / hour nationwide.
By comparison, Northwest has combined over 75 years in the utility and process control industries. Moreover,
Northwest does not simply consult, we design and build, which are added costs to consultancy design fees. The
IEEE Survey report for 2022 reports an increase in rates nationally of $10 / hour between 2021 and 2022.
Additionally, BLS reports a 9.7% increase in CPI nationally from November 2021 to the present.
(https://data.bls.gov/pdq/SurveyOutputServlet)
Proposed Contract Services Terms:
Principal Rates
While the survey indicates an increase in rates of $10 / hour just in the past year, and CPI has increased 9.7%
since the start of the last contract, 9.7% would increase our rate to $156.32 / hour. We are pleased to inform
that the proposed rate will remain unchanged at a $142.50 / hour flat rate, which includes all expenses for
both principals (Mark Wray and John Blizman). There will be no additional charges for travel and, as in the
past, never a charge for overtime or phone calls, which we typically answer 24/7.
Additional Staff
If additional staff beyond two persons resident at any time is required, this would be at the cost of $130 / hour +
expenses billed at cost. This would be based on project requirements and must be authorized by the City before
deployment. This represents a 10% change to the previous contract, consistent with the IEEE survey. Since we
cannot control external rates, we need to recognize the increase.
Cost of Living Adjustments
Northwest will maintain the practice of not applying cost of living adjustments (inflation, etc.), with the sole
exception of a major change in CA state tax rates. Should the future political landscape increase tax liability
beyond the current levels, Northwest will review the impact and consult with the City only if the impact
represents a significant cost restructuring.
Insurance
• NW already maintains the insurance levels as currently required by the City. Current Insurance
certificates renewed in March 2023 are on file with the City.
• NW actively retains CA DIR Registration.
Contract Term
• The contract term is three years.
Material Purchases
• Northwest will purchase material as required and only as authorized by the City on a case-by-case basis
with zero markup.
Invoicing
• Invoices for Labor will be submitted once per month.
• All labor invoices shall be supported with timesheets.
• Invoices for material and/or expense costs, if applicable, will be submitted upon authorization by the
City to purchase.
• Material or expense invoices shall be supported with vendor quotations/bills, expense receipts, and
prior City authorization(s) for purchase.
Estimated Costs
Based on the scope of work and the proposed terms, Northwest estimates the cost of the labor hours only
portion of the contract to be $2,419,903. This represents a decrease from the previous three-year contract.
Materials are a separate line item and are estimated at $300,000. The proposed not-to-exceed amount is $
Features of the Proposed Services and Terms
• Residency on site allows for synergy between project completion and training and development.
• Including the residency on-site, the rate structure proposed is much less than market consultant rates.
• There is consistency in the contract rate year to year.
• NW's experience covers a wide spectrum of industrial design, operations, and maintenance.
• Our principals have held positions in engineering, field services, start-up and commissioning, operations,
plant front line, and executive management. We have worked in Oil and Gas, Power Generation,
Transmission and Distribution, and machinery automation. We have worked in over 36 countries.
Combined, our principals have 76 years of direct industrial experience.
• We have demonstrated the ability and resources to pursue a concept to the completion of many multi-
disciplined projects. Many of these projects involved engineering, procurement, and construction of
civil, mechanical, and electrical disciplines. Our experience in operations and maintenance ensures less
downstream problems with equipment and troubleshooting.
• Unlike traditional design firms, we have substantial experience in utility plant staff management,
budgeting, cost-benefit analysis, cost tracking, and resource and personnel management, provides our
clients with a partner in strategic planning and project execution. We have experience in large project
estimating IRP development, including emerging technologies contract management.
• We provide full life cycle costs of a design, factoring in O&M fixed and variable expenses, and
competently analyze the remaining life cycle of existing assets, including life cycle extension options.
• Our work philosophy is goal-oriented. We work closely with clients and are often embedded into the
client’s organization as a partner as opposed to a consultant.
• We embrace, encourage, and deliver client resource training. Many of our trained client professionals
have successfully transitioned from a previous trade role to a design, supervisory, and, in a few cases,
executive positions. We provide on-the-job training and structured classroom training.
• We can perform many generator and relay testing operations and do so regularly for Siemens.
• We have design and installation experience in Fire and gas systems.
• Our automation experience is substantial and not limited to any specific vendors. Our considerable
experience is in SCADA, PLCs, and embedded controllers. We have substantial experience in substation
automation with both SEL, Siemens, and Alstom. We are current and forward-looking with technology.
We are registered system integrators with Aveva, Schneider Electric, and Rockwell Software.
• Data integration between disparate, modern, and legacy systems both on the plant floor and corporate
systems.
• Cyber Security design experience for all network systems.
• Aside from automation systems, we have core programming experience in many languages, Java and
Javascript, C++, Python, .NET.
• We have substantial database programming experience. We have developed many database
applications leveraging raw field data into performance indicators on demand.
• Unlike many firms, we do not simply write specifications and plans. We have the ability to not only
provide engineering and research, but we also have the ability to build, subcontract, manage, and
commission. This ability, while working closely with the client, provides a much better handover
situation to operations and maintenance.
• Unlike many firms, we do not apply rates based on skillsets utilized. Our rates are fixed for a client. This
gives our clients the ability to utilize our skillsets without concern over the cost of any particular
resource or type of work we may be asked to complete. Our rates are very competitive, with a superior
skillset matrix and the flexibility to ensure work is completed. We do not charge overtime rates, and
often, there is no charge for off-duty assistance.
We are always committed to working as efficiently as possible and as a dedicated and loyal partner with the
City. We thank you for your continued trust in our services.
Sincerely,
John S. Blizman
General Manager
Northwest Electrical Services LLC
17420 Goldenview Dr.
Anchorage, AK 99516
ph: +1.877.336.3539
fax: +1.484.551.3370
email: jblizman@nwelec.com
mobile: +1.610.937.3987
Page 16 of 17
EXHIBIT B
SCHEDULE
Tasks Breakdown Cost Hours
1 Power SCADA 13.00%$333,957 2344
2 Power SCADA Hardware / Network 13.50%$346,801 2434
3 Gonzales / MGS Blackstart 1.00%$25,689 180
4 MGS Support 2.00%$51,378 361
5 Well 22 4.00%$102,756 721
6 Water SCADA Maintenance, revisions, network, reports, modeling 9.00%$231,201 1622
7 Power SCADA Maintenance, revisions, network, reports 9.00%$231,201 1622
8 Water and Power SCADA Remote Access (read only)0.50%$12,844 90
9 Water System Elecrtical LV maintenance 4.00%$102,756 721
10 Water System I&C Maintenance 2.60%$66,791 469
11 Operator Training and Development 2.10%$53,947 379
12 Automation Training and Development 3.00%$77,067 541
13 Station A Diesel Simulation 5.00%$128,445 901
14 Gonzales CEMS 2.50%$64,222 451
15 Emergency Response 2.50%$64,222 451
16 Gonzales Maintenance 0.50%$12,844 90
17 Control Room Display Wall 1.50%$38,533 270
18 PP1 New Building, VFD's electrical, automation 7.00%$179,823 1262
19 Well 19 electrical and VFD Conversion 7.50%$192,667 1352
20 Water Export and Treatment 1.00%$25,689 180
21 Sump Electrical and Control Maint for Public Works 0.50%$12,844 90
22 Technical Consulting 1.00%$25,689 180
23 External Consultants as required 1.50%$38,533 270
24 Materials $300,000 NA
94.20%$2,719,903 16982
Previous Contract Services Terms:
Northwest has not applied or considered a cost-of-living rate adjustment over the past three years despite
substantial inflationary pressures. Our contract has a fixed rate for three years, and like everyone else, we work
through the challenges, as the City also works through the same challenges.
Northwest charged a flat rate, regardless of the skill set involved. Unlike other firms, skillsets and positions such
as Project Management, Senior Engineer, Design Engineer, Commissioning Engineer, Test Engineer, Technician,
Network Design and Security, drafting, etc. have various billable rates. The IEEE published typical rates for
various industries in 2022. A few key rates to consider:
1. Utilities – Median rate $180 / hour nationwide, with a mean rate of $206 / hour.
2. For the Pacific census region, the median rate is $200 / hour.
3. For experience of 35 or more years, the median rate is $193 / hour nationwide.
By comparison, Northwest has combined over 75 years in the utility and process control industries. Moreover,
Northwest does not simply consult, we design and build, which are added costs to consultancy design fees. The
IEEE Survey report for 2022 reports an increase in rates nationally of $10 / hour between 2021 and 2022.
Additionally, BLS reports a 9.7% increase in CPI nationally from November 2021 to the present.
(https://data.bls.gov/pdq/SurveyOutputServlet)
Proposed Contract Services Terms:
Principal Rates
While the survey indicates an increase in rates of $10 / hour just in the past year, and CPI has increased 9.7%
since the start of the last contract, 9.7% would increase our rate to $156.32 / hour. We are pleased to inform
that the proposed rate will remain unchanged at a $142.50 / hour flat rate, which includes all expenses for
both principals (Mark Wray and John Blizman). There will be no additional charges for travel and, as in the
past, never a charge for overtime or phone calls, which we typically answer 24/7.
Additional Staff
If additional staff beyond two persons resident at any time is required, this would be at the cost of $130 / hour +
expenses billed at cost. This would be based on project requirements and must be authorized by the City before
deployment. This represents a 10% change to the previous contract, consistent with the IEEE survey. Since we
cannot control external rates, we need to recognize the increase.
Cost of Living Adjustments
Northwest will maintain the practice of not applying cost of living adjustments (inflation, etc.), with the sole
exception of a major change in CA state tax rates. Should the future political landscape increase tax liability
beyond the current levels, Northwest will review the impact and consult with the City only if the impact
represents a significant cost restructuring.
Insurance
• NW already maintains the insurance levels as currently required by the City. Current Insurance
certificates renewed in March 2023 are on file with the City.
• NW actively retains CA DIR Registration.
Contract Term
• The contract term is three years.
Material Purchases
• Northwest will purchase material as required and only as authorized by the City on a case-by-case basis
with zero markup.
Page 17 of 17
EXHIBIT C
EQUAL EMPLOYMENT OPPORTUNITY
PRACTICES PROVISIONS
A. Contractor certifies and represents that, during the performance of this Agreement, the
contractor and each subcontractor shall adhere to equal opportunity employment practices
to assure that applicants and employees are treated equally and are not discriminated
against because of their race, religious creed, color, national origin, ancestry, handicap,
sex, or age. Contractor further certifies that it will not maintain any segregated facilities.
B. Contractor agrees that it shall, in all solicitations or advertisements for applicants for
employment placed by or on behalf of Contractor, state that it is an "Equal Opportunity
Employer" or that all qualified applicants will receive consideration for employment without
regard to their race, religious creed, color, national origin, ancestry, handicap, sex or age.
C. Contractor agrees that it shall, if requested to do so by the City, certify that it has not, in the
performance of this Agreement, discriminated against applicants or employees because of
their membership in a protected class.
D. Contractor agrees to provide the City with access to, and, if requested to do so by City,
through its awarding authority, provide copies of all of its records pertaining or relating to its
employment practices, except to the extent such records or portions of such records are
confidential or privileged under state or federal law.
E. Nothing contained in this Agreement shall be construed in any manner as to require or
permit any act which is prohibited by law.
City Council Agenda Report
Meeting Date:October 17, 2023
From:Scott Williams, Director of Finance
Department:Finance
Submitted by:Jessica Alcaraz, Financial Services Administrator
Subject
Audited Financial Reports
Recommendation
A. Receive and file the Fiscal Year 2021-22 Annual Financial Statements; and
B. Extend submittal of the Fiscal Year 2022-23 Final Audit and Report to Council to January 16,
2024.
Background
Audits are to be performed in accordance with the standards set forth for the financial audits by
the Governmental Accounting Standards Board (GASB), in the General Accounting Office
(GOA). In addition, Article VIII, Chapter 8.11 of the City Charter requires City Council to appoint
a California certified public accounting firm to provide an independent, annual audit of all City
accounts, including the accounts of all departments, officers and employees who receive, handle
or disburse public funds. The Charter also requires the final audit to be submitted to Council 120
days after the end of the fiscal year.
Following a competitive Request for Proposal (RFP) process, on May 5, 2020 Council awarded
White Nelson Diehl Evans LLP, now CliftonLarsonAllen LLP (CLA), a three-year professional
services agreement for professional auditing services. Fiscal Year (FY) 2021-22 was the last
audit year where CLA was to provide auditing services and production of the audited financial
statements. In the months after the close of the FY 2021-22 financial statements, staff worked
with CLA on providing the requisite information for the firm to initiate and conduct the audit. The
audit process can be lengthy as in addition to verifying and analyzing financial data, the audit
firm also reviews relevant City policies and procedures, and conducts interviews with
management staff and Council. While industry best practice for the completion of an audit is 18
months after a budget is adopted, a combination of circumstances throughout the audit process,
including implementation of a new GASB pronouncement, audit questions pertaining to the
purchase of MGS, and staffing changes/challenges at CLA, resulted in a significant and atypical
delay in the completion of the FY 2021-22 audit. With the audit now complete, staff is submitting
the Fiscal Year 2021-22 Annual Financial Statements to Council as required by the City’s
Charter.
As noted above, Article VIII, Chapter 8.11 of the City Charter requires the final audit to be
submitted to Council within 120 days after the end of the fiscal year. With the City’s fiscal year
ending on June 30, audited financial statements would need to be submitted to Council by late
October 2023. However, 120 days after the end of the fiscal year (June 30) is not feasible as it
can take several months to receive all documents from outside contractors and vendors to accrue
all expenditures related to the prior year, finalize journal entries, reconciliations and for the
auditors to complete their audit and produce the final audited financial reports. Additionally,
industry best practice is 18 months after a budget is adopted, which places finalization of the
audited financials by end of the calendar year and presentation to Council soon after. As such,
staff is seeking an extension for submission of the final audit and report to Council for Fiscal Year
2022-23 Annual Financial Statements to January 16, 2024, anticipated to be the first Council
Meeting of 2024. Staff is currently working with the City’s new audit firm, The Pun Group LLP, on
the FY 2022-23 audit and is confident the audit will be completed in advance of the January 16
date. Pursuant to Article VIII, Chapter 8.11 of the City Charter, the City Council may extend the
deadline for submission of audited financial statements beyond 120 days after the end of the
fiscal year.
Fiscal Impact
There is no fiscal impact associated with this report.
Attachments
1. 2022 Audited City-wide Financial Statements
2. 2022 Audited VPU Financial Statements
3. 2022 Audited Electric Financial Statements
4. 2022 Audited Water Financial Statements
CITY OF VERNON
ANNUAL COMPREHENSIVE FINANCIAL STATEMENTS
AND SUPPLEMENTARY INFORMATION
YEAR ENDED JUNE 30, 2022
CITY OF VERNON
TABLE OF CONTENTS
YEAR ENDED JUNE 30, 2022
INTRODUCTORY SECTION
LETTER OF TRANSMITTAL I
FINANCIAL SECTION
INDEPENDENT AUDITORS’ REPORT 1
MANAGEMENTS’ DISCUSSION AND ANALYSIS (REQUIRED
SUPPLEMENTARY INFORMATION) 4
FINANCIAL STATEMENTS
GOVERNMENT-WIDE FINANCIAL STATEMENTS
STATEMENT OF NET POSITION 17
STATEMENT OF ACTIVITIES 18
FUND FINANCIAL STATEMENTS
BALANCE SHEET – GOVERNMENTAL FUNDS 20
RECONCILIATION TO THE GOVERNMENTAL FUND BALANCE SHEET
TO THE STATEMENT OF NET POSITION – GOVERNMENTAL
ACTIVITIES 21
STATEMENT OF REVENUES, EXPENDITURES, AND CHANGES IN
FUND BALANCE – GOVERNMENTAL FUNDS 22
RECONCILIATION TO THE STATEMENT OF REVENUES,
EXPENDITURES, AND CHANGES IN FUND BALANCE OF
GOVERNMENTAL FUND TO THE STATEMENT OF ACTIVITIES –
GOVERNMENTAL ACTIVITIES 23
STATEMENT OF NET POSITION – PROPRIETARY FUNDS 24
STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN NET
POSITION – PROPRIETARY FUNDS 26
STATEMENT OF CASH FLOWS – PROPRIETARY FUNDS 27
STATEMENT OF FIDUCIARY NET POSITION – FIDUCIARY FUNDS 29
STATEMENT OF CHANGES IN FIDUCIARY NET POSITION –
FIDUCIARY FUNDS 30
NOTES TO FINANCIAL STATEMENTS 31
CITY OF VERNON
TABLE OF CONTENTS
YEAR ENDED JUNE 30, 2022
REQUIRED SUPPLEMENTARY INFORMATION
BUDGETARY COMPARISON SCHEDULE – GENERAL FUNDS 78
NOTE TO REQUIRED SUPPLEMENTARY INFORMATION 79
SCHEDULE OF CHANGES IN THE NET PENSION LIABILITY AND
RELATED RATIOS – MISCELLANEOUS PLAN 80
SCHEDULE OF PENSION CONTRIBUTIONS – MISCELLANEOUS PLAN 83
SCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION
LIABILITY – SAFETY PLAN 85
SCHEDULE OF CHANGES IN THE NET PENSION LIABILITY AND
RELATED RATIOS – SAFETY PLAN 86
SCHEDULE OF PENSION CONTRIBUTIONS – SAFETY PLAN 87
SCHEDULE OF CHANGES IN NET OPEB LIABILITY AND RELATED
RATIOS 89
SCHEDULE OF OPEB CONTRIBUTIONS 91
INTRODUCTORY SECTION
4305 Santa Fe Avenue, Vernon, California
90058 Telephone (323) 583‐8811
(i)
City of Vernon, California
Finance Department
October 2, 2023
To the Honorable Mayor and City Council
Vernon, California
In accordance with the Charter of the City of Vernon (City), please accept submission of the Annual
Financial Report for the fiscal year ended June 30, 2022. Responsibility for the accuracy of the data,
completeness, and fairness of the presentation, including all disclosures, rests with the City. We
believe the data included is accurate in all material aspects and is presented in a manner designed to
fairly set forth the financial position and operational achievements of the City, as measured by the
financial activity of its various funds. In addition, all disclosures necessary to enable the reader to gain a
maximum understanding of the City’s financial activities have been included.
Vernon’s City Charter requires an annual audit of the City’s financial statements by an independent
Certified Public Accountant. Accordingly, this year's audit was completed by CliftonLarsonAllen LLP.
The auditors' report on the basic financial statements is included in the financial section of this report.
Management’s discussion and analysis (MD&A) immediately follows the independent auditors’ report and
provides a narrative introduction, overview, and analysis of the City’s basic financial statements.
MD&A complements this letter of transmittal and, as such, should be read in conjunction.
ECONOMIC CONDITION AND OUTLOOK
Since it was founded in 1905, Vernon has maintained a business-friendly environment, thus allowing the
City to remain one of Southern California's prime locations for industry of all types. Vernon offers
businesses a range of advantages compared to nearby cities in L.A. County. Features such as lower
permit fees; lower electricity, water and natural gas utility rates; excellent City services tailored to specific
business needs; easy access to major transportation hubs; and proximity to a substantially skilled
workforce enable business and industry to thrive in Vernon.
Vernon is the industrial heart of Southern California. Major manufacturers, processors and distributors have
made Vernon their home for more than a century. Vernon currently houses more than 1,800 businesses
that employ approximately 50,000 men and women from nearby communities throughout the Greater Los
Angeles area. These include food and agriculture, apparel, steel, plastics logistics and home
furnishings companies serving as a vital economic engine in the region.
(ii)
Vernon is a key contributor to the diverse Los Angeles County economy. While the California economy
has effectively recovered from the pandemic recession of 2020 with a faster return to normalcy in most
business sectors, the current global and local economies continue to face many of the same challenges of
the prior year and remain prevalent today, Inflation continues to top historical norms, rising interest rates
continue to put pressure on the housing market, car sales and other certain parts of the economy, the risk
of new COVID variants, and the war in Ukraine continue to have a global economic effect. A mix of
economic forecasts believe that the longer inflation persists and the higher the Federal Reserve increases
interest rates in response, the greater the risk to the overall economy.
The City will continue to build on the successes and achievements realized in the current year and
remains committed to serving its customers. The City’s main revenue sources consisting of utilities
fees, property and parcel taxes, business license taxes, and sales and use tax, have all sustained
steady growth this year despite the current financial woes. As the City moves into fiscal year (FY) 2022-
23, we are optimistic about continued growth but applied conservative budgeting principles during the
budget development process for FY 2022-23.
While the budget reflects tempered optimism, the current global and local economies continue to face
new and ongoing challenges that lead us reevaluate spending strategies, The City’s future economic
health will ne dependent on growing and maintaining healthy reserves through fiscally conservative
budgets and polices, planning for economic opportunities, and maintaining its strong financial position
through prudent, long-range policy decisions and sound fiscal management, The City will continue to
monitor key economic indicators, sources of revenue, and spending levels as part of its sound,
conservative fiscal approach.
Additionally, the City continues to make strides in developing its community relationships. With
seasonal community outreach events, it is connecting with Vernon residents and those residents in
neighboring communities in the southeast region. The City has begun circulating a Resident Newsletter
and is also active on its social media platforms, focusing on dissemination of information that is relevant to
the community, ensuring that its population is well-informed on City matters. By forging these
connections with community members, the City is confident that the bi-directional conversations that
result will allow it to better serve the needs of its constituents.
Powering Business Competitiveness
The City of Vernon Public Utilities Department (VPU) serves as an essential resource to the City's
business and residential community, providing high-quality utility services at cost effective rates with the
highest standards of reliability. VPU offers electricity, natural gas, water, and fiber optic services to Vernon
based businesses and residents, often at a cost savings compared to neighboring utility providers. The
City-owned electric, natural gas, water, and fiber optic distribution systems have a strong, established
history of reliability, capable of efficiently and successfully serving the needs of the City's unique largely
industrial community.
The electric utility provides businesses reliable and competitive electrical services. The electric utility has
operated for more than 80 years. Its electrical power and distribution system helps guarantee
uninterrupted electrical service for Vernon's businesses. Electricity costs for large businesses are
comparable and less than power costs from competing utility providers in the Los Angeles region,
depending on the customer type and service being provided.
(iii)
Vernon's natural gas distribution system offers significant advantages for businesses. Vernon's natural
gas transportation rates are less than those offered by a large private natural gas utility in the same
service area. Vernon’s natural gas is distributed through a robust network of more than 44 miles gas
distribution pipelines.
Vernon has 35 miles of fiber optic cable spanning its five-square miles, offering businesses “dark fiber”
and “lit fiber” data services. Vernon's advanced network of fiber optic cable provides businesses new
high-speed methods to virtually connect their buildings and offices to the Internet at lower costs with high
reliability.
Vernon's water utility offers large industrial users water rates that are among the lowest in Southern
California. Vernon maintains reliable water sources to serve a customer base that uses a high volume of
water. Vernon supplies most of the water it sells from City-owned wells and purchases the remaining
water supplies from regional agencies through agreements with the Metropolitan Water District of
Southern California (MWD).
Safeguarding the Environment
Vernon is one of four cities in the State of California with a health department. Vernon's Health and
Environmental Control Department regulates industrial operations conducted in the City. Established in
1908, the Vernon Department of Health & Environmental Control (DHEC) provides comprehensive and
efficient services to accomplish this goal, tailoring its operations to regulate and meet the needs of the
City's large industrial sector.
The DHEC provides Vernon businesses and residents multiple programs to ensure that they are operating
as required by local and State regulations. In addition, the department oversees numerous programs that
cater to the basic needs of the community as a whole.
From food safety, water quality, solid waste, to sustainability, the DHEC functions as a resource hub for
information on regulatory mandates, user-friendly guidance, specialized permitting, and education. These
in-house experts are accessible to businesses and residents alike.
By maintaining its own municipal health authority, the community deals directly with Vernon DHEC officials
to address important environmental and health-related issues, thus enhancing the City’s ability to respond
quickly, especially in critical times like the recent pandemic.
DHEC staff are equipped to efficiently address situations that have the potential to impact the health and
wellness of the community. The team partners with complementary agencies including Los Angeles
County Fire, Los Angeles County Public Health, and Vernon’s own Police Department; and engages third-
party resources when necessary. The DHEC will often be the first on-scene when a hazardous incident is
reported, as the team possesses the expertise to coordinate resources, and can spearhead the
implementation of remedies to ensure that the City is safe haven to live and conduct business.
Vernon manages several special programs and operations to safeguard the public’s health and safety and
protect the City's environment. Among these are the following: Food safety, Food Defense and Consumer
Protection, Water Quality, Land Use, Solid Waste, Liquid Waste, Certified Unified Program Agency (CUPA),
Groundwater and Soil Clean-up and Emergency Preparedness and Disaster Response. Each of these
programs is designed to ensure a safe environment for residents and the business community.
(iv)
Public Works
The City’s Public Works Department is responsible for the Planning, Building and Safety, and maintenance
and construction of the City’s infrastructure. The department includes approximately 40 employees
consisting of engineers, building inspectors, plan checkers, technicians, mechanics and maintenance
personnel.
The engineering section is responsible for administering city contracts and designing public improvements,
such as roadways, storm drains, sewers, traffic signals and City-owned buildings. This section also
maintains plans for city construction projects and prepares legal descriptions for street dedications.
The survey section maintains Vernon’s centerline ties, monuments and benchmarks, providing the basis
from which private property lines are established in the City. It is also responsible for engineering and
inspecting city-run construction projects. Public works crews maintain the City’s streets, sewers, storm
drain systems, traffic islands and City buildings. These crews also provide graffiti and litter removal. The
City garage warehouses supplies and maintains a fleet of more than 300 vehicles and motorized
equipment.
Public Works reviews, inspects and approves all new construction within the public right-of-way, and
cooperates with other departments to review and process all parcel maps, lot line adjustments, lot mergers,
covenants and agreements.
Public Safety
Creating a safe environment for residents and businesses to thrive is a key factor to Vernon’s success. The
City’s skilled Police Department personnel are some of the best in their respective fields. Expeditious
response times and community engagement are hallmarks of their exceptional service.
The mission of the Vernon Police Department (VPD) is to provide swift, skillful, and responsive law
enforcement services to the people and businesses of our community through the application of
proactive problem-solving strategies and the development of equal partnerships with the people
served. Officers seek to ensure a sense of well-being in the community, and they are guided by their
commitment to working closely with the industrial population. VPD is dedicated to maintaining the
highest degree of professionalism and ethical standards in its pursuit of this mission, ever mindful of the
need to safeguard the individual liberties of all members of the community.
VPD responds to emergency calls in less than four minutes. Vernon police officers are specially trained and
outfitted with the latest technology to investigate offenses unique to an industrial community. Using mobile
computer terminals in their patrol cars, officers can query criminal databases from the field and connect
seamlessly with the Department's advanced communications center, which is fully integrated with its
records management and E911 systems. With its specialized units, the VPD maintains an effective
community policing strategy.
Vernon's Police serve as a major emergency response and disaster preparedness resource for the
Greater Los Angeles region. Vernon works closely with L.A. County and municipal public safety
agencies in neighboring cities to offer essential public safety resources and assistance at times of an
emergency through mutual aid agreements. Vernon consistently provides more police and emergency
response mutual aid coverage than that which the City requests through these agreements.
(v)
MAJOR INITIATIVES
Under the direction of the Mayor and City Council, City management identifies the priorities that shape the
path leading into the City’s future. City initiatives are reevaluated regularly, and new goals are frequently
vetted to ensure that City efforts are consistent with the priorities of our policy body and the community. The
City strives each year to better fulfill its mission of delivering outstanding municipal services that are
responsive, comprehensive, and beneficial to the entire community by continuing its tradition of fostering
innovation, ingenuity, and opportunity within its operations. City staff remains focused on actions that
achieve the primary goals of tending to the public’s needs, building neighborhood connections, and
governing for results that strengthen our community. The City’s dedication to improvement and
modernization has created an environment where City of Vernon residents and businesses are dialed in
and able to collaborate with staff, voice their concerns, and have access to a plethora of information on
the City and their chosen topic(s) of interest. As these relationships flourish, businesses and residents
alike are able to enjoy all that Vernon has to offer while also participating in guiding Vernon down its path
into the future.
1. Vernon is very committed to meeting its debt service coverages. In order to address the budget
deficit historically present in the General Fund, the City placed on the ballot a measure to increase the
Utility Users Tax from 1% to 6% which passed in April 2019. The passage of this measure will
effectively eliminate operating transfers from its enterprise activities to the General Fund. To
minimize the burden on the business community, an equivalent discount has been provided to
Vernon’s electric, gas, water, and fiber optics utility customers.
2. Vernon has the capacity to expand its services as new businesses emerge and as existing
businesses flourish and expand. An attractive, business friendly approach is extended to
customers in the form of discounts that are available for large electricity consumers. Revenue sharing
mechanisms have also been implemented to help stimulate both growth and retention. The City’s Good
Governance and Reform initiatives provide a tangible demonstration of the overarching commitment
to sound governance and best business practices.
3. Based upon the City’s electric debt service schedule, there will be a significant reduction in debt
service starting in 2027. With input from business and residential communities, the City continues to
evaluate its position and initiatives to ensure that electric rates remain competitive and that
infrastructure needs are being addressed.
4. The inherent governance challenges in the City, due to a very small residential population,
continues to be addressed by its residents, businesses, Chamber of Commerce, and City Council.
Over the past 5 years, the public has become much more engaged in the political process and
continues to keep a watchful eye on all important issues facing the City. The disincorporation
controversy raised by assembly bill 46 in 2011 has been addressed with the whole-hearted adoption
of key reforms and comprehensive implementation of best practices in all City operations.
5. The State of California Joint Legislative Audit Committee (JLAC) is no longer pursuing the
disincorporation of the City. Vernon has addressed all outstanding JLAC recommendations effective
July 2018. Emphatically committed to good governance and transparency, the City is proud of its
success in satisfying each reform that JLAC recommended. As a result, the City moves forward with
clear, concise, and comprehensive policies and procedures that uphold best practices.
6. The shutdown of the Exide recycled battery plant operation has been and will continue to be under
State of California oversight. The Department of Toxic Substances Control is completely responsible
for monitoring the site and all related cleanup on a continual basis. The State of California has
established funding for the Exide plant cleanup effort collected through a fee on
(vi)
each battery recycled along with any restitution from Exide which remains a global company. There is
no direct impact on City operations and Exide does not pose a concern to existing Vernon businesses.
7. Vernon’s electric rates remain competitive, and in many cases, lower than adjacent municipal and
investor-owned utilities. However, in many respects, Vernon’s electric utility services continue to
outperform its neighboring peers thanks to a higher reliability rating and greater customer
satisfaction. In fact, VPU is a three-time recipient of the RP3 Diamond Level Award, the highest
reliability award from APPA, which reflects our continued investment in utility infrastructure and
commitment to safety and workforce development.
8. Since the purchase of Malburg Generating Station (MGS), Vernon Public Utilities optimizes the
operating profile for operational savings and continued coordination with the CAISO to prevent
statewide rolling blackouts and requests to run MGS when energy is needed most across the electric
grid.
FINANCIAL INFORMATION
Management of the City is responsible for establishing and maintaining internal control designed to
ensure that the assets of the government are protected from loss, theft, or misuse, and to ensure that
adequate accounting data are compiled to allow for the preparation of financial statements in conformity
with U.S. generally accepted accounting principles. Internal control is designed to provide reasonable, but
not absolute, assurance that these objectives are met. The concept of reasonable assurance recognizes
that: (1) the cost of a control should not exceed the benefits likely to be derived; and (2) the valuation of
costs and benefits requires estimates and judgments by management.
This report consists of management’s representations concerning the finances of the City. As a result,
management assumes full responsibility for the completeness and reliability of all of the information
presented in this report. Management asserts that, to the best of their knowledge and belief, this financial
report is complete and reliable in all material respects.
BUDGETARY CONTROLS
The City maintains budgetary controls, the objective of which is to ensure compliance with legal
provisions embodied in the annual appropriated budget approved by the City Council. Activities of all
governmental funds and proprietary funds are included in the annual appropriated budget. The level of
budgetary control (that is, the level at which expenditures cannot legally exceed the appropriated amount)
is established at the departmental level.
RELEVANT FINANCIAL POLICIES
Over the years, through sound fiscal management, the City has positioned itself well to weather
economic downturns, create a positive atmosphere for economic development, and allow flexibility in
addressing budgetary challenges. As of June 30, 2022, the City’s overall total net position was $256.7
million. This consisted of a positive governmental net position of $74.3 million and business-type net
position of $182.4 million. By continuing to develop sound fiscal management plans, the City intends to
maintain an overall positive net position.
ACKNOWLEDGMENTS
The preparation of this report on a timely basis is a team effort involving many dedicated people across the
entire organization. I would like to extend a special thanks to the talented finance professionals
throughout the City, led by Joaquin Leon, Deputy City Treasurer, Jessica Alcaraz, Financial Services
Administrator and Angela Melgar, Finance Manager. Appreciation is also expressed to Carlos Fandino,
City Administrator; Zaynah Moussa, City Attorney; Todd Dusenberry, General Manager of Public Utilities;
Dan wall, Director of Public Works; Robert Sousa, Chief of Police; Freddy Agyin, Director of Health and
Environmental Control; Michael Earl, Human Resource Director; and Lisa Pope, City Clerk.
(vii)
In closing, without the leadership and support of the City Council, the preparation and results presented
within this report would not have been conceivable. Their steadfast leadership has made possible the
implementation of the City’s important, innovative concepts in fiscal management discussed herein.
Should you have any questions regarding the documentation provided, please do not hesitate to contact
me.
Respectfully submitted,
Scott Williams
Director of Finance/City Treasurer
FINANCIAL SECTION
CLA (CliftonLarsonAllen LLP) is an independent network member of CLA Global. See CLAglobal.com/disclaimer.
CliftonLarsonAllen LLP
CLAconnect.com
(1)
INDEPENDENT AUDITORS’ REPORT
Honorable Mayor and
Members of the City Council
City of Vernon
Vernon, California
Report on the Audit of the Financial Statements
We have audited the accompanying financial statements of the governmental activities, the business-
type activities, each major fund, and the aggregate remaining fund information of the City of Vernon,
California (the City), as of and for the year ended June 30, 2022, and the related notes to financial
statements, which collectively comprise the City’s financial statements as listed in the table of contents.
In our opinion, the financial statements referred to above present fairly, in all material respects, the
financial position of the governmental activities, the business-type activities, each major fund, and the
aggregate remaining fund information of the City, as of June 30, 2022, and the changes in financial
position, and, where applicable, cash flows thereof for the year then ended in accordance with
accounting principles generally accepted in the United States of America.
Basis for Opinions
We conducted our audit in accordance with auditing standards generally accepted in the United States
of America (GAAS) and the standards applicable to financial audits contained in Government Auditing
Standards, issued by the Comptroller General of the United States. Our responsibilities under those
standards are further described in the Auditors’ Responsibilities for the Audit of the Financial
Statements section of our report. We are required to be independent of the City and to meet our other
ethical responsibilities, in accordance with the relevant ethical requirements relating to our audit. We
believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our
audit opinions.
Emphasis of Matter
Change in Accounting Principle
As described in Note 1C to the financial statements, effective July 1, 2021, the City adopted new
accounting guidance, Statement of Governmental Accounting Standards Board (GASB Statement) No.
87, Leases. Our opinions are not modified with respect to this matter.
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presentation of the financial statements in
accordance with accounting principles generally accepted in the United States of America, and for the
design, implementation, and maintenance of internal control relevant to the preparation and fair
presentation of financial statements that are free from material misstatement, whether due to fraud or
error.
Honorable Mayor and
Members of the City Council
City of Vernon
(2)
In preparing the financial statements, management is required to evaluate whether there are conditions
or events, considered in the aggregate, that raise substantial doubt about the City of Vernon’s ability to
continue as a going concern for twelve months beyond the financial statement date, including any
currently known information that may raise substantial doubt shortly thereafter.
Auditors’ Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole
are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that
includes our opinions. Reasonable assurance is a high level of assurance but is not absolute assurance
and therefore is not a guarantee that an audit conducted in accordance with GAAS and Government
Auditing Standards will always detect a material misstatement when it exists. The risk of not detecting a
material misstatement resulting from fraud is higher than for one resulting from error, as fraud may
involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
Misstatements are considered material if there is a substantial likelihood that, individually or in the
aggregate, they would influence the judgment made by a reasonable user based on the financial
statements.
In performing an audit in accordance with GAAS and Government Auditing Standards, we:
Exercise professional judgment and maintain professional skepticism throughout the audit.
Identify and assess the risks of material misstatement of the financial statements, whether due
to fraud or error, and design and perform audit procedures responsive to those risks. Such
procedures include examining, on a test basis, evidence regarding the amounts and disclosures
in the financial statements.
Obtain an understanding of internal control relevant to the audit in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the City’s internal control. Accordingly, no such opinion is
expressed.
Evaluate the appropriateness of accounting policies used and the reasonableness of significant
accounting estimates made by management, as well as evaluate the overall presentation of the
financial statements.
Conclude whether, in our judgment, there are conditions or events, considered in the aggregate,
that raise substantial doubt about the City’s ability to continue as a going concern for a
reasonable period of time.
We are required to communicate with those charged with governance regarding, among other matters,
the planned scope and timing of the audit, significant audit findings, and certain internal control related
matters that we identified during the audit.
(3)
Honorable Mayor and
Members of the City Council
City of Vernon
Required Supplementary Information
Accounting principles generally accepted in the United States of America require that the
management’s discussion and analysis, the General Fund budgetary comparison schedule, the
schedules of changes in net pension liability and related ratios and schedules of pension contributions
related to the City’s miscellaneous and safety pension plans, and the schedule of changes in net OPEB
liability and related ratios related to the City’s other postemployment benefits plan, be presented to
supplement the financial statements. Such information is the responsibility of management and,
although not a part of the financial statements, is required by the Governmental Accounting Standards
Board who considers it to be an essential part of financial reporting for placing the financial statements
in an appropriate operational, economic, or historical context. We have applied certain limited
procedures to the required supplementary information in accordance with auditing standards generally
accepted in the United States of America, which consisted of inquiries of management about the
methods of preparing the information and comparing the information for consistency with
management’s responses to our inquiries, the financial statements, and other knowledge we obtained
during our audit of the financial statements. We do not express an opinion or provide any assurance on
the information because the limited procedures do not provide us with sufficient evidence to express an
opinion or provide any assurance.
Other Information
Management is responsible for the other information included in the annual report. The other
information comprises the introductory section but does not include the basic financial statements and
our auditors’ report thereon. Our opinions on the basic financial statements do not cover the other
information, and we do not express an opinion or any form of assurance thereon.
In connection with our audit of the basic financial statements, our responsibility is to read the other
information and consider whether a material inconsistency exists between the other information and the
basic financial statements, or the other information otherwise appears to be materially misstated. If,
based on the work performed, we conclude that an uncorrected material misstatement of the other
information exists, we are required to describe it in our report.
Other Reporting Required by Government Auditing Standards
In accordance with Government Auditing Standards, we have also issued our report
dated October 4, 2023, on our consideration of the City’s internal control over financial reporting
and on our tests of its compliance with certain provisions of laws, regulations, contracts and grant
agreements and other matters. The purpose of that report is solely to describe the scope of our testing
of internal control over financial reporting and compliance and the results of that testing, and not to
provide an opinion on the effectiveness of the City’s internal control over financial reporting or on
compliance. That report is an integral part of an audit performed in accordance with
Government Auditing Standards in considering the City’s internal control over financial reporting
and compliance.
CliftonLarsonAllen LLP
Irvine, California
October 4, 2023
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(4)
As management of the City of Vernon (“the City”), we offer readers of the financial statements this narrative
overview and analysis of the financial activities of the City for the fiscal year ended June 30, 2022.
OVERVIEW OF BASIC FINANCIAL STATEMENTS
This discussion and analysis are intended to serve as an introduction to the City's basic financial statements.
The City's basic financial statements comprise three components: (i) government-wide financial statements,
(ii) fund financial statements, and (iii) notes to the basic financial statements.
Government-wide financial statements
The government-wide financial statements are designed to provide readers with a broad overview of the
City's finances, in a manner similar to a private-sector business.
The statement of net position presents information on all of the City's total assets and deferred outflows of
resources and total liabilities and deferred inflows of resources, with the difference between the two reported
as net position. Over time, increases or decreases in net position may serve as a useful indicator of whether
the financial position of the City is improving or deteriorating.
The statement of activities presents information showing how the City's net position changed during the
most recent fiscal year. All changes in net position are reported as soon as the underlying event giving rise
to the change occurs, regardless of the timing of related cash flows. Thus, revenues and expenses are
reported in this statement for some items that will only result in cash flows in future fiscal periods (e.g.,
uncollected taxes and earned but unused vacation leave).
Both of the government-wide financial statements distinguish functions of the City that are principally
supported by taxes (governmental activities) from other functions that are intended to recover all or a
significant portion of their costs through user fees and charges (business-type activities). The governmental
activities of the City include general government, public safety, public works, and health services. The
business-type activities of the City is administered by the Vernon Public Utilities which consists of the
Electric, Gas, Water, and Fiber Optics utilities.
The government-wide financial statements include not only the City of Vernon (known as the primary
government), but also blended component units. Certain blended component units, although legally
separate entities are, in substance, part of the primary government’s operations and are included as part of
the primary government. Fiduciary funds are not presented in the government-wide financial statements as
the resources are not available to support City programs.
The government-wide financial statements can be found on pages 17-19 of this report.
Fund financial statements
A fund is a grouping of related accounts that is used to maintain control over resources that have been
segregated for specific activities or objectives. The City, like other state and local governments, uses fund
accounting to ensure and demonstrate compliance with finance-related legal requirements. All of the funds
of the City can be divided into three categories: governmental funds, proprietary funds, and fiduciary funds.
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(5)
Governmental funds
Governmental funds are used to account for essentially the same functions reported as governmental
activities in the government-wide financial statements. However, unlike the government-wide financial
statements, governmental fund financial statements focus on near-term inflows and outflows of spendable
resources, as well as on balances of spendable resources available at the end of the fiscal year. Such
information may be useful in evaluating a government's near-term financing requirements.
Because the focus of governmental funds is narrower than that of the government-wide financial statements,
it is useful to compare the information presented for governmental funds with similar information presented
for governmental activities in the government-wide financial statements. By doing so, readers may better
understand the long-term impact of the government's near-term financing decisions. Both the governmental
funds balance sheet and the governmental funds statement of revenues, expenditures, and changes in fund
balances provide a reconciliation to facilitate this comparison between governmental funds and
governmental activities.
The City adopts an annual appropriated budget for its General Fund. A budgetary comparison schedule has
been provided for the General Fund (see page 74).
The basic governmental funds financial statements can be found on pages 20-23 of this report.
Proprietary funds
The City’s proprietary funds consist of enterprise funds. Enterprise funds are used to report the same
functions presented as business-type activities in the government-wide financial statements. The City uses
enterprise funds to account for its Vernon Public Utilities which consists of the Electric, Gas, Water, and
Fiber Optics utilities.
Proprietary funds provide the same type of information as the government-wide financial statements, only in
more detail. The proprietary fund financial statements provide separate information for the Vernon Public
Utilities.
The basic proprietary funds financial statements can be found on pages 24-28 of this report.
Fiduciary funds
Fiduciary funds are used to account for resources held for the benefit of parties outside of the government.
Fiduciary funds are not reflected in the government-wide financial statements because the resources of
those funds are not available to support City programs. The accounting used for fiduciary funds is much like
that used for proprietary funds.
The basic fiduciary funds financial statements can be found on pages 29-30 of this report.
Notes to the basic financial statements
The notes provide additional information that is essential to a full understanding of the data provided in the
government-wide and fund financial statements. The notes to the financial statements can be found on
pages 31-75 of this report.
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(6)
GOVERNMENT-WIDE FINANCIAL ANALYSIS
City’s Net Position
The table below summarizes the City’s net position as of June 30, 2022 and June 30, 2021. The details
of the current year’s summary can be found on page 17 of this report.
City of Vernon
Net Position
June 30, 2022 and 2021
2022 2021 2022 2021 2022 2021
Assets:
Current and other assets 31,543,883$ 15,676,741$ 190,425,409$ 174,666,191$ 221,969,292$ 190,342,932$
Restricted assets 6,267,964 5,070,045 46,383,084 56,392,885 52,651,048 61,462,930
Capital assets 163,093,528 165,326,345 458,427,644 257,253,484 621,521,172 422,579,829
Total assets 200,905,375 186,073,131 695,236,137 488,312,560 896,141,512 674,385,691
Deferred Outflows of Resources
Deferred outflows related to pensions 23,034,461 23,952,913 5,338,797 4,901,360 28,373,258 28,854,273
Deferred outflows related to OPEB liability 2,856,840 3,326,931 662,143 680,773 3,518,983 4,007,704
Deferred amount on bond refunding ‐ ‐ 1,933,345 292,472 1,933,345 292,472
Total deferred outflows of resources 25,891,301 27,279,844 7,934,285 5,874,605 33,825,586 33,154,449
Liabilities:
Current liabilities 4,494,931 3,779,531 23,591,507 21,910,613 28,086,438 25,690,144
Long term liabilities 92,405,587 135,010,934 485,156,669 316,254,536 577,562,256 451,265,470
Total liabilities 96,900,518 138,790,465 508,748,176 338,165,149 605,648,694 476,955,614
Deferred Inflows of Resources
Deferred inflows related to pensions 44,972,489 2,754,345 10,423,470 563,607 55,395,959 3,317,952
Deferred inflows related to OPEB liability 6,807,966 7,315,776 1,577,912 1,496,988 8,385,878 8,812,764
Deferred inflows related to Leases 3,803,114 ‐ ‐ ‐ 3,803,114 ‐
Deferred gain from sale of generation assets ‐ ‐ ‐ 6,555,916 ‐ 6,555,916
Total deferred outflows of resources 55,583,569 10,070,121 12,001,382 8,616,511 67,584,951 18,686,632
Net Position:
Net investment in capital assets 162,746,593 165,326,345 168,787,837 148,442,763 331,534,430 313,769,108
Restricted 4,422,510 4,146,007 32,836,544 23,894,665 37,259,054 28,040,672
Unrestricted (deficit)(92,856,514) (104,979,963) (19,203,517) (24,931,923) (112,060,031) (129,911,886)
Total net position 74,312,589$ 64,492,389$ 182,420,864$ 147,405,505$ 256,733,453$ 211,897,894$
Governmental Activities Business‐type Activities Totals
The assets and deferred outflows of resources of the City exceeded its liabilities and deferred inflows of
resources at the close of the most recent fiscal year by $256,733,453 (net position).
The category of the City’s net position with the largest balance totaling $331,534,430 represents
resources that are invested in capital assets, net of the related debt.
The second-largest category of net position, totaling $37,259,054 represents the City’s restricted assets,
which are restricted for employee flexible spending account, grants and debt service.
The last remaining category of net position, totaling ($112,060,031) represents a deficit in unrestricted
net position that is expected to be recovered from the City’s future revenues.
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(7)
Governmental activities, net position:
Current and other assets increased by $15,867,142 from the prior year due to increase in cash and
cash equivalents of $3,566,960, accounts receivable of $1,773,892, taxes receivable of $1,630,903,
internal balances of $4,881,456 and lease receivable of $3,836,304 through the implementation of
GASB Statement No. 87.
Restricted assets increased by $1,197,919 from the prior year mainly due to an increase in
restricted cash and investments balance for streets improvements.
Capital assets decreased by $2,232,817 from the prior year mainly due to depreciation of
$4,991,029 offset by the acquisition of machinery and equipment and infrastructure and building
upgrades and improvements as well as the liquidation & disposal of City department’s assets.
Deferred outflows of resources for pension costs decreased by $918,452 from the prior year
mainly due to a change in current year’s contribution to the pension that will be applied as a
reduction in net pension liability in the next fiscal year, or other items arising from changes in
actuarial assumptions, difference between actual and projected experiences, difference between
actual and projected investment gains/losses, or changes in a fund’s proportionate share of the net
pension liability.
Deferred outflows of resources for other postemployment benefits (OPEB) decreased by $470,091
from the prior year due a change in current year contribution to the OPEB plan that will be applied as
a reduction in net OPEB liability in the next fiscal year, or other items arising from changes in
actuarial assumptions, difference between actual and projected experiences, difference between
actual and projected investment gains/losses, or changes in a fund’s proportionate share of the net
OPEB liability.
Current liabilities increased by $715,400 from the prior year mainly due to an increase in accounts
payable of $1,718,829 offset by a decrease in accrued wages and benefits of $825,446 and
unearned revenue of $216,467.
Long-term liabilities decreased by $42,605,347 from the prior year mainly due to decrease in net
pension liability and other postemployment benefits liability of $40,851,219 and $3,485,823,
respectively, offset by an increase in liabilities due in more than 1 year of $1,291,165.
Deferred inflows of resources for pension actuarial increased by $42,218,144 from the prior year
due to changes in total pension liability that are to be recognized as an increase in pension
expenses in future fiscal years. These balances arise from changes in actuarial assumptions, the
difference between actual and projected experiences, the difference between actual and projected
investment gains/losses, or changes in the fund’s proportionate share of the plan’s net pension
liability.
Deferred inflows of resources for OPEB decreased by $507,810 from the prior year mainly due to
changes in actuarial assumptions and the difference between actual and expected experience.
Deferred inflows of resources for leases increased by $3,803,114 due to the implementation of
GASB Statement No. 87.
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(8)
Governmental activities, net position (continued):
Net investment in capital assets decreased by $2,579,679 from the prior year which is equivalent to
the decrease in capital assets, net of finance purchase obligations during the current year.
Restricted net position increased by $276,503 from the prior year mainly due to a decrease in the
restricted designation placed on street improvement account and SCWP account.
The unrestricted net deficit decreased by $10,456,738 from the prior year mainly due to the current
year’s change in net position of $8,153,489 offset by a decrease in net investment in capital assets
of $2,579,679.
Business-type activities, net position:
Current and other assets increased $15,759,218 from the prior year mainly due to an increase in
cash and cash equivalents of $10,600,320 and in receivables of $9,212,592 offset by a decrease in
internal balances of $4,881,456.
Restricted assets decreased by $10,009,801 from the prior year mainly due to the drawdowns
funding the capital improvement projects.
Capital assets increased $201,174,160 from the prior year mainly due to acquisitions of the Malburg
Generation Station (MGS), and new equipment and facility improvements, offset by depreciation of
$17,904,210 and net capital asset disposals of $2,315,926 (See Note 5).
Deferred outflows of resources increased by $2,059,680 due to the decrease in amount on bond
refunding of $1,640,873 and in deferred pensions of $437,437.
Current liabilities increased $1,680,894 mainly due to an increase in accounts payable of
$3,393,468 offset by a decrease in bond interest payable $1,498,676.
Long-term liabilities increased by $168,902,133 from the prior year mainly due to bonds payable
increase with newly issued bonds related to MGS acquisition (see Note 6).
Deferred inflows of resources increased by $3,384,871 mainly due to the increase related to
pensions of $9,859,863 offset by the amortization of the remaining deferred gain from sale of
generation assets of $6,555,916 as a result of the purchase of MGS.
Net investment in capital assets decreased by $11,290,729 from the prior year, which is attributable
to the increase in capital assets, net of capital bonds payable.
The VPU’s total net position at fiscal year 2021-22 was $182,420,864, which increased by
$35,015,359 from the prior year due to an increase in the net investment in capital assets by
$20,345,074, an increase in the funds restricted for debt service of $8,941,879 and a decrease of
the unrestricted (deficit) of $5,728,406.
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(9)
Changes in Net Position
The table below summarizes the City’s changes in net position between the current and prior fiscal
year. The details of the current year’s changes in net position can be found on pages 18-19 of this
report.
City of Vernon
Statement of Activities
Years ended June 30, 2022 and 2021
2022 2021 2022 2021 2022 2021
Revenues:
Program revenues
Charges for services 5,912,509$ 6,470,901$ 5,912,509$ 6,470,901$
Vernon public utilities 238,570,758 212,205,129 238,570,758 212,205,129
Operating and capital grants and contributions 5,262,389 2,103,424 865,403 6,127,792 2,103,424
General revenues
Taxes 41,888,435 39,163,804 41,888,435 39,163,804
State allocations 14,989,046 14,445,575 14,989,046 14,445,575
Investment income (loss)208,039 70,480 285,622 69,606 493,661 140,086
Gain (loss) on the sale of land and assets ‐ ‐ ‐ ‐ ‐ ‐
Other revenues 2,736,631 2,531,566 ‐ ‐ 2,736,631 2,531,566
Total revenues 70,997,049 64,785,750 239,721,783 212,274,735 310,718,832 277,060,485
Expenses:
Governmental activities
General government 17,564,758 15,238,548 ‐ ‐ 17,564,758 15,238,548
Public safety 35,417,532 33,919,854 ‐ ‐ 35,417,532 33,919,854
Public works 11,811,876 10,468,302 ‐ ‐ 11,811,876 10,468,302
Health services 1,416,058 1,280,046 ‐ ‐ 1,416,058 1,280,046
Interest on long‐term debt 199 67,707 ‐ ‐ 199 67,707
Business‐type activities
Vernon public utilities 199,672,850 203,474,562 199,672,850 203,474,562
Total expenses 66,210,423 60,974,457 199,672,850 203,474,562 265,883,273 264,449,019
Change in net position before transfers 4,786,626 3,811,293 40,048,933 8,800,173 44,835,559 12,611,466
Transfers:
Interfund transfers 5,033,574 4,781,720 (5,033,574) (4,781,720) ‐ ‐
Net Transfers 5,033,574 4,781,720 (5,033,574) (4,781,720) ‐ ‐
Change in net position 9,820,200 8,593,013 35,015,359 4,018,453 44,835,559 12,611,466
Net position ‐ beginning of year 64,492,389 55,899,376 147,405,505 143,387,052 211,897,894 199,286,428
Net position ‐ end of year 74,312,589$ 64,492,389$ 182,420,864$ 147,405,505$ 256,733,453$ 211,897,894$
Business‐type ActivitiesGovernmental Activities Totals
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(10)
Governmental activities, changes in net position:
Governmental activities’ net position increased by $9,820,200 and business-type activities’ net
position increased by $35,015,359 for a net increase of $44,835,559 for the City.
Governmental activities consist of the following departments:
GENERAL GOVERNMENT PUBLIC SAFETY PUBLIC WORKS HEALTH SERVICES
CITY COUNCIL POLICE ADMIN‐ENGINEERING‐PLANNING HEALTH
CITY ADMINISTRATION BUILDING REGULATIONS
INFORMATION TECHNOLOGY CITY HOUSING
CITY ATTORNEY FACILITIES MAINTENANCE
HUMAN RESOURCES FLEET SERVICES
CITY CLERK STREET LIGHTING
FINANCE STREET MAINTENANCE
COMMUNITY PROMOTION WAREHOUSE
INDUSTRIAL DEVELOPMENT
COMMUNITY DEVELOPMENT
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(11)
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(12)
Business-type activities, changes in net position:
Business-type activities increased the City's net position by $35,015,359 before transfers which is a
$30,996,906 decrease from the prior year. The key reason for this increase was due to the significant
increase in operating income of $27,102,304 and lower interest expense of $5,134,307 offset by the
loss on the disposition of assets of $2,315,926.
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(13)
FINANCIAL ANALYSIS OF THE GOVERNMENTAL FUNDS
As noted earlier, the City uses fund accounting to ensure and demonstrate compliance with finance-
related legal requirements.
Governmental funds
The focus of the City's governmental funds is to provide information on near-term inflows, outflows, and
balances of spendable resources. Such information is useful in assessing the City's financing
requirements. In particular, the nonspendable, restricted, committed, assigned, and unassigned fund
balances may serve as a useful measure of a government's net resources available for spending at the
end of the fiscal year.
At the end of the current fiscal year, the City's governmental funds reported a combined ending fund
balances of $27,847,091 (see page 20), an increase of $10,879,836 from the prior year. Approximately
0.61% of the total fund balance amount, $168,491, constitutes nonspendable fund balance, which are
amounts that are not in a spendable form or are required to be maintained intact. Approximately
15.88% of the total fund balance amount, $4,442,510, constitutes restricted fund balance, which are
amounts that can be spent only for specific purposes stipulated by external resource providers,
constitutionally, or through enabling legislation. The remainder of the fund balance amount,
$23,256,090 is an unassigned fund balance deficit to indicate that it is the residual classification that is
not contained in the other classifications.
The General Fund is the operating fund of the City. At the end of the current fiscal year, the total fund
balance was $27,847,091 (see page 22). At the end of the current fiscal year, the total fund balance
represents 43.9% of the total expenditures for the year.
Proprietary funds
The City's proprietary funds provide the same type of information found in the government-wide
financial statements but in more detail.
Unrestricted net position for the Vernon Public Utilities at the end of the year amounted to a deficit
balance of $19,203,517 (see page 25). This deficit balance in unrestricted net position is primarily due
to the proprietary funds being heavily invested in capital assets for which it has not yet recovered the
cost of capital invested. The proprietary funds expect to eliminate these deficit balances through
increased future revenues.
The total increase in net position for the Vernon Public Utilities was $35,015,359 (see page 26). Other
factors concerning the finances of these funds have already been addressed in the discussion of the
City's business-type activities.
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(14)
GENERAL FUND AND BUDGETARY HIGHLIGHTS
For the current year, the General Fund’s total positive variance between the final budgeted amounts
and the actual amount of change in fund balance was $11,450,180. The key reasons for this variance
were due to lower actual revenues than projected of $1,615,795 and lower actual expenditures than
appropriated by $13,155,975.
For the current year, the General Fund’s total positive variance between the final budgeted estimated
revenues and actual revenues was $1,615,795. The main reason for the variance, was that taxes came
in higher than expected by $2,621,650 and $8,935,173 respectively offset by intergovernmental
revenues coming in lower by $5,534,510.
For the current year, the General Fund’s total positive variance between the final budgeted amount and
the actual amount for expenditures was $13,155,975. The key reasons for this variance were due to
higher appropriations than actual expenditures of $9,440,279 in capital outlay and $2,192,186 in public
works.
CAPITAL ASSET AND DEBT ADMINISTRATION
Capital assets
The City's investment in capital assets for its governmental and business-type activities as of June 30,
2022, amounts to $621,521,172 (net of accumulated depreciation). This investment in capital assets
includes land, construction in progress, building, utility system improvements, machinery and
equipment, infrastructure such as roads, and intangible assets such as environmental emission credits.
The increase in capital assets of $198,941,343 is mainly due to the purchase of Malburg Generation
Station. Additionally, capital assets was updated for the implementation of GASB Statement No. 87,
Leases, for right-to-use- lease assets.
Additional information on the City's capital assets can be found in Note 5 of this report.
Outstanding debt
As of June 30, 2022, the following debt remains outstanding:
$37,895,000 City of Vernon Electric System Revenue Bonds, 2008 Taxable Series A
$11,505,000 City of Vernon Electric System Revenue Bonds, 2012 Taxable Series B
$111,720,000 City of Vernon Electric System Revenue Bonds, 2015 Taxable Series A
$19,305,000 City of Vernon Electric System Revenue Bonds, 2020 Series A
$173,815,000 City of Vernon Electric System Revenue Bonds, 2021 Taxable Series A
$52,070,000 City of Vernon Electric System Revenue Bonds, 2022 Taxable Series A
$14,600,000 City of Vernon Water System Revenue Bonds, 2020 Taxable Series A
$1,220,930 City of Vernon agreement with the Water Replenishment District of Southern
California
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(15)
The City of Vernon Electric System Revenue Bonds, 2008 Taxable Series A were issued to provide
funds to (i) finance the cost of certain capital improvements to the City’s Electric System, (ii) fund a
deposit to the Debt Service Reserve Fund, and (iii) to pay costs of issuance of the 2008 Bonds.
The City of Vernon Electric System Revenue Bonds, 2012 Taxable Series B were issued to provide
funds to (i) refund the $28,680,000 aggregate principal amount of 2009 Bonds maturing on August 1,
2012, (ii) to pay a portion of the Costs of the 2012 Project, and (iii) to pay costs of issuance of the 2012
Taxable Series B Bonds.
The City of Vernon Electric System Revenue Bonds, 2015 Taxable Series A were issued to provide
funds to (i) refund a portion of the Outstanding Electric System Revenue Bonds, 2009 Series A; (ii)
finance the costs of certain capital improvements to the City’s Electric System by reimbursing the
Electric System for the prior payment of such costs from the Light and Power Fund; (iii) fund a deposit
to the Debt Service Reserve Fund; and (iv) pay costs of issuance of the 2015 Bonds.
The City of Vernon Electric System Revenue Bonds, 2020 Series A were issued to provide funds to
(i) finance the acquisition and construction of certain capital improvements to the Electric System of the
City, (ii) to refund all of the City’s outstanding Electric System Revenue Bonds, 2009 Series A, and (iii)
to pay costs of issuance of the 2020 Bonds.
The City of Vernon Electric System Revenue Bonds, 2021 Series A were issued to provide funds: (i)
to pay the costs of the acquisition by the City of Vernon of a 134-megawatt natural gas-fired
generating facility located within the city limits on land owned by the City, together with certain related
electrical interconnection facilities and other assets, property, and contractual rights, (ii) to fund a
deposit to the Debt Service Reserve Fund in satisfaction of the Debt Service Reserve Requirement,
and (iii) to pay costs of issuance of the 2021 Bonds.
The City of Vernon Electric System Revenue Bonds, 2022 Series A were issued to (i) refund and
defease all the City’s outstanding Electric System Revenue Bonds, 2012 Series A and a portion of the
City’s outstanding Electric System Revenue Bonds, 2012 Taxable Series B and (ii) to pay costs of
issuance of the 2022 Bonds.
The City of Vernon Water System Revenue Bonds, 2020 Series A were issued to provide funds to
(i) finance the acquisition and construction of certain capital improvements to the Water System of the
City, (ii) purchase a municipal bond debt service reserve insurance policy for deposit in the Reserve
Fund in satisfaction of the Reserve Requirement, and (iii) to pay costs of issuance of the 2020 Bonds.
As of June 30, 2022, the ratings on all Electric System Revenue Bonds of the City changed from the
prior year to BBB+/Stable by S&P and Baa1/Stable by Moody’s and the ratings on all Water Revenue
Bonds is A-/Stable by S&P and not rated by Moody’s.
Additional information on the City's long-term debt can be found in Note 6 of this report.
CITY OF VERNON
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(16)
ECONOMIC FACTORS AND NEW YEAR’S BUDGET AND RATES
Local and state economies experienced continual growth throughout fiscal year 2021-22, with tapering
in the latter months due to prolonged historical high inflation and the increased interest rates by the
Federal Reserve. Cities continue to be challenged in forecasting the economy and preparing the budget
for the next fiscal year. The City has been fortunate in its specific mix of businesses, which has proven
to be resilient in response to volatile economic changes. These factors were considered in preparing
the City and VPU’s budget for fiscal year 2022-23.
The City developed a conservative spending plan addressing City Council and community
priorities while focusing on operations at full capacity, deferring maintenance and operational
needs while still focused on delivering quality core municipal services.
VPU continues to respond to inflation and supply chain issues, including higher energy,
natural gas, materials and supplies, chemicals, and construction costs to maintain generation,
transmission, and distribution infrastructure to continue to provide exceptionally reliable
service.
Continue to implement VPU’s capital plan, manage operating and maintenance expenses,
update the 2018 Integrated Resource Plan, complete an Electric Cost of Service Analysis and
Rate Design study, transition customer load growth to green commerce, optimize the MGS
operating profile, and continue to implement the multi-year water rate adjustment plan
approved by City Council.
REQUESTS FOR INFORMATION
This financial report is designed to provide a general overview of the City's finances for all those with
an interest in the City's finances. Questions concerning any of the information provided in this report
or requests for additional financial information should be addressed to the Director of Finance,
swilliams@cityofvernon.org, City of Vernon, 4305 Santa Fe Avenue, Vernon, California, 90058.
CITY OF VERNON
STATEMENT OF NET POSITION
JUNE 30, 2022
See accompanying Notes to Financial Statements.
(17)
Governmental Business-Type
Activities Activities Total
ASSETS
Cash and Cash Equivalents 17,973,383$ 156,960,639$ 174,934,022$
Accounts Receivable, Net of Allowance 1,783,820 14,262,338 16,046,158
Taxes Receivable 4,947,687 - 4,947,687
Lease Receivable - Current Portion 66,705 - 66,705
Lease Receivable 3,769,599 - 3,769,599
Notes and Loans Receivable 8,816 - 8,816
Other Receivables 61,919 - 61,919
Accrued Unbilled Revenue - 19,025,964 19,025,964
Accrued Interest Receivable - 89,197 89,197
Internal Balances 2,763,463 (2,763,463) -
Prepaid Natural Gas - 636,909 636,909
Prepaid Expenses 168,491 1,012,402 1,180,893
Deposits - 1,201,423 1,201,423
Restricted Cash and Investments 6,267,964 46,383,084 52,651,048
Capital Assets:
Nondepreciable 65,801,086 70,803,890 136,604,976
Depreciable, Net 97,292,442 387,623,754 484,916,196
Total Assets 200,905,375 695,236,137 896,141,512
DEFERRED OUTFLOWS OF RESOURCES
Deferred Outflows Related to Pensions 23,034,461 5,338,797 28,373,258
Deferred Outflows Related to OPEB Liability 2,856,840 662,143 3,518,983
Deferred Amount on Bond Refunding - 1,933,345 1,933,345
Total Deferred Outflows of Resources 25,891,301 7,934,285 33,825,586
LIABILITIES
Accounts Payable 2,828,577 17,472,509 20,301,086
Accrued Wages and Benefits 613,476 406,604 1,020,080
Customer Deposits 239,139 500,168 739,307
Bond Interest Payable - 5,212,226 5,212,226
Unearned Revenue 813,739 - 813,739
Noncurrent Liabilities:
Due Within One Year 2,563,534 50,905,670 53,469,204
Due in More than One Year 5,082,788 414,605,974 419,688,762
Net Other Postemployment Benefit Liability 13,292,721 3,080,913 16,373,634
Net Pension Liability 71,466,544 16,564,112 88,030,656
Total Liabilities 96,900,518 508,748,176 605,648,694
DEFERRED INFLOWS OF RESOURCES
Deferred Inflows Related to Pensions 44,972,489 10,423,470 55,395,959
Deferred Inflows Related to OPEB Liability 6,807,966 1,577,912 8,385,878
Deferred Inflows Related to Leases 3,803,114 - 3,803,114
Total Deferred Inflows of Resources 55,583,569 12,001,382 67,584,951
NET POSITION
Net Investment in Capital Assets 162,746,593 168,787,837 331,534,430
Restricted for:
Employee Flexible Spending Account 25,261 - 25,261
Street Improvements 3,855,244 - 3,855,244
Asset Forfeiture Funds 542,005 - 542,005
Debt Service - 32,836,544 32,836,544
Unrestricted (Deficit) (92,856,514) (19,203,517) (112,060,031)
Total Net Position 74,312,589$ 182,420,864$ 256,733,453$
CITY OF VERNON
STATEMENT OF ACTIVITIES
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Financial Statements.
(18)
Program Revenues
Charges Operating Capital
for Grants and Grants and
Function/Program Activities Expenses Services Contributions Contributions
PRIMARY GOVERNMENT
Governmental Activities:
General Government 17,564,758$ 8,525,489$ 2,273$ -$
Public Safety 35,417,532 229,726 1,862,043 -
Public Works 11,811,876 1,564,854 5,616 3,392,457
Health Services 1,416,058 626,014 --
Interest on Long Term Liabilities 199 - --
Total Governmental Activities 66,210,423 10,946,083 1,869,932 3,392,457
Business-Type Activities:
Electric 176,601,293 208,539,519 665,887 -
Gas 18,478,619 18,705,573 5,029 -
Water 9,217,802 10,845,652 194,487 -
Fiber Optics 408,710 480,014 --
Total Business-Type Activities 204,706,424 238,570,758 865,403 -
Total Primary Government 270,916,847$ 249,516,841$ 2,735,335$ 3,392,457$
CITY OF VERNON
STATEMENT OF ACTIVITIES (CONTINUED)
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Financial Statements.
(19)
Function/Program Activities
PRIMARY GOVERNMENT
Governmental Activities:
General Government
Public Safety
Public Works
Health Services
Interest on Long Term Liabilities
Total Governmental Activities
Business-Type Activities:
Electric
Gas
Water
Fiber Optics
Total Business-Type Activities
Total Primary Government
General Revenues:
Property Taxes
Parcel Taxes
Utility Users Taxes
Franchise Taxes
Business License Taxes
Other Taxes
Investment Income
Rental income
State Contribution - Sales and
Use Taxes
Other Revenues
Total General Revenues
CHANGE IN NET POSITION
Net Position - Beginning of Year
NET POSITION - END OF YEAR
Net (Expenses) Revenues and
Change in Net Position
Governmental Business-Type
Activities Activities Total
(9,036,996)$ -$ (9,036,996)$
(33,325,763) - (33,325,763)
(6,848,949) -(6,848,949)
(790,044) -(790,044)
(199) -(199)
(50,001,951) - (50,001,951)
-32,604,113 32,604,113
-231,983 231,983
-1,822,337 1,822,337
-71,304 71,304
-34,729,737 34,729,737
(50,001,951) 34,729,737 (15,272,214)
4,982,723 -4,982,723
15,214,692 - 15,214,692
13,826,831 - 13,826,831
1,821,409 -1,821,409
5,929,166 -5,929,166
12,805 - 12,805
100,809 285,622 386,431
208,039 -208,039
14,989,046 - 14,989,046
2,736,631 -2,736,631
59,822,151 285,622 60,107,773
9,820,200 35,015,359 44,835,559
64,492,389 147,405,505 211,897,894
74,312,589$ 182,420,864$ 256,733,453$
CITY OF VERNON
BALANCE SHEET – GOVERNMENTAL FUND
JUNE 30, 2022
See accompanying Notes to Financial Statements.
(20)
General
Fund
ASSETS
Cash and Cash Equivalents 17,973,383$
Accounts Receivable, Net of Allowance 1,783,820
Taxes Receivable 4,947,687
Lease Receivable - Current Portion 66,705
Lease Receivable 3,769,599
Notes and Loans Receivable 8,816
Other Receivables 61,919
Due from Other Funds 2,966,261
Prepaid Items 168,491
Restricted Cash and Investments 6,267,964
Total Assets 38,014,645$
LIABILITIES AND FUND BALANCE
LIABILITIES
Accounts Payable 2,828,577$
Accrued Wages and Benefits 613,476
Unearned Revenue 813,739
Customer Deposits 239,139
Advances from Other Funds 202,798
Total Liabilities 4,697,729
DEFERRED INFLOWS OF RESOURCES
Deferred Inflows - Unavailable Revenues 1,666,711
Deferred Inflows Related to Leases 3,803,114
Total Deferred Inflows of Resources 5,469,825
FUND BALANCE
Nonspendable:
Prepaid Items 168,491
Restricted for:
Employee Flexible Spending Account 25,261
Street Improvements 3,855,244
Asset Forfeiture Funds 542,005
Unassigned 23,256,090
Total Fund Balance 27,847,091
Total Liabilities and Fund Balance 38,014,645$
CITY OF VERNON
RECONCILIATION TO THE GOVERNMENTAL FUND BALANCE SHEET
TO THE STATEMENT OF NET POSITION – GOVERNMENTAL ACTIVITIES
JUNE 30, 2022
See accompanying Notes to Financial Statements.
(21)
Fund Balance - Governmental Fund 27,847,091$
Amounts reported for governmental activities in the Statement of Net Position
are different because:
Receivables not available to pay for current period expenditures are reported as
unavailable revenue in the financial statements. 1,666,711
Capital assets used in governmental activities are not financial resources
and therefore are not reported in the governmental fund 163,061,941
Right to Use assets used in governmental activities are not current
financial resources and therefore are not reported in the funds. Related
long-term lease liabilities are not due and payable in the current period;
therefore, they are not reported in the funds. These items consist of:
Right to Use Assets, Net of Accumulated Amortization 31,587
Lease Liability (31,660)
Long-term liabilities are not due and payable in the current period and
therefore are not reported in the governmental fund
Compensated Absences (2,673,930)
Claims Payable (4,940,732)
Net pension and other postemployment benefit (OPEB) liabilities applicable to
the City's governmental activities are not due and payable in the current period
and therefore are not reported in the governmental fund. Deferred outflows and
inflows of resources related to the pension and OPEB liabilities applicable to the
City's governmental activities are only reported in the government-wide financial
statements
Deferred Outflows of Resources for Pensions 23,034,461
Deferred Outflows of Resources for OPEB 2,856,840
Deferred Inflows of Resources for Pensions (44,972,489)
Deferred Inflows of Resources for OPEB (6,807,966)
Net Pension Liability (71,466,544)
Net OPEB Liability (13,292,721)
Net Position of Governmental Activities 74,312,589$
CITY OF VERNON
STATEMENT OF REVENUES, EXPENDITURES, AND CHANGES
IN FUND BALANCE – GOVERNMENTAL FUND
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Financial Statements.
(22)
General
Fund
REVENUES
Taxes 56,686,792$
Special Assessments 1,704,159
Licenses and Permits 2,158,284
Fines, Forfeitures, and Penalties 258,268
Investment Income 100,809
Intergovernmental Revenues 1,789,300
Charges for Services 10,276,400
Rental Income 513,701
Other Revenues 876,199
Total Revenues 74,363,912
EXPENDITURES
Current:
General Government 17,085,390
Public Safety 34,345,479
Public Works 7,688,016
Health Services 1,411,874
Capital Outlay 2,927,921
Debt Service:
Principal 25,197
Interest 199
Total Expenditures 63,484,076
CHANGE IN FUND BALANCE 10,879,836
Fund Balance - Beginning of Year 16,967,255
FUND BALANCE - END OF YEAR 27,847,091$
CITY OF VERNON
RECONCILIATION OF THE STATEMENT OF REVENUES, EXPENDITURES,
AND CHANGES IN FUND BALANCE OF GOVERNMENTAL FUND TO
THE STATEMENT OF ACTIVITIES – GOVERNMENTAL ACTIVITIES
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Financial Statements.
(23)
Net Change in Fund Balance - Total Governmental Fund 10,879,836$
Amounts reported for governmental activities in the Statement of
Activities are different because:
Revenues in the Statement of Activities that do not provide current financial
resources are not reported as revenues in the funds 1,666,711
Governmental funds report capital outlays as expenditures. However,
in the Statement of Activities, the costs of those assets are allocated
over their estimated useful lives as a depreciation expense. As a
result, fund balances decrease by the amount of financial resources
expended, whereas net position decreases by the amount of
depreciation expense charged for the year.
Capital Outlay 3,291,130
Depreciation and Amortization Expense (5,016,299)
Loss on Disposal of Capital Assets (564,505)
Principal payment of long term liabilities uses current financial
resources but is not reported in the Statement of Activities
Principal Payments Lease Liability 25,197
Some expenses reported in the Statement of Activities do not
require the use of current financial resources and therefore are
not reported as expenditures in the governmental fund:
Change in Net Pension Liability 40,851,219
Change in Net OPEB Liability 3,485,823
Change in Deferred Outflows Related to Pensions (918,452)
Change in Deferred Outflows Related to OPEB (470,091)
Change in Deferred Inflows Related to Pensions (42,218,144)
Change in Deferred Inflows Related to OPEB 507,810
Change in Compensated Absences (168,675)
Change in Claims Payable (1,531,360)
Change in Net Position of Governmental Activities 9,820,200$
CITY OF VERNON
STATEMENT OF NET POSITION – PROPRIETARY FUNDS
JUNE 30, 2022
See accompanying Notes to Financial Statements.
(24)
Business-Type Activities
Enterprise Funds
Nonmajor
Electric Gas Water Fiber Optics
Fund Fund Fund Fund Totals
ASSETS
Current Assets:
Cash and Cash Equivalents 130,758,591$ 8,692,417$ 17,015,777$ 493,854$ 156,960,639$
Accounts Receivable, Net of Allowance 12,396,047 580,100 1,141,938 144,253 14,262,338
Accrued Unbilled Revenue 16,411,782 1,240,987 1,373,195 -19,025,964
Accrued Interest Receivable 84,749 -4,448 -89,197
Due from Other Funds 70,399 --- 70,399
Prepaid Expenses 17,666 --- 17,666
Prepaid Natural Gas 636,909 --- 636,909
Total Current Assets 160,376,143 10,513,504 19,535,358 638,107 191,063,112
Noncurrent Assets:
Restricted Cash and Investments 39,025,025 -7,358,059 -46,383,084
Advances to Other Funds 27,079,890 -202,798 -27,282,688
Prepaid Expenses 994,736 --- 994,736
Deposits 1,201,423 --- 1,201,423
Capital Assets:
Nondepreciable 63,421,951 -7,381,939 -70,803,890
Depreciable, Net 362,295,361 15,379,161 8,886,072 1,063,160 387,623,754
Total Noncurrent Assets 494,018,386 15,379,161 23,828,868 1,063,160 534,289,575
Total Assets 654,394,529 25,892,665 43,364,226 1,701,267 725,352,687
DEFERRED OUTFLOWS OF RESOURCES
Deferred Outflows Related to Pensions 4,016,377 397,282 917,279 7,859 5,338,797
Deferred Outflows Related to OPEB Liability 498,130 49,273 113,765 975 662,143
Deferred Amount on Refunding 1,933,345 - -- 1,933,345
Total Deferred Outflows of Resources 6,447,852 446,555 1,031,044 8,834 7,934,285
CITY OF VERNON
STATEMENT OF NET POSITION – PROPRIETARY FUNDS (CONTINUED)
JUNE 30, 2022
See accompanying Notes to Financial Statements.
(25)
Business-Type Activities
Enterprise Funds
Nonmajor
Electric Gas Water Fiber Optics
Fund Fund Fund Fund Totals
LIABILITIES
Current Liabilities:
Accounts Payable 15,828,391$ 215,122$ 1,415,262$ 13,734$ 17,472,509$
Accrued Wages and Benefits 333,914 28,032 44,295 363 406,604
Due to Other Funds 2,965,077 71,583 -- 3,036,660
Customer Deposits 425,426 13,558 61,184 -500,168
Bond Interest Payable 4,969,736 -242,490 -5,212,226
Bonds Payable 50,110,000 -250,000 -50,360,000
Note Payable - - 139,535 -139,535
Compensated Absences 369,608 8,377 28,069 81 406,135
Total Current Liabilities 75,002,152 336,672 2,180,835 14,178 77,533,837
Noncurrent Liabilities:
Advances from Other Funds -23,226,198 -3,853,692 27,079,890
Bonds Payable 397,826,476 -14,885,833 -412,712,309
Note Payable - - 1,081,395 -1,081,395
Compensated Absences 739,215 16,754 56,139 162 812,270
Other Postemployment Benefit Liability 2,317,770 229,264 529,343 4,536 3,080,913
Net Pension Liability 12,461,180 1,232,605 2,845,943 24,384 16,564,112
Total Noncurrent Liabilities 413,344,641 24,704,821 19,398,653 3,882,774 461,330,889
Total Liabilities 488,346,793 25,041,493 21,579,488 3,896,952 538,864,726
DEFERRED INFLOWS OF RESOURCES
Deferred Inflows Related to Pensions 7,841,575 775,654 1,790,896 15,345 10,423,470
Deferred Inflows Related to OPEB Liability 1,187,063 117,419 271,107 2,323 1,577,912
Total Deferred Inflows of Resources 9,028,638 893,073 2,062,003 17,668 12,001,382
NET POSITION
Net Investment in Capital Assets 145,563,396 15,301,360 6,869,387 1,053,694 168,787,837
Restricted for Debt Service 32,836,544 - -- 32,836,544
Unrestricted (Deficit)(14,932,990) (14,896,706) 13,884,392 (3,258,213) (19,203,517)
Total Net Position 163,466,950$ 404,654$ 20,753,779$ (2,204,519)$ 182,420,864$
CITY OF VERNON
STATEMENT OF REVENUES, EXPENSES, AND CHANGES
IN FUND NET POSITION – PROPRIETARY FUNDS
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Financial Statements.
(26)
Business-Type Activities
Enterprise Funds
Nonmajor
Electric Gas Water Fiber Optics
Fund Fund Fund Fund Totals
OPERATING REVENUES
Charges for Services 208,539,519$ 18,705,573$ 10,845,652$ 480,014$ 238,570,758$
Total Operating Revenue 208,539,519 18,705,573 10,845,652 480,014 238,570,758
OPERATING EXPENSES
Cost of Sales 144,582,543 17,765,508 7,743,964 222,558 170,314,573
Depreciation 16,510,921 707,035 500,102 186,152 17,904,210
Total Operating Expenses 161,093,464 18,472,543 8,244,066 408,710 188,218,783
OPERATING INCOME 47,446,055 233,030 2,601,586 71,304 50,351,975
NONOPERATING REVENUES (EXPENSES)
Intergovernmental 665,887 5,029 194,487 -865,403
Investment Income 269,257 4,128 11,991 246 285,622
Net Decrease in Fair Value of Investments (8,231) - -- (8,231)
Interest Expense (13,599,589) -(563,895)-(14,163,484)
Loss on Disposal of Assets (1,900,009) (6,076) (409,841)-(2,315,926)
Total Nonoperating Revenues
(Expenses)(14,572,685) 3,081 (767,258) 246 (15,336,616)
CHANGE IN NET POSITION 32,873,370 236,111 1,834,328 71,550 35,015,359
Net Position (Deficit) - Beginning of Year 130,593,580 168,543 18,919,451 (2,276,069) 147,405,505
NET POSITION (DEFICIT) - END OF YEAR 163,466,950$ 404,654$ 20,753,779$ (2,204,519)$ 182,420,864$
CITY OF VERNON
STATEMENT OF CASH FLOWS – PROPRIETARY FUNDS
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Financial Statements.
(27)
Business-Type Activities
Enterprise Funds
Nonmajor
Electric Gas Water Fiber Optics
Fund Fund Fund Fund Totals
CASH FLOWS FROM OPERATING ACTIVITIES
Cash Received from Customers 199,972,221$ 18,586,393$ 10,427,677$ 367,504$ 229,353,795$
Cash Paid to Suppliers for Goods and Services (133,793,435) (16,770,406) (6,851,398) (242,584) (157,657,823)
Cash Paid to Employees for Services (3,090,696) (724,165) (1,818,089) (168,276) (5,801,226)
Cash Paid to City for Services (5,214,961) - -- (5,214,961)
Net Cash Provided by Operating
Activities 57,873,129 1,091,822 1,758,190 (43,356) 60,679,785
CASH FLOWS FROM CAPITAL AND RELATED
FINANCING ACTIVITIES
Repayment of Bonds (34,975,000) -(240,000)-(35,215,000)
Issuance of Bonds 235,885,000 --- 235,885,000
Bond Premiums 38,266,557 --- 38,266,557
Payment to Refunding Bond Escrow Agent (62,999,903) --- (62,999,903)
Bond Interest Paid (16,875,267) -(587,975)-(17,463,242)
Payment of Note Payable - - (139,535)-(139,535)
Net Acquisition of Capital Assets (216,887,677) (261,506) (4,033,299) (211,814) (221,394,296)
Net Cash Used by Capital and Related
Financing Activities (57,586,290) (261,506) (5,000,809) (211,814) (63,060,419)
CASH FLOWS FROM NONCAPITAL FINANCING
ACTIVITIES
Grant Revenue Received 665,887 5,029 194,487 -865,403
Cash Received (Paid) to Other Funds 114,065 (59) 1,915,195 (114,006) 1,915,195
Net Cash Provided (Used) by Noncapital
Financing Activities 779,952 4,970 2,109,682 (114,006) 2,780,598
CASH FLOWS FROM INVESTING ACTIVITIES
Investment Income 178,598 4,128 7,583 246 190,555
Cash Provided by Investing Activities 178,598 4,128 7,583 246 190,555
CHANGE IN CASH AND CASH EQUIVALENTS 1,245,389 839,414 (1,125,354) (368,930) 590,519
Cash and Cash Equivalents - Beginning of Year 168,538,227 7,853,003 25,499,190 862,784 202,753,204
CASH AND CASH EQUIVALENTS - END OF YEAR 169,783,616$ 8,692,417$ 24,373,836$ 493,854$ 203,343,723$
COMPOSITION OF CASH AND CASH EQUIVALENTS
Cash and Cash Equivalents 130,758,591$ 8,692,417$ 17,015,777$ 493,854$ 156,960,639$
Restricted Cash and Investments 39,025,025 -7,358,059 -46,383,084
Total 169,783,616$ 8,692,417$ 24,373,836$ 493,854$ 203,343,723$
CITY OF VERNON
STATEMENT OF CASH FLOWS – PROPRIETARY FUNDS (CONTINUED)
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Financial Statements.
(28)
Business-Type Activities
Enterprise Funds
Nonmajor
Electric Gas Water Fiber Optics
Fund Fund Fund Fund Totals
RECONCILIATION OF OPERATING INCOME (LOSS)
TO NET CASH PROVIDED (USED) BY OPERATING
ACTIVITIES
Operating Income (Loss) 47,446,055$ 233,030$ 2,601,586$ 71,304$ 50,351,975$
Adjustments to Reconcile Operating Income
(Loss) to Net Cash Provided by Operating
Activities:
Depreciation 16,510,921 707,035 500,102 186,152 17,904,210
Deferred Gain from Sale of Generation Assets (6,555,916) - -- (6,555,916)
Change in Operating Assets and Liabilities:
Accounts Receivable (6,672,318) (216,191) (164,414) (112,510) (7,165,433)
Accrued Unbilled Revenue (1,889,809) 97,011 (254,361) -(2,047,159)
Due from Other Funds 523,087 - -- 523,087
Prepaid Expenses and Deposits (104,017) - -- (104,017)
Prepaid Natural Gas (636,909) - -- (636,909)
Deferred Outflows of Resources (564,694) 5,199 102,727 37,961 (418,807)
Accounts Payable 3,257,996 164,516 (1,292) (27,752) 3,393,468
Accrued Wages and Benefits (115,466) (22,058) (67,916) (4,087)(209,527)
Due to Other Funds 2,965,077 71,583 (593,486) -2,443,174
Customer Deposits (5,171) -800 -(4,371)
Compensated Absences 56,427 1,347 (18,983)(2,289) 36,502
Other Postemployment Benefit Liability (111,573) (48,588) (167,986) (24,246)(352,393)
Net Pension Liability (3,801,160) (627,374) (1,822,068) (168,284) (6,418,886)
Deferred Inflows of Resources 7,570,599 726,312 1,643,481 395 9,940,787
Net Cash Provided (Used) by Operating
Activities 57,873,129$ 1,091,822$ 1,758,190$ (43,356)$ 60,679,785$
CITY OF VERNON
STATEMENT OF FIDUCIARY NET POSITION – FIDUCIARY FUND
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Financial Statements.
(29)
Redevelopment
Successor
Agency
Trust Fund
ASSETS
Other Receivable 3,654$
Restricted Cash and Investments 19,037,529
Total Assets 19,041,183
LIABILITIES
Bond Interest Payable 734,183
Long-Term Debt:
Due Within One Year 1,845,000
Due in More than One Year 36,885,803
Total Liabilities 39,464,986
NET POSITION (DEFICIT)
Total Net Position Held in Trust for Dissolution of
Former Redevelopment Agency (20,423,803)$
CITY OF VERNON
STATEMENT OF CHANGES IN FIDUCIARY NET POSITION – FIDUCIARY FUND
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Financial Statements.
(30)
Redevelopment
Successor
Agency
Trust Fund
ADDITIONS
Property Tax Increment 4,969,969$
Investment Earnings 7,054
Total Additions 4,977,023
DEDUCTIONS
Community Development 831,337
Interest on Long-Term Debt 2,289,050
Total Deductions 3,120,387
CHANGE IN NET POSITION 1,856,636
Net Position (Deficit) Held in Trust - Beginning of Year (22,280,439)
NET POSITION (DEFICIT) HELD IN TRUST - END OF YEAR (20,423,803)$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(31)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The financial statements of the City of Vernon, California (City) have been prepared in
conformity with U.S. generally accepted accounting principles (U.S. GAAP). The
Governmental Accounting Standards Board (GASB) is the accepted standard-setting body
for establishing governmental accounting and financial reporting principles. The more
significant of the City’s accounting policies are described below.
A. Reporting Entity
The City was incorporated on September 16, 1905 as a General Law City. Effective
July 1, 1988, the City became a Charter City. The City operates under a Council-City
Administrator form of government. As required by generally accepted accounting
principles, the accompanying financial statements present the City of Vernon (primary
government) and its component units, entities for which the primary government is
considered to be financially accountable. Blended component units, although legally
separate entities, are, in substance, part of the government’s operations and so data
from these units are combined with the data of the primary government. For the fiscal
year ended June 30, 2021, the City transferred its fire department operations to Los
Angeles County, California. See Note 4 and Note 7 for further details on how the transfer
impacted the City's capital assets and safety pension plan, respectively.
B. Basis of Presentation
Government-Wide Financial Statements
The statement of net position and statement of activities display information about the
primary government (the City). These statements include the financial activities of the
overall government. It is the City’s policy to make eliminations to minimize the double
counting of internal activities, except for services rendered by governmental activities to
business-type activities. These statements distinguish between the governmental and
business-type activities of the City. Governmental activities, which normally are
supported by taxes, are reported separately from business-type activities, which rely to a
significant extent on fees charged to external parties. Effective February 1, 2012, due to
AB 1X 26, the dissolution of Redevelopment Agencies throughout California, the
activities of the dissolved Vernon Redevelopment Agency are recorded in the Vernon
Redevelopment Successor Agency trust fund which is a component unit of the City.
The statement of activities presents a comparison between direct expenses and
program revenues for each segment of the business-type activities of the City and for
each function of the City’s governmental activities. Direct expenses are those that are
specifically associated with a program or function; and therefore, are clearly identifiable
to a particular function. Program revenues include (i) charges paid by the recipients of
goods or services offered by the programs and (ii) grants and contributions that are
restricted to meeting the operational or capital requirements of a particular program.
Revenues that are not classified as program revenues, including all taxes, are presented
instead as general revenues.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(32)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
B. Basis of Presentation (Continued)
Government-Wide Financial Statements (Continued)
Separate financial statements are provided for governmental fund, proprietary funds and
fiduciary funds, even though the latter are excluded from the government-wide financial
statements. The major individual governmental fund and the major individual enterprise
funds are reported as separate columns in the fund financial statements.
Fund Financial Statements
The fund financial statements provide information about the City’s funds and blended
component units. Separate statements for each fund category – governmental and
proprietary – are presented. The emphasis of fund financial statements is on major
governmental and enterprise funds, each displayed in a separate column.
Proprietary funds distinguish operating revenues and expenses from nonoperating
items. Proprietary fund operating revenues, such as charges for services, result from
exchange transactions associated with the principal activity of the fund. Exchange
transactions are those in which each party receives and gives up essentially equal
values. Nonoperating revenues, such as subsidies and investment earnings, result from
nonexchange transactions or ancillary activities. Operating expenses include the cost of
sales and services, administrative expenses and depreciation on capital assets. All
expenses not meeting this definition are reported as nonoperating expenses.
The City reports one major governmental fund:
The General Fund is the City’s primary operating fund. It is used to account for all
revenues and expenditures necessary to carry out basic governmental activities of the
City that are not accounted for through other funds. For the City, the General Fund
includes such activities as general government, public safety, health services, and public
works.
The City reports three major enterprise funds:
The Electric Fund accounts for the maintenance and operations of the City’s
electric utility plant. Revenues for this fund are primarily from charges for
services.
The Gas Fund accounts for the maintenance and operations of the City’s gas
utility plant. Revenues for this funds are primarily from charges for services.
The Water Fund accounts for the maintenance and operations of the City’s water
utility plant. Revenues for this fund are primarily from charges for services.
The City also reports a fiber optics nonmajor enterprise fund for the maintenance and
operation of the City’s fiber optics utility plant.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(33)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
B. Basis of Presentation (Continued)
Fund Financial Statements (Continued)
The City reports one fiduciary fund:
Vernon Redevelopment Successor Agency Private-Purpose Trust Fund –
This is a fiduciary fund type used by the City to report trust arrangements under
which principal and income benefit other governments. This fund reports the
assets, liabilities and activities of the Successor Agency to the Dissolved Vernon
Redevelopment Agency. Unlike the limited reporting typically utilized for Agency
Funds, the Private-Purpose Trust Fund reports a statement of fiduciary net
position and a statement of changes in fiduciary net position.
The government-wide and proprietary fund financial statements are reported using the
economic resources measurement focus and the accrual basis of accounting. Revenues
are recorded when earned and expenses are recorded at the time liabilities are incurred,
regardless of when the related cash flows take place. Nonexchange transactions, in
which the City gives (or receives) value without directly receiving (or giving) equal value
in exchange, include property and sales taxes, grants, entitlements and donations. On
an accrual basis, revenue from property taxes is recognized in the fiscal year for which
the taxes are levied. Revenues from sales taxes are recognized when the underlying
transactions take place. Revenues from grants, entitlements and donations are
recognized in the fiscal year in which all eligible requirements have been satisfied.
Governmental fund type financial statements are reported using the current financial
resources measurement focus and the modified accrual basis of accounting. Under this
method, revenues and other governmental fund type financial resources are recognized
when they become susceptible to accrual – that is, when they become both measurable
and available. Revenues are considered to be available when they are collectible within
the current period or soon enough thereafter to pay liabilities of the current period.
Property, sales, and other taxes are considered available and are accrued when
received within 60 days after fiscal year-end. Additionally, all other revenue sources are
considered available and are accrued when received within 60 days of year-end.
Expenditures generally are recorded when a liability is incurred, as under accrual
accounting. However, debt service expenditures, as well as expenditures related to
compensated absences and claims and judgments, are recorded only when payment is
due. General capital assets acquisitions are reported as expenditures in governmental
fund statements.
Fiduciary funds are used to account for resources held for the benefit of parties outside
the government. Fiduciary funds are not reflected in the government-wide financial
statements because the resources of those funds are not available to support the City’s
own programs. The City maintains a separate fund to report the activities of the
Successor Agency to the Dissolved Redevelopment Agency. These assets do not
belong to the City. The accounting used for fiduciary funds is much like that used for
proprietary funds.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(34)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
B. Basis of Presentation (Continued)
Fund Financial Statements (Continued)
Because the governmental fund financial statements are presented on a different
measurement focus and basis of accounting than the government-wide financial
statements for governmental activities, reconciliations are presented which briefly
explain the adjustments necessary to reconcile the fund financial statements to the
governmental-wide statements.
C. Implementation of New Accounting Pronouncements
In June 2017, the Governmental Accounting Standards Board (GASB) issued GASB
Statement No. 87, Leases. This standard requires the recognition of certain lease assets
and liabilities for leases that previously were classified as operating leases and as
inflows of resources or outflows of resources recognized based on the payment
provisions of the contract. It establishes a single model for lease accounting based on
the foundational principle that leases are financings of the right to use an underlying
asset. Under this standard, a lessee is required to recognize a lease liability and an
intangible right-to-use lease asset, and a lessor is required to recognize a lease
receivable and a deferred inflow of resources.
The City adopted the requirements of the guidance effective July 1, 2021 and has
applied the provisions of this standard to the beginning of the period of adoption.
D. Cash and Investments
The City follows the practice of pooling cash and investments of all funds to maximize
returns for all funds, except for funds held by trustees or fiscal agents.
For purposes of the statement of cash flows, the City considers amounts on deposit in
the City’s cash and investment pool and all highly liquid investments (including restricted
cash and investments) with an original maturity of three months or less when purchased
to be cash equivalents. Investment transactions are recorded on the trade date.
Investments in nonparticipating interest-earning investment contracts are reported at
cost and all other investments are reported at fair value. Fair value is defined as the
amount that the City could reasonably expect to receive for an investment in a current
sale between a willing buyer and a seller and is generally measured by quoted market
prices.
E. Receivables/Payables
Short-term interfund receivables and payables are classified as “due from other funds”
and “due to other funds”, respectively, on the balance sheet and as internal balances on
the statement of net position. Long-term interfund receivables and payables are
classified as “advances to/from other funds,” respectively, on the balance sheet and as
internal balances on the statement of net position.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(35)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
E. Receivables/Payables (Continued)
Proprietary fund trade receivables are shown net of an allowance for uncollectible
accounts. Allowances for uncollectible were $1,043,137 as of June 30, 2022. Utility
customers are billed monthly. The estimated value of services provided, but unbilled at
year-end, has been included in the accompanying financial statements.
F. Inventories
All inventories are valued at cost, or estimated historical costs when historical
information is unavailable, using the first-in/first-out (FIFO) method. Inventory costs in
the governmental funds are recorded as an expenditure when used and are reported
under the consumption method of accounting. Inventory costs in the proprietary funds
are recorded as an expense or capitalized into capital assets when used.
G. Prepaid Items
The City made a prepayment to Southern California Public Power Authority (SCPPA) for
the City’s share of SCPPA’s payoff of the Hoover Center and Air Slots debt. This prepaid
amount is amortized over the life of the debt based on the annual debt service
obligations. See Note 9 for further information regarding SCPPA.
H. Capital Assets
Capital assets (including infrastructure) are recorded at historical cost or at estimated
historical cost if the actual historical cost is not available. Contributed capital assets are
valued at their acquisition value on the date contributed. Capital assets include
intangible assets with indefinite lives and public domain (infrastructure) general capital
assets consisting of certain improvements including roads and bridges, sidewalks, curbs
and gutters, and traffic light systems. The capitalization threshold for all capital assets is
$5,000. Capital assets used in operations are depreciated using the straight-line method
over their estimated useful lives in the government-wide and proprietary funds
statements.
The estimated useful lives are as follows:
Infrastructure 10 to 50 Years
Utility Plant and Buildings 25 to 50 Years
Improvements 10 to 20 Years
Right-to-use equipment 3 years
Machinery and Equipment 3 to 35 Years
Maintenance and repairs are charged to operations when incurred. Betterments and
major improvements, which significantly increase values, change capacities or extend
useful lives, are capitalized. Upon sale or retirement of capital assets, the cost and
related accumulated depreciation are removed from the respective accounts and any
resulting gain or loss is included in the changes in net financial position.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(36)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
I. Compensated Absences
Accumulated vacation is accrued when incurred in the government-wide, proprietary and
fiduciary fund financial statements. A liability for accrued vacation is recorded in the
governmental fund only to the extent that such amounts have matured (i.e., as a result of
employee resignations and retirements). Upon termination of employment, the City will
pay the employee all accumulated vacation leave at 100% of the employee’s base
hourly rate.
J.Deferred Outflows and Inflows of Resources
The statement of net position will sometimes report a separate section for deferred
outflows of resources. This separate financial statement element, deferred outflows of
resources, represents a consumption of net assets that applies to a future period and will
not be recognized as an outflow of resources (expense/expenditure) until that time.
The City has the following items that qualify for reporting as deferred outflows of
resources:
Deferred outflows related to pension and OPEB plans equal to employer
contributions made after the measurement date of the pension and OPEB
liabilities.
Deferred outflows related to pension and OPEB plans for differences between
expected and actual experiences. These amounts are amortized over a closed
period equal to the average of the expected remaining service lives of all
employees that are provided with pensions and OPEB benefits through the
plans.
Deferred outflows related to pension for changes in employer’s proportion and
differences between employer’s contributions and the proportionate share of
employer contributions. These amounts are amortized over a closed period equal
to the average of the expected remaining service lives of all employees that are
provided with pensions benefits through the plans.
Deferred outflows related to OPEB plans for changes in assumptions. These
amounts are amortized over a closed period equal to the average of the
expected remaining service lives of all employees that are provided with OPEB
benefits through the plans.
Deferred outflows related to pension and OPEB plans resulting from the net
difference between projected and actual earnings on plan investments. These
amounts are amortized over five years.
Deferred amount on bond refunding which is amortized over the life of refunding
debt.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(37)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
J.Deferred Outflows and Inflows of Resources (Continued)
The statement of net position and the governmental fund balance sheet will sometimes
report a separate section for deferred inflows of resources. This separate financial
statement element, deferred inflows of resources, represents an acquisition of net assets
that applies to a future period and will not be recognized as an inflow of resources
(revenue) until that time. The City has the following items that qualify for reporting in this
category:
Deferred inflows related to OPEB plans for changes in assumptions. These
amounts are amortized over a closed period equal to the average of the
expected remaining service lives of all employees that are provided with
pensions and OPEB benefits through the plans.
Deferred inflows related to OPEB plans for differences between expected and
actual experiences. These amounts are amortized over a closed period equal to
the average of the expected remaining service lives of all employees that are
provided with OPEB benefits through the plans.
Deferred inflows related to pension plans for changes in employer’s proportion
and differences between employer’s contributions and the proportionate share of
employer contributions. These amounts are amortized over a closed period equal
to the average of the expected remaining service lives of all employees that are
provided with pension benefits through the plans.
Deferred inflows related to pension and OPEB plans resulting from the net
difference between projected and actual earnings on plan investments. These
amounts are amortized over five years.
K. Long-Term Obligations
Certain of the City’s governmental fund obligations not currently due and payable at
year-end are reported in the government-wide statement of net position. Long-term debt
and other obligations financed by proprietary funds and the fiduciary fund are reported
as liabilities in the appropriate proprietary fund, fiduciary fund and government-wide
statement of net position, respectively. Bond discounts and premiums, and deferred
amounts on refunding are amortized over the life of the bonds using the straight-line
method, which approximates the effective interest method.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(38)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
L. Leases
Lessee
The City is a lessee for a noncancellable leases of equipment. The City recognizes a
lease liability and an intangible right-to-use asset (lease asset) in the governmental
activities in the government-wide statement of net position. At the commencement of a
lease, the City initially measures the lease liability at the present value of payments
expected to be made during the lease term. Subsequently, the lease liability is reduced
by the principal portion of lease payments made. The lease asset is initially measured as
the initial amount of the lease liability, adjusted for lease payments made at or before the
lease commencement date. Subsequently, the lease asset is amortized on a straight-line
basis over its useful life.
The City monitors changes in circumstances that would require a remeasurement of its
lease and will remeasure the lease asset and liability if certain changes occur that are
expected to significantly affect the amount of the lease liability.
Lessor
The City is a lessor for a noncancellable lease of land and improvements. The City
recognizes a lease receivable and a deferred inflow of resources in the statement of net
position and in the governmental fund balance sheet. At the commencement of a lease,
the City initially measures the lease receivable at the present value of payments
expected to be received during the lease term. Subsequently, the lease receivable is
reduced by the principal portion of lease payments received. The deferred inflow of
resources is initially measured as the initial amount of the lease receivable, adjusted for
lease payments received at or before the lease commencement date. Subsequently, the
deferred inflow of resources is recognized as revenue over the life of the lease term.
The City monitors changes in circumstances that would require a remeasurement of its
lease and will remeasure the lease receivable and deferred inflows of resources if
certain changes occur that are expected to significantly affect the amount of the lease
receivable.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(39)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
M. Net Position
The government-wide financial statements and proprietary fund financial statements
utilize a net position presentation. Net position is categorized as follows:
Net Investment in Capital Assets – This category groups all capital assets,
including infrastructure, into one component of net position. Accumulated
depreciation and the outstanding balances of debt that are attributable to the
acquisition, construction or improvement of these assets reduce the balance in this
category.
Restricted Net Position – This category presents external restrictions imposed by
creditors, grantors, contributors or laws or regulations of other governments and
restrictions imposed by law through constitutional provisions or enabling legislation.
Unrestricted Net Position – This category represents the net position of the City not
reported in other categories.
The City’s policy regarding whether to first apply restricted or unrestricted resources
when an expense is incurred for purposes for which both restricted and unrestricted net
position are available is to use restricted resources first.
N. Fund Balance
In the fund financial statements, the governmental fund balance is classified in the
following categories:
Nonspendable Fund Balance – includes amounts that are (a) not in spendable
form, or (b) legally or contractually required to be maintained intact. The “not in
spendable form” criterion includes items that are not expected to be converted to
cash, for example, inventories, prepaid amounts, and long-term notes receivable.
Restricted Fund Balance – includes amounts that are restricted for specific
purposes stipulated by external resource providers, constitutionally or through
enabling legislation. Restrictions may effectively be changed or lifted only with the
consent of resource providers.
Committed Fund Balance – includes amounts that can only be used for the specific
purposes determined by formal action of the City’s highest level of decision-making
authority, its City Council. Commitments may be changed or lifted only by the City
taking the same formal action that imposed the constraint originally (for example,
ordinance).
Unassigned Fund Balance – includes the residual classification for the General
Fund and includes all amounts not contained in the other classifications.
In circumstances when an expenditure is made for a purpose for which amounts are
available in multiple fund balance classifications, fund balance is depleted in the order of
restricted, committed, assigned, and unassigned.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(40)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
O. Encumbrances
The City establishes encumbrances to record the amount of purchase orders, contracts,
and other obligations, which have not yet been fulfilled, canceled or discharged.
Encumbrances outstanding at year-end do not constitute expenditures or liabilities.
Encumbrances outstanding at year-end are reported as a component of unassigned
fund balance. Unencumbered appropriations lapse at year-end.
P. Use of Estimates
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make estimates and
assumptions that affect certain reported amounts and disclosures. Accordingly, actual
results could differ from those estimates.
Q. Property Taxes
The County of Los Angeles (County) levies, collects and apportions property taxes for all
taxing jurisdictions within the County. Property taxes are determined by applying
approved rates to the properties’ assessed values. The County remits property taxes
applicable to the City less an administrative fee throughout the year.
Article XIIIA of the state of California Constitution limits the property tax levy to support
general government services of the various taxing jurisdictions to $1.00 per $100 of
assessed value. Taxes levied to service voter-approved debt prior to June 30, 1978, are
excluded from this limitation.
Secured property taxes are levied in two installments, November 1 and February 1. They
become delinquent with penalties after December 10 and April 10, respectively. The lien
date is January 1 of each year for secured and unsecured property taxes and the levy
date occurs on the 4th Monday of September of the tax year. Unsecured property taxes
on the tax roll as of July 31 become delinquent with penalties on August 31.
R. Pensions
For purposes of measuring the net pension liability and deferred outflows/inflows of
resources related to pensions and pension expense, information about the fiduciary net
position of the City’s California Public Employees’ Retirement System (CalPERS) and
PARS plan and additions to/deductions from the Plans’ fiduciary net position have been
determined on the same basis as they are reported by CalPERS and PARS. For this
purpose, benefit payments (including refunds of employee contributions) are recognized
when due and payable in accordance with the benefit terms. Investments are reported at
fair value.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(41)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
S.Postemployment Benefits Other than Pensions (OPEB)
For purposes of measuring the net OPEB liability, deferred outflows of resources and
deferred inflows of resources related to OPEB, and OPEB expense information about
the fiduciary net position of the City’s OPEB Plan and additions to/deductions from the
Plan’s fiduciary net position have been determined on the same basis as they are
reported by the Plan. For this purpose, the Plan recognizes benefit payments when due
and payable in accordance with the benefit terms. Investments are reported at fair value.
NOTE 2 CASH AND INVESTMENTS
Cash and Investments
Cash and investments as of June 30, 2022, are classified in the accompanying financial
statements as follows:
Primary Fiduciary
Government Fund Total
Cash and Cash Equivalents 174,934,022$ -$ 174,934,022$
Restricted Cash and Cash Equivalents 52,651,048 19,037,529 71,688,577
Total Cash and Cash
Equivalents 227,585,070$ 19,037,529$ 246,622,599$
Cash and investments as of June 30, 2022, consist of the following:
Cash on Hand 1,300$
Deposits with Financial Institutions 99,883,420
Investments 146,737,879
Total Cash and Investments 246,622,599$
The City’s Investment Policy
The City’s Investment Policy sets forth the investment guidelines for all funds of the City.
The Investment Policy conforms to the California Government Code Section 53600 et. seq.
The authority to manage the City’s investment program is derived from the City Council.
Pursuant to Section 53607 of the California Government Code, the City Council annually,
appoints the City Treasurer to manage the City’s investment program and approves the
City’s Investment Policy. The Treasurer is authorized to delegate this authority as deemed
appropriate. No person may engage in investment transactions except as provided under
the terms of the Investment Policy and the procedures established by the Treasurer.
This Investment Policy requires that the investments be made with the prudent person
standard, that is, when investing, reinvesting, purchasing, acquiring, exchanging, selling or
managing public funds, the trustee (Treasurer and staff) will act with care, skill, prudence,
and diligence under the circumstances then prevailing, including but not limited to, the
general economic conditions and the anticipated needs of the City.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(42)
NOTE 2 CASH AND INVESTMENTS (CONTINUED)
The City’s Investment Policy (Continued)
The Investment Policy also requires that when following the investing actions cited above,
the primary objective of the trustee be to safeguard the principal, secondarily meet the
liquidity needs of depositors, and then achieve a return on the funds under the trustee’s
control. Further, the intent of the Investment Policy is to minimize the risk of loss on the
City’s held investments from:
A. Credit risk
B.Custodial credit risk
C.Concentration of credit risk
D. Interest rate risk
Investments Authorized by the California Government Code and the City’s Investment
Policy
The table below identifies the investment types that are authorized for the City by the
California Government Code and the City’s Investment Policy. The table also identifies
certain provisions of the California Government Code that address interest rate risk, credit
risk, and concentration of credit risk. This table does not address investment of debt
proceeds held by the bond trustee that are governed by the provisions of debt agreements
of the City, rather than the general provisions of the California Government Code or the
City’s Investment Policy.
Maximum Maximum
Authorized Maximum Percentage Investment Minimum
Investment Type Maturity of Portfolio* in One Issuer Rating
U.S. Treasury Obligations 5 Years None None None
U.S. Agency Securities 5 Years None None None
Local Agency Bonds 5 Years None None AA
CA State and Local Agency Bonds 5 Years 30%None None
Bankers’ Acceptances 180 Days 40%30%None
Commercial Paper 270 Days 25%10%(1)
Negotiable Certificates of Deposit 5 Years 30%None None
Repurchase Agreements 1 year None None None
Reverse Repurchase Agreements 92 Days 20%None None
Medium-Term Notes 5 Years 30%None A
Mutual Funds Investing in Eligible Securities N/A 20%10%AAA
Money Market Mutual Funds N/A 20%10%AAA
Mortgage Pass-Through Securities 5 Years 20%None AA
State Administered Pool Investment N/A None None None
(1)Highest letter and numerical rating by a nationally recognized statistical ratings organization.
* Excluding amounts held by bond trustee that are not subject to California Government Code restrictions.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(43)
NOTE 2 CASH AND INVESTMENTS (CONTINUED)
Investments Authorized by Debt Agreements
Investments of debt proceeds held by bond trustees are governed by provisions of the debt
agreements, rather than the general provisions of the California Government Code or the
City’s Investment Policy. The table below identifies the investment types that are authorized
for investments held by the bond trustee. The table also identifies certain provisions of these
debt agreements that address interest rate risk, credit risk, and concentration of credit risk.
Maximum Maximum
Authorized Maximum Percentage Investment Minimum
Investment Type Maturity of Portfolio in One Issuer Rating
U.S. Treasury Obligations None None None None
U.S. Agency Securities None None None None
Certificates of Deposit None None None None
Bankers’ Acceptances 1 Year None None None
Commercial Paper None None None (1)
Money Market Mutual Funds N/A None None AAA
State Administered Pool Investment N/A None $50 Million None
Investment Contracts None None None None
(1)Highest letter and numerical rating by a nationally recognized statistical ratings organization.
Disclosure Relating to Interest Rate Risk
Interest rate risk is the risk that changes in market interest rates will adversely affect the fair
value of an investment. Generally, the longer the maturity of an investment, the greater the
sensitivity of its fair value to changes in market interest rates. One of the ways that the City
manages its exposure to interest rate risk is by purchasing a combination of shorter-term
and longer-term investments and by timing cash flows from maturities so that a portion of
the portfolio is maturing or coming close to maturity evenly over time as necessary to
provide the cash flow and liquidity needed for operations. The City monitors the interest rate
risk inherent in its portfolio by measuring the weighted average maturity of its portfolio. The
City has no specific limitations with respect to this metric.
Investment Maturities
Fair Value (in Months)
as of Less than 13 to 25 to
Investment Type 6/30/2022 12 Months 24 Months 60 Months
Investments:
Local Agency Investment Fund 627,044$ 627,044$ -$ -$
Investments with Fiscal Agent:
Money Market Mutual Funds 146,110,835 146,110,835 --
Total Investments 146,737,879$ 146,737,879$ -$ -$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(44)
NOTE 2 CASH AND INVESTMENTS (CONTINUED)
Disclosures Relating to Credit Risk
Generally, credit risk is the risk that an issuer of an investment will not fulfill its obligation to
the holder of the investment. This is measured by the assignment of a rating by a nationally
recognized statistical rating organization. Presented below is the minimum rating required by
the California Government Code, the City’s Investment Policy, or debt agreements, and the
actual rating as of the year-end for each investment type.
Concentration of Credit Risk
The City’s Investment Policy places no limit on the amount the City may invest in any one
issuer excluding a 10% limitation on commercial paper, mutual funds, and money market
mutual funds and a 30% limitation on bankers’ acceptances. The City’s Investment Policy
also places no limit on the amount of debt proceeds held by a bond trustee that the trustee
may invest in one issuer that is governed by the provisions of debt agreements of the City,
rather than the general provisions of the California Government Code or the City’s
Investment Policy. As of June 30, 2022, there were no investments held by the City that
exceeded 5% in any one issuer, excluding the investments in money market mutual funds.
Custodial Credit Risk
Custodial credit risk for deposits is the risk that, in the event of the failure of a depository
financial institution, a government will not be able to recover its deposits or will not be able
to recover collateral securities that are in the possession of an outside party. The custodial
credit risk for investments is the risk that, in the event of the failure of the counterparty to a
transaction, a government will not be able to recover the value of its investment or collateral
securities that are in the possession of another party. The California Government Code and
the City’s Investment Policy do not contain legal or policy requirements that would limit the
exposure to custodial credit risk for deposits or investments. Under the California
Government Code, a financial institution is required to secure deposits, in excess of the
FDIC insurance amount of $250,000, made by state or local governmental units by pledging
government securities held in the form of an undivided collateral pool. The market value of
the pledged securities in the collateral pool must equal at least 110% of the total amount
deposited by the public agencies. California law also allows financial institutions to secure
City deposits by pledging first trust deed mortgage notes having a value of 150% of the
secured public deposits. Such collateral is held by the pledging financial institution’s trust
department or agent in the City’s name.
At year-end, the carrying amounts of the City’s deposits were $99,883,420. The bank
balances were $100,221,139, respectively. The difference between the bank balances and
the carrying amounts represents outstanding checks and deposits in transit. As of June 30,
2022, the City’s deposits with financial institutions were either FDIC-insured or collateralized
by the pledging financial institution as required by Section 53652 of the California
Government Code.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(45)
NOTE 2 CASH AND INVESTMENTS (CONTINUED)
Local Agency Investment Fund (LAIF)
The City is a voluntary participant in the Local Agency Investment Fund (LAIF) that is
regulated by the California Government Code under the oversight of the Treasurer of the
state of California. The fair value of the City’s investment in this pool is reported in the
accompanying financial statements at amounts based upon the City’s pro rata share of the
fair value provided by LAIF for the entire LAIF portfolio. The balance available for withdrawal
is based on the accounting records maintained by LAIF. LAIF is not rated.
Fair Value Measurement
The City categorizes its fair value measurement within the fair value hierarchy established
by accounting principles generally accepted in the United States of America. The hierarchy
is based on the valuation inputs used to measure the fair value of the assets. Level 1 inputs
are quoted prices in active markets for identical assets, Level 2 inputs are quoted prices of
similar assets in active markets, and Level 3 inputs are significant unobservable inputs.
The fair value of the City’s investments in the Local Agency Investment Fund and the money
market mutual funds are not subject to the fair value hierarchy requirement.
Minimum Fair Value
Required Credit Rating as of
Investment Type Rating Moody's / S&P June 30, 2022
Investments:
Local Agency Investment Fund Not Rated Not Rated 627,044$
Investments with Fiscal Agent:
Money Market Mutual Funds Aaa / AAA Aaa / AAA 146,110,835
Total Investments 146,737,879$
NOTE 3 LEASE RECEIVABLE
The City, acting as lessor, leases land and improvements under a noncancellable lease
agreement. The lease expires in January 2061. The net present value of the lease
receivable was determined using a discount rate of 2.01%. Monthly lease payments are
$11,914. During the year ended June 30, 2022, the District recognized $65,378 and $77,584
in lease revenue and interest revenue respectively, pursuant to this lease agreement. The
lease provides for increases in future minimum monthly lease payments, subject to certain
variable increases.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(46)
NOTE 3 LEASE RECEIVABLE (CONTINUED)
Estimated future minimum lease payments to be received are as follows:
Fiscal Year Ending June 30,Principal Interest
2023 66,705$ 76,258$
2024 68,058 74,905
2025 69,439 73,524
2026 70,847 72,115
2027 72,284 70,678
2028-2032 384,022 330,792
2033-2037 424,587 290,227
2038-2042 469,436 245,378
2043-2047 519,023 195,791
2048-2051 573,847 140,966
2052-2056 634,463 80,350
2057-2061 483,593 16,776
Total Requirements 3,836,304$ 1,667,760$
NOTE 4 INTERFUND TRANSACTIONS
Interfund receivables and payables were as follows at June 30, 2022:
Due to/from Other Funds
Due from Other Funds Due to Other Funds Amount
General Fund Electric Enterprise Fund 2,965,077$
Gas Enterprise Fund 1,184
Electric Enterprise Fund Gas Enterprise Fund 70,399
Total 3,036,660$
The interfund balances resulted from borrowing of cash for temporary purposes. All
balances are expected to be reimbursed within the subsequent year.
Advances to/from Other Funds
Receivable Fund Payable Fund Amount
Electric Enterprise Fund Gas Enterprise Fund 23,226,198$
Fiber Optics Enterprise Fund 3,853,692
Water Enterprise Fund General Fund 202,798
Total 27,282,688$
The advance between the Electric Enterprise Fund and the Gas and Fiber Optics Enterprise
Funds do not accrue interest due to the nature of the City’s operational relationship and
capital projects funded by the Electric Enterprise Fund that benefit all City operations. On
November 6, 2012, the City adopted Resolution No. 2012-215 extending the repayment
term of the advance from 15 months to a period of over 10 years.
The advance between the Water Enterprise Fund and the General Fund does not accrue
interest due to the nature of the City’s operational relationship and capital projects funded by
the Water Fund that benefit both. On November 6, 2012, the City adopted Resolution No.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(47)
2012-215 extending the repayment term of the advance from 15 months to a period of over
10 years.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(48)
NOTE 5 CAPITAL ASSETS
Capital asset activity of governmental activities for the fiscal year ended June 30, 2022, was
as follows:
Balance
June 30, 2021 Balance
Restated (1) Additions Deletions June 30, 2022
Governmental Activities:
Capital Assets, Not Being Depreciated:
Land 63,569,108$ -$ -$ 63,569,108$
Construction in Progress 1,286,427 945,551 - 2,231,978
Total Capital Assets, Not
Being Depreciated 64,855,535 945,551 - 65,801,086
Capital Assets, Being Depreciated/Amortized:
Infrastructure 158,968,027 108,610 - 159,076,637
Building and Improvements 16,711,672 69,284 (8,362) 16,772,594
Improvements Other than Buildings 11,980,249 229,764 (297) 12,209,716
Right-to-Use Leased Equipment 56,857 - - 56,857
Machinery and Equipment 20,279,547 1,937,921 (5,312,385) 16,905,083
Total Capital Assets, Being
Depreciated/Amortized 207,996,352 2,345,579 (5,321,044) 205,020,887
Less: Accumulated Depreciation/
Amortization For:
Infrastructure (75,134,891) (3,567,572) - (78,702,463)
Building and Improvements (9,215,846) (394,407) 5,185 (9,605,068)
Improvements Other than Buildings (6,228,742) (349,342) 199 (6,577,885)
Right-to-Use Leased Equipment - (25,270) - (25,270)
Machinery and Equipment (16,889,206) (679,708) 4,751,155 (12,817,759)
Total Accumulated Depreciation/
Amortization (107,468,685) (5,016,299) 4,756,539 (107,728,445)
Total Capital Assets, Being Depreciated/
Amortized, Net:
Infrastructure 83,833,136 (3,458,962) - 80,374,174
Building and Improvements 7,495,826 (325,123) (3,177) 7,167,526
Improvements Other than Buildings 5,751,507 (119,578) (98) 5,631,831
Right-to-Use Leased Equipment 56,857 (25,270) - 31,587
Machinery and Equipment 3,390,341 1,258,213 (561,230) 4,087,324
Total 100,527,667 (2,670,720) (564,505) 97,292,442
Governmental Activities Capital
Assets, Net 165,383,202$ (1,725,169)$ (564,505)$ 163,093,528$
(1)Beginning balance was restated to add right-to-use leased assets due to implementation
of GASB Statement No. 87, Leases. See Note 1C
Depreciation expense was charged to governmental functions as follows:
General Government 826,038$
Public Safety 222,444
Public Works 3,967,817
Total Depreciation/Amortization Expense -
Governmental Functions 5,016,299$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(49)
NOTE 5 CAPITAL ASSETS (CONTINUED)
Capital asset activity of business-type activities for the fiscal year ended June 30, 2022, was
as follows:
Balance Balance
June 30, 2021 Additions Deletions Transfers June 30, 2022
Business-Type Activities:
Capital Assets, Not Being Depreciated:
Electric Utility - Land 13,193,594$ -$ -$ -$ 13,193,594$
Water Utility - Water 467,640 - - - 467,640
Electric Utility - Intangibles -
Environmental Credits 1,163,811 3,610,772 - - 4,774,583
Electric Utility - Construction in
Progress 45,324,750 129,024 - - 45,453,774
Water Utility - Construction in Progress 4,635,417 2,366,637 - (87,755) 6,914,299
Total Capital Assets, Not
Being Depreciated 64,785,212 6,106,433 - (87,755) 70,803,890
Capital Assets, Being Depreciated
Electric Utility - Production Plant 16,189,303 196,173,685 - - 212,362,988
Electric Utility - Transmission Plant 4,888,113 - (1,271,649) - 3,616,464
Electric Utility - Distribution Plant 258,451,179 16,781,817 (18,181,346) - 257,051,650
Electric Utility - General Plant 9,587,933 192,379 (25,903) - 9,754,409
W ater Utility Plant 23,765,353 1,666,662 (1,789,499) 87,755 23,730,271
Gas Utility Plant 26,973,692 261,506 (34,604) - 27,200,594
Fiber Optic Utility Plant 4,161,378 211,814 (616,583) - 3,756,609
Total Capital Assets, Being
Depreciated 344,016,951 215,287,863 (21,919,584) 87,755 537,472,985
Less: Accumulated Depreciation for:
Electric Utility - Production Plant (10,757,493) (8,634,043) - - (19,391,536)
Electric Utility - Transmission Plant (3,424,581) (78,093) 1,059,485 - (2,443,189)
Electric Utility - Distribution Plant (101,227,123) (7,438,076) 16,493,501 - (92,171,698)
Electric Utility - General Plant (6,148,921) (360,709) 25,903 - (6,483,727)
Water Utility Plant (15,723,755) (500,102) 1,379,658 - (14,844,199)
Gas Utility Plant (11,142,926) (707,035) 28,528 - (11,821,433)
Fiber Optic Utility Plant (3,123,880) (186,152) 616,583 - (2,693,449)
Total Accumulated Depreciation (151,548,679) (17,904,210) 19,603,658 - (149,849,231)
Total Capital Assets, Being Depreciated,
Net:
Electric Utility - Production Plant 5,431,810 187,539,642 - - 192,971,452
Electric Utility - Transmission Plant 1,463,532 (78,093) (212,164) - 1,173,275
Electric Utility - Distribution Plant 157,224,056 9,343,741 (1,687,845) - 164,879,952
Electric Utility - General Plant 3,439,012 (168,330) - - 3,270,682
W ater Utility Plant 8,041,598 1,166,560 (409,841) 87,755 8,886,072
Gas Utility Plant 15,830,766 (445,529) (6,076) - 15,379,161
Fiber Optic Utility Plant 1,037,498 25,662 - - 1,063,160
Total 192,468,272 197,383,653 (2,315,926) 87,755 387,623,754
Business-Type Activities Capital
Assets, Net 257,253,484$ 203,490,086$ (2,315,926)$ -$ 458,427,644$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(50)
NOTE 5 CAPITAL ASSETS (CONTINUED)
Depreciation expense was charged to the business-type functions as follows:
Electric Fund 16,510,921$
Gas Fund 707,035
Water Fund 500,102
Fiber Optics Fund 186,152
Total Depreciation Expense - Business-
Type Functions 17,904,210$
NOTE 6 LONG-TERM LIABILITIES
Changes in Long-Term Liabilities
The following is a summary of long-term liabilities transactions for the fiscal year ended
June 30, 2022:
Balance Balance Amounts
June 30, 2021 Due Within
Restated (1) Additions Reductions June 30, 2022 One Year
Governmental Activities:
Claims Payable (Note 7)3,409,372$ 2,831,928$ (1,300,568)$ 4,940,732$ 1,646,911$
Compensated Absences (Note 1I)2,505,255 1,597,293 (1,428,618) 2,673,930 891,310
Lease Liability 56,857 - (25,197)31,660 25,313
Total 5,971,484$ 4,429,221$ (2,754,383)$ 7,646,322$ 2,563,534$
Business-Type Activities:
Other Debt:
Bonds Payable 281,475,000$ 235,885,000$ (96,450,000)$ 420,910,000$ 50,360,000$
Bond Premium 7,744,795 38,266,557 (2,680,100) 43,331,252 -
Bond Discount (1,923,931) - 754,988 (1,168,943) -
Notes Payable - Direct Borrowing 1,360,465 - (139,535)1,220,930 139,535
Compensated Absences 1,181,903 805,554 (769,052) 1,218,405 406,135
Total 289,838,232$ 274,957,111$ (99,283,699)$ 465,511,644$ 50,905,670$
(1)The beginning balance was restated to add leases payable due to the implementation of
GASB Statement No. 87, Leases. See Note 1C.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(51)
NOTE 6 LONG-TERM LIABILITIES (CONTINUED)
Compensated Absences
There is no fixed payment schedule for earned but unpaid compensated absences in both
the governmental and business type activities.
Lease Liability
The City leases equipment under a noncancelable lease agreement. The lease expires
October 2023. The net present values of the lease payable was determined using a discount
rate of 0.46%. Monthly lease payments total $2,116.
Total future minimum lease payments under lease agreements are as follows:
Lease Liability
Fiscal Year Ending June 30,Principal Interest
2023 25,313$ 83$
2024 6,347 2
Total Requirements 31,660$ 85$
$43,765,000 Electric System Revenue Bonds (2008 Taxable Series A)
At June 30, 2022, $37,895,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $72,050,772, payable through
fiscal year 2039. For the current year, debt service and net electric revenues were
$4,240,768 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2008 Taxable Series A were issued to provide funds to (i) finance the cost of certain capital
improvements to the City’s Electric System, (ii) fund a deposit to the Debt Service Reserve
Fund, and (iii) to pay costs of issuance of the 2008 Bonds.
$37,640,000 Electric System Revenue Bonds (2012 Series A)
On January 10, 2012, the City issued Electric System Revenue Bonds, 2012 Series A, in the
amount of $37,640,000. The City of Vernon Electric System Revenue Bonds, 2012 Series A
were issued to provide funds to (i) pay a portion of the costs of certain capital improvements
to the City’s Electric System, (ii) to provide for capitalized interest on the 2012 Series A
Bonds, and (iii) to pay costs of issuance of the 2012 Series A Bonds. The Electric System
Revenue Bonds were refunded in the current fiscal year with the issuance of the Electric
System Revenue Bonds 2021 Series A.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(52)
NOTE 6 LONG-TERM LIABILITIES (CONTINUED)
$35,100,000 Electric System Revenue Bonds (2012 Taxable Series B)
On January 10, 2012, the City issued Electric System Revenue Bonds, 2012 Series B, in the
amount of $35,100,000. During the current fiscal year, a portion of the Electric System
Revenue Bonds were refunded with the issuance of the Electric System Revenue Bonds
2022 Series A. At June 30, 2022, $11,505,000 remained outstanding. The bonds are special
obligation bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $12,752,831, payable through
fiscal year 2027. For the current year, debt service and net electric revenues were
$25,817,900 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2012 Taxable Series B were issued to provide funds to (i) refund the $28,680,000 aggregate
principal amount of 2009 Bonds maturing on August 1, 2012, (ii) to pay a portion of the
Costs of the 2012 Project, and (iii) to pay costs of issuance of the 2012 Taxable Series B
Bonds.
$111,720,000 Electric System Revenue Bonds (2015 Taxable Series A)
At June 30, 2022, $111,720,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $124,140,019, payable through
fiscal year 2027. For the current year, debt service and net electric revenues were
$5,087,518 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2015 Taxable Series A were issued to provide funds to (i) refund a portion of the
Outstanding Electric System Revenue Bonds, 2009 Series A; (ii) finance the Costs of certain
Capital Improvements to the City’s Electric System by reimbursing the Electric System for
the prior payment of such Costs from the Light and Power Fund; (iii) fund a deposit to the
Debt Service Reserve Fund; and (iv) pay costs of issuance of the 2015 Bonds.
$71,990,000 Electric System Revenue Bonds (2020 Series A)
At June 30, 2022, $19,305,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $30,319,875, payable through
fiscal year 2038. For the current year, debt service and net electric revenues were
$25,596,000 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2020 Series A were issued to provide funds to (i) to finance the acquisition and construction
of certain capital improvements to the Electric System of the City, (ii) to refund all the City’s
outstanding Electric System Revenue Bonds, 2009 Series A, and (iii) to pay costs of
issuance of the 2020 Bonds.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(53)
NOTE 6 LONG-TERM LIABILITIES (CONTINUED)
$183,815,000 Electric System Revenue Bonds (2021 Series A)
In December 2021, the City of Vernon issued 2021A Electric System Revenue Bonds in the
amount of $183,815,000 (i) to pay the costs of the acquisition by the City of Vernon of a
134-megawatt natural gas-fired generating facility located within the City limits on land
owned by the City, together with certain related electrical interconnection facilities and other
assets, property, and contractual rights; (ii) to fund a deposit to the Debt Service Reserve
Fund in satisfaction of the Debt Service Reserve Requirement; and (iii) to pay costs of
issuance of the 2021 bonds.
The bonds bear interest rates between 4.00%-5.00% that is payable on a semi-annual basis
on April 1 and October 1, commencing April 1, 2022. At June 30, 2022, $173,815,000
remained outstanding. The bonds are special obligation bonds which are secured by an
irrevocable pledge of electric revenues payable to bondholders. The debt service remaining
on the bonds is $207,098,300, payable through fiscal year 2028. For the current year, debt
service and net electric revenues were $12,671,686 and $69,089,394, respectively.
Under the Bond Indenture of Trust, interest and principal on the bonds are payable from Net
Revenues (or Revenues less Operation and Maintenance Expenses) and/or amounts in the
Light and Power Enterprise (as those terms are defined in the Indenture of Trust). The City
of Vernon Electric System Revenue Bonds, 2021 Series A were issued to (i) refund and
defease all of the City’s outstanding Electric System Revenue Bonds, 2012 Series A and a
portion of the City’s outstanding Electric System Revenue bonds, 2012 Taxable Series B
and (ii) pay costs of issuance of the 2022 Bonds.
$52,070,000 Electric System Revenue Bonds (2022 Series A)
In December 2021, the City of Vernon issued 2022A Electric System Revenue Bonds in the
amount of $52,070,000 to refund the 2012A Electric System Revenue Bonds, a portion of
the 2012B Electric Revenue Bonds, and provide for the costs of issuing the bonds.
The bonds bear interest rates between 4.00%-5.00% that is payable on a semi-annual basis
beginning February 1 and August 1, commencing on August 1, 2022. At June 30, 2022,
$52,070,000 remained outstanding. The bonds are special obligation bonds which are
secured by an irrevocable pledge of electric revenues payable to bondholders. The debt
service remaining on the bonds is $78,789,447, payable through fiscal year 2042. For the
current year, debt service and net electric revenues were $0 and $69,089,394, respectively.
Under the Bond Indenture of Trust, interest and principal on the bonds are payable from Net
Revenues (or Revenues less Operation and Maintenance Expenses) and/or amounts in the
Light and Power Enterprise (as those terms are defined in the Indenture of Trust). The City
of Vernon Electric System Revenue Bonds, 2021 Series A were issued to (i) refund and
defease all of the City’s outstanding Electric System Revenue Bonds, 2012 Series A and a
portion of the City’s outstanding Electric System Revenue bonds, 2012 Taxable Series B
and (ii) pay costs of issuance of the 2022 Bonds.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(54)
NOTE 6 LONG-TERM LIABILITIES (CONTINUED)
$14,840,000 Water System Revenue Bonds (2020 Series A)
At June 30, 2022, $14,600,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of water revenues payable to
bondholders. The debt service remaining on the bonds is $25,040,038, payable through
fiscal 2051. For the current year, debt service and net water revenues were $827,975 and
$3,194,732, respectively. Under the Indenture of Trust dated May 6, 2020, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Water Enterprise (as those terms are
defined in the Indenture of Trust).
A summary of bonds payable for business-type activities is as follows:
Fixed Annual Original
Interest Principal Issue Outstanding
Bonds Maturity Rates Installments Amount June 30, 2022
City of Vernon 07/01/38 7.40% - To begin 07/01/10: 43,765,000$ 37,895,000$
Electric System Revenue Bonds,8.59%$265,000 -
2008 Taxable Series A $4,065,000
City of Vernon 08/01/26 6.25% - To begin 08/01/22: 35,100,000 11,505,000
Electric System Revenue Bonds,6.50% $6,165,000 -
2012 Taxable Series B $7,940,000
City of Vernon 08/01/26 4.05% - To begin 08/01/23: 111,720,000 111,720,000
Electric System Revenue Bonds,4.85% $15,925,000 -
2015 Taxable Series A $22,540,000
City of Vernon 08/01/50 5.00% To begin 08/03/20: 71,990,000 19,305,000
Electric System Revenue Bonds,$1,525,000 -
2020 Taxable Series A $28,655,000
City of Vernon 04/01/28 4% - To begin 04/01/22: 183,815,000 173,815,000
Electric System Revenue Bonds,5.00% $10000,000 -
2021 Taxable Series A $54,915,000
City of Vernon 08/01/41 5.00% To begin 05/05/22: 52,070,000 52,070,000
Electric System Revenue Bonds,$950,000 -
2022 Taxable Series A $5,850,000
Premiums 42,376,244
Discounts (1,098,956)
Total Electric System
Revenue Bonds 447,587,288
Water System:
City of Vernon 08/01/50 5.00% To begin 08/01/21: 14,840,000 14,600,000
Water System Revenue Bonds, $240,000 -
2020 Taxable Series A $3,785,000
Premium 535,833
Total Water System
Revenue Bonds 15,135,833
Total Revenue Bonds 462,723,121$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(55)
NOTE 6 LONG-TERM LIABILITIES (CONTINUED)
Note Payable – Direct Borrowing
In May 2019, the City entered into an agreement with Water Replenishment District of
Southern California (WRD) for assistance with the construction of a new groundwater well or
rehabilitation of an existing groundwater well. The promissory note is unsecured and has no
interest basis for an amount not to exceed $1,500,000. As of June 30, 2022, WRD has
disbursed all of the funds under the agreement to the City. The note is payable in quarterly
principal payments commencing September 1, 2020, in an amount which, together with all
quarterly payments, will be sufficient to fully amortize the principal balance of the note by the
maturity date of April 1, 2031.
Upon an event of default, WRD may declare any or all of the outstanding and unpaid
principal balance immediately due and payable, without presentment, demand, protest,
notice of protest, notice of acceleration or of intention to accelerate or any other notice,
declaration or act of any kind, all of which are hereby expressly waived by the City.
Business-Type Activities Debt Service Requirements
As of June 30, 2022, annual debt service requirements of business-type activities to maturity
are as follows:
Electric System Revenue Bonds
2008 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 1,025,000$ 3,211,156$
2024 1,120,000 3,119,029
2025 1,220,000 3,018,526
2026 1,330,000 2,909,004
2027 1,450,000 2,789,603
2028-2032 9,445,000 11,747,040
2033-2037 14,510,000 6,677,437
2038-2041 7,795,000 683,979
Total Requirements 37,895,000$ 34,155,772$
Electric System Revenue Bonds
2012 Taxable Series B
Fiscal Year Ending June 30,Principal Interest
2023 6,165,000$ 531,831$
2024 1,170,000 302,613
2025 1,305,000 225,269
2026 1,390,000 140,181
2027 1,475,000 47,938
Total Requirements 11,505,000$ 1,247,832$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(56)
NOTE 6 LONG-TERM LIABILITIES (CONTINUED)
Business-Type Activities Debt Service Requirements (Continued)
Electric System Revenue Bonds
2015 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 22,540,000$ 4,580,368$
2024 23,520,000 3,596,938
2025 24,585,000 2,530,618
2026 25,780,000 1,341,193
2027 15,295,000 370,904
Total Requirements 111,720,000$ 12,420,019$
Electric System Revenue Bonds
2020 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 -$ 965,250$
2024 - 965,250
2025 - 965,250
2026 - 965,250
2027 - 965,250
2028-2032 6,585,000 4,188,125
2033-2037 10,325,000 1,940,625
2038-2041 2,395,000 59,875
Total Requirements 19,305,000$ 11,014,875$
Electric System Revenue Bonds
2021 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 20,380,000$ 8,385,050$
2024 21,335,000 7,405,125
2025 22,400,000 6,325,000
2026 23,530,000 5,190,875
2027 31,255,000 3,917,875
2028-2032 54,915,000 2,059,375
Total Requirements 173,815,000$ 33,283,300$
Electric System Revenue Bonds
2022 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 -$ 1,923,697$
2024 4,690,000 2,486,250
2025 4,885,000 2,246,875
2026 5,130,000 1,996,500
2027 5,405,000 1,733,125
2028-2032 5,270,000 7,357,500
2033-2037 6,765,000 5,860,625
2038-2042 19,925,000 3,114,875
Total Requirements 52,070,000$ 26,719,447$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(57)
NOTE 6 LONG-TERM LIABILITIES (CONTINUED)
Business-Type Activities Debt Service Requirements (Continued)
Water System Revenue Bonds
2020 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 250,000$ 575,725$
2024 265,000 562,850
2025 275,000 549,350
2026 - 542,475
2027 - 542,475
2028-2032 1,985,000 2,563,500
2033-2037 2,180,000 2,052,625
2038-2042 2,680,000 1,535,450
2043-2047 3,180,000 1,051,925
2048-2051 3,785,000 463,663
Total Requirements 14,600,000$ 10,440,038$
Note Payable
Fiscal Year Ending June 30,Principal Interest
2023 139,535$ -$
2024 139,535 -
2025 139,535 -
2026 139,535 -
2027 139,535 -
2028-2031 523,256 -
Total Requirements 1,220,930$ -$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(58)
NOTE 6 LONG-TERM LIABILITIES (CONTINUED)
Expense Stabilization Fund
The City maintains an Expense Stabilization Fund held by a Trustee in such amounts, at
such times and from sources as shall be determined by the City in its sole discretion. In the
event of default under the Indenture shall have occurred and is continuing, the Trustee shall
transfer all moneys in the fund to the debt service funds as provided in the Indenture.
Moneys on deposit in this fund may be withdrawn by the City at any time no event of default
exists under the Indenture. As at June 30, 2022, this fund has a balance of $38,934,149.
Right to Accelerate Upon Default
Notwithstanding anything contrary in the Indenture or in the Bonds, upon the occurrence of
an Event of Default, the Trustee may, with the consent of each Credit Provider whose
consent is required by a Supplemental Indenture or a Credit Support Agreement, and shall,
at the direction of the Owners of a majority in principal amount of Outstanding Bonds (other
than Bonds owned by or on behalf of the City) by written notice to the City, declare the
principal of the Outstanding Bonds and the interest thereon to be immediately due and
payable, whereupon such principal and interest shall, without further action, become and be
immediately due and payable.
Credit Ratings
As of June 30, 2022, the ratings on all Electric System Revenue Bonds is BBB+ by S&P and
Baa2 by Moody’s and the ratings on all Water System Revenue Bonds is AA by S&P and
not rated by Moody’s.
Line of Credit
As at June 30, 2022, the City does not have a line of credit with a financial institution.
NOTE 7 RISK MANAGEMENT
The City is exposed to various risks of loss related to torts; theft of, damage to, and
destruction of assets, errors, and omissions; injuries to employees, and natural disasters.
The City utilizes insurance policy(s) to transfer these risks. Each policy has either self-
insured retention or deductible, which are parts of our Risk Financing Program. There have
been no significant settlements or reductions in insurance coverage during the past three
fiscal years.
Starting in Fiscal 2010, the City chose to establish the Risk Financing Program in the
General Fund, whereby assets are set aside for claim-litigation settlements associated with
the above-mentioned risks up to their self-insured retentions or policy deductibles. Athens
Administrators Inc. is our Third-Party Administrator for the City’s workers’ compensation
program and they provide basic services for general liability claims and litigation.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(59)
NOTE 7 RISK MANAGEMENT (CONTINUED)
The insurance limits for the fiscal year 2022 are as follows (amounts in thousands):
Deductible/SIR
Insurance Type Program Limits (Self-Insured Retention)
Excess Liability Insurance $20,000,000 $2,000,000 SIR per occurrence
D and O Employment Practice $2,000,000 $150,000 SIR nonsafety; $150,000 SIR safety
Excess Workers Compensation $50,000,000 $1,500,000 SIR per occurrence for presumptive loss
Employer's Liability $1,000,000 $1,000,000 SIR per occurrence for all employees
Commercial Property Insurance $100,000,000 $25,000 except:
$25,000,000 Flood Sublimit $250,000 power stations
$1.5/kVA transfers, subject to a $250,000 minimum
$500,000 named transformers
Employee Dishonest - Crime $1,000,000 $25,000
Pollution - Site Owned $5,000,000 $25,000 for nonutility locations, divested locations
and scheduled storage tanks
$50,000 for utility locations
$100,000 for natural gas pipeline
Cyber Liability $3,000,000 $100,000
Contractors Equipment/Auto $10,000,000 Maximum Loss Per Occurrence $5,000
Physical Damage $1,000,000 Equipment Limit-loss or damage to
any one piece
Residential Property Insurance $8,023,126 Blanket Building Limit $2,500
$89,013 Blanket Business Personal Property Limit
Terrorism and Sabotage $100,000,000 Policy Aggregate N/A
$5,000,000 Active Shooter and Malicious Attack
Per Occurrence/Aggregate
$5,000,000 Terrorism and Sabotage Liability
Per Occurrence/Aggregate
The City has numerous claims and pending litigations, which generally involve accidents
and/or liability or damage to City property. The balance of claims/litigations against the City
is in the opinion of management, ordinary routine matters, incidental to the normal business
conducted by the City. In the opinion of management, such proceedings are substantially
covered by insurance, and the ultimate dispositions of such proceedings are not expected to
have a material adverse effect on the City’s financial position, results of operations or cash
flows.
Changes in the balance of claims liabilities for the past two fiscal years for all self-insurance
activities combined are as follows:
2022 2021
Claims Payable, Beginning of Fiscal Year 3,409,372$ 3,840,080$
Incurred Claims and Change in Estimates 2,831,928 836,537
Claims Payments (1,300,568) (1,267,245)
Claims Payable, End of Fiscal Year 4,940,732$ 3,409,372$
NOTE 8 PENSION PLANS
The following is a summary of pension related items for the year ended June 30, 2022:
Deferred Deferred
Pension Outflows Inflows Pension
Liability of Resources of Resources Expense
Miscellaneous 28,268,856$ 7,936,320$ (14,256,658)$ 3,150,422$
Safety 59,761,800 20,436,938 (41,139,301) 5,288,917
Total 88,030,656$ 28,373,258$ (55,395,959)$ 8,439,339$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(60)
NOTE 8 PENSION PLAN (CONTINUED)
A. General Information About the Pension Plans
On October 1, 2020, the City transferred its fire department operations to Los Angeles
County, California. The City’s full-time safety (police and fire personnel) employees were
converted from the City’s agent multiple-employer defined benefit pension plan to a cost-
sharing defined benefit pension plan during the fiscal year ended June 30, 2021. See
Note 10 for further information.
Plan Descriptions
All full-time safety and miscellaneous personnel and temporary or part-time employees
who have worked a minimum of 1,000 hours in a fiscal year are eligible to participate in
the City’s cost-sharing and agent multiple-employer defined benefit pension Safety and
Miscellaneous Plans, respectively, administered by the California Public Employees’
Retirement System (CalPERS) that acts as a common investment and administrative
agent for participating public entities within the state of California. Benefits vest after five
years of service. Employees who retire at the minimum retirement age with five years of
credited service are entitled to retirement benefits. Monthly retirement benefits are based
on a percentage of an employee’s average compensation for his or her highest
consecutive 12 or 36 months of compensation for each year of credited service.
Benefits Provided
Miscellaneous members hired prior to January 1, 2013, with five years of credited
service may retire at age 55 based on a benefit factor derived from the 2.7% at 55
Miscellaneous formula or may retire between ages 50 and 54 with reduced retirement
benefits. New Miscellaneous members (PEPRA) with five years of credited service may
retire at age 62 based on a benefit factor derived from the 2% at 62 Miscellaneous
formula or may retire between age 52 and 61 with reduced retirement benefits. The
benefit factor increases to a maximum of 2.5% at age 67. Safety members with five
years of credited service may retire at age 50 based on a benefit factor derived from the
3% at 50 Safety formula for sworn Police and Fire Department employees. New Safety
members (PEPRA) with five years of credited service may retire at age 57 based on a
benefit factor derived from the 2.7% at 57 Safety (PEPRA) formula or may retire
between age 50 and 56 with reduced retirement benefits for new Safety (PEPRA)
members of both Police and Fire Departments. CalPERS also provides death and
disability benefits. These benefit provisions and all other requirements are established
by State statute provided through a contract between the City and CalPERS.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(61)
NOTE 8 PENSION PLAN (CONTINUED)
A. General Information About the Pension Plans (Continued)
Benefits Provided (Continued)
The Plans’ provisions and benefits in effect as of the measurement date of June 30,
2021, are summarized as follows:
Miscellaneous
Prior to On or After
Hire Date January 1, 2013 January 1, 2013
Benefit Formula 2.7%@55 2%@62
Benefit Vesting Schedule 5 Years of Service 5 Years of Service
Benefit Payments Monthly for Life Monthly for Life
Retirement Age5052
Monthly Benefits, as a Percent of Eligible Compensation 2.0% to 2.7% 1.0% to 2.5%
Required Employee Contribution Rates 8.000%6.250%
Required Employer Contribution Rates:
Normal Cost Rate 11.380% 11.380%
Payment of Unfunded Liability 3,924,540$ -$
Safety
Prior to On or After
Hire Date January 1, 2013 January 1, 2013
Benefit Formula 3.0%@50 2.7%@57
Benefit Vesting Schedule 5 Years of Service 5 Years of Service
Benefit Payments Monthly for Life Monthly for Life
Retirement Age5050
Monthly Benefits, as a Percent of Eligible Compensation 3%2.0% to 2.7%
Required Employee Contribution Rates 9.000%13.750%
Required Employer Contribution Rates:
Normal Cost Rate 22.780% 22.780%
Payment of Unfunded Liability 7,063,113$ 15,563$
Employees Covered
At June 30, 2022, the following employees were covered by the benefit terms for each
Plan:
Miscellaneous Safety
Inactive Employees or Beneficiaries Currently
Receiving Benefits 243 262
Inactive Employees Entitled to But Not Yet
Receiving Benefits 215 132
Active Employees 161 41
Total 619 435
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(62)
NOTE 8 PENSION PLAN (CONTINUED)
A. General Information About the Pension Plans (Continued)
Contributions
Section 20814(c) of the California Public Employees’ Retirement Law requires that the
employer contribution rates for all public employers be determined on an annual basis by
the actuary and shall be effective on July 1 following notice of a change in the rate.
Funding contributions for both Plans are determined annually on an actuarial basis as of
June 30 by CalPERS. The actuarially determined rate is the estimated amount
necessary to finance the costs of benefits earned by employees during the year, with an
additional amount to finance any unfunded accrued liability (UAL). The City is required to
contribute to the difference between the actuarially determined rate and the contribution
rate of employees.
Contributions for the fiscal year ended June 30, 2022, included $11,003,216 for the UAL
and $3,213,343 for the normal cost rate resulting in a total amount paid of $14,216,559.
B. Net Pension Liability
The City’s net pension liability for each Plan is measured as the total pension liability,
less the pension plan’s fiduciary net position. The net pension liability of each of the
Plans is measured as of June 30, 2021, using an annual actuarial valuation as of
June 30, 2020, rolled forward to June 30, 2021, using standard update procedures. A
summary of principal assumptions and methods used to determine the net pension
liability is shown below.
Actuarial Assumptions
The total pension liabilities in the June 30, 2021 actuarial valuations were determined
using the following actuarial assumptions:
Miscellaneous Safety
Valuation Date June 30, 2020 June 30, 2020
Measurement Date June 30, 2021 June 30, 2021
Actuarial Cost Method Entry Age Normal Entry Age Normal
Actuarial Assumptions:
Discount Rate 7.15% 7.15%
Inflation 2.500% 2.500%
Payroll Growth 2.750%2.750%
Projected Salary Increase (1)(1)
Mortality Rate Table (2)(2)
Post-Retirement Benefit Increase (3)(3)
(1)Varies by entry age and service.
(2)The mortality table used was developed based on CalPERS-specific data. The
probabilities of mortality are based on the 2017 CalPERS Experience Study for the
period from 1997 to 2015. Pre-retirement and Post-retirement mortality rates includes
15 years of projected mortality improvement using 90% of Scale MP-2016 published by
the Society of Actuaries. For more details on this table, please refer to the CalPERS
Experience Study and Review of Actuarial Assumptions report from December 2017
that can be found on the CalPERS website.
(3)The lessor of contract COLA or 2.50% until Purchasing Power Protection Allowance Floor
on purchasing power applies, 2.50% thereafter.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(63)
NOTE 8 PENSION PLAN (CONTINUED)
B. Net Pension Liability (Continued)
Long-Term Expected Rate of Return
The long-term expected rate of return on pension plan investments was determined
using a building-block method in which expected future real rates of return (expected
returns, net of pension plan investment expense and inflation) are developed for each
major asset class.
In determining the long term expected rate of return, CalPERS took into account both
short term and long term market return expectations as well as the expected pension
fund cash flows. Using historical returns of all the funds’ asset classes, expected
compound (geometric) returns were calculated over the short term (first 10 years) and
the long-term (11+ years) using a building block approach. Using the expected nominal
returns for both short term and long term, the present value of benefits was calculated
for each fund. The expected rate of return was set by calculating the rounded single
equivalent expected return that arrived at the same present value of benefits for cash
flows as the one calculated using both short term and long term returns. The expected
rate of return was then set equal to the single equivalent rate calculated above and
adjusted to account for assumed administrative expenses.
The expected real rates of return by asset class are as follows:
Assumed Real Return Real Return
Asset Years Years
Allocation 1 - 10 (b)11+ (c)
Global Equity 50.00 %4.80 %5.98 %
Fixed Income 28.00 1.00 2.62
Inflation Assets -0.77 1.81
Private Equity 8.00 6.30 7.23
Real Assets 13.00 3.75 4.93
Liquidity 1.00 -(0.92)
Total 100.00 %
(a)
(b) An expected inflation of 2.0% used for this period.
(c) An expected inflation of 2.92% used for this period.
In the CalPERS ACFR, Fixed Income is included in Global Debt Securities; Liquidity is
included in Short-term Investments; Inflation Assets are included in both Global Equity
Securities and Global Debt Securities.
Asset Class (a)
Discount Rate
The discount rate used to measure the total pension liability was 7.15%. The projection
of cash flows used to determine the discount rate assumed that contributions from plan
members will be made at the current member contribution rates and that contributions
from employers will be made at statutorily required rates, actuarially determined. Based
on those assumptions, the Plan’s fiduciary net position was projected to be available to
make all projected future benefit payments of current plan members. Therefore, the
long-term expected rate of return on plan investments was applied to all periods of
projected benefit payments to determine the total pension liability.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(64)
NOTE 8 PENSION PLAN (CONTINUED)
B. Net Pension Liability (Continued)
Subsequent Events
On July 12, 2021, CalPERS reported a preliminary 21.3% net return on investments for
fiscal year 202-21. Based on the thresholds specified in CalPERS Funding Risk
Mitigation policy, the excess return of 14.3% prescribes a reduction in investment
volatility that corresponds to a reduction in the discount rate used for funding purposes
of 0.20%, from 7.00% to 6.80%. Since CalPERS was in the final stages of the four-year
Asset Liability Management (ALM) cycle, the board elected to defer any changes to the
asset allocation until the ALM process concluded, and the board could make its final
decision on the asset allocation in November 2021.
On November 17, 2021, the board adopted a new strategic asset allocation. The new
asset allocation along with new capital market assumptions, economic assumptions and
administrative expense assumption support a discount rate of 6.90% (net of investment
expense but without a reduction for administrative expense) for financial reporting
purposes. This includes a reduction in the price inflation assumption from 2.50% to
2.30% as recommended in the November 2021 CalPERS Experience Study and Review
of Actuarial Assumptions. This study also recommended modifications to retirement
rates, termination rates, mortality rates and rates of salary increases that were adopted
by the board. These new assumptions will be reflected in the GASB 68 account
valuation reports for the June 30, 2022 measurement date.
C.Changes in the Net Pension Liability
The changes in the Net Pension Liability for the Miscellaneous Plan over the
measurement period follows:
Increase (Decrease)
Total Plan Net Pension
Pension Fiduciary Liability
Liability Net Position
Miscellaneous Plan:
Balance at June 30, 2020 (Measurement
Date) 184,953,577$ 138,335,116$ 46,618,461$
Changes in the Year:
Service Cost 2,735,636 -2,735,636
Interest on the Total Pension Liability 13,153,255 -13,153,255
Differences Between Expected and
Actual Experience 1,777,340 -1,777,340
Contribution - Employer -4,979,542 (4,979,542)
Contribution - Employee -1,161,711 (1,161,711)
Net Investment Income -30,012,771 (30,012,771)
Benefit Payments, Including Refunds
of Employee Contributions (8,274,278) (8,274,278) -
Administrative Expenses -(138,188)138,188
Net Changes 9,391,953 27,741,558 (18,349,605)
Balance at June 30, 2021 (Measurement
Date)194,345,530$ 166,076,674$ 28,268,856$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(65)
NOTE 8 PENSION PLAN (CONTINUED)
C.Changes in the Net Pension Liability (Continued)
The City reported a net pension liability for its proportionate share of the net pension
liability of the safety plan as of June 30, 2022, in the amount of $59,761,800.
The City’s net pension liability for the safety plan is measured as the proportionate share
of the net pension liability of the CalPERS cost sharing pool. The City’s net pension
liability of the Plan is measured as of June 30, 2021, and the total pension liability for the
safety plan used to calculate the net pension liability was determined by an actuarial
valuation as of June 30, 2020, rolled forward to June 30, 2021, using standard update
procedures. The City’s proportion of the net pension liability was based on a projection
of the City’s long-term share of contributions to the pension plan relative to the projected
contributions of all participating employers, actuarially determined.
The City’s proportionate share of the net pension liability for the safety plan as of
June 30, 2020 and 2022 measurement dates was as follows:
Safety
Proportion - June 30, 2020 1.33110 %
Proportion - June 30, 2021 1.70286
Change - Increase (Decrease) 0.37176 %
Sensitivity of the Net Pension Liability to Changes in the Discount Rate
The following presents the net pension liability of the City for each Plan, calculated using
the discount rate for each Plan, as well as what the City’s net pension liability would be if
it were calculated using a discount rate that is a one percentage point lower or a one
percentage point higher than the current rate:
Miscellaneous Safety
One Percent Decrease 6.15%6.15%
Net Pension Liability 55,565,615$ 99,454,775$
Current Discount Rate 7.15%7.15%
Net Pension Liability 28,268,856$ 59,761,800$
One Percent Increase 8.15%8.15%
Net Pension Liability 5,909,752$ 27,158,923$
Pension Plan Fiduciary Net Position
Detailed information about each pension plan’s fiduciary net position is available in the
separately issued CalPERS financial reports.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(66)
NOTE 8 PENSION PLAN (CONTINUED)
D.Pension Expenses and Deferred Outflows/Inflows of Resources Related to
Pensions
For the measurement period ended June 30, 2021, the City recognized pension expense
of $3,150,422 related to the miscellaneous plan and $5,288,917 related to the safety
plan. At June 30, 2022, the City reported deferred outflows of resources and deferred
inflows of resources related to pensions from the following sources:
Miscellaneous Plan Safety Plan Total
Deferred Deferred Deferred Deferred Deferred Deferred
Outflows of Inflows of Outflows of Inflows of Outflows of Inflows of
Resources Resources Resources Resources Resources Resources
Pension Contributions Subsequent
to Measurement Date 5,957,671$ -$ 8,258,888$ -$14,216,559$ -$
Differences Between Expected and
Actual Experience 1,978,648 -10,210,224 -12,188,872 -
Change in Assumptions - - - -- -
Net Differences Between Projected
and Actual Earnings on Plan
Investments - (14,256,658) -(35,569,658)-(49,826,316)
Change in Employer's Proportion and
Differences Between the Employer's
Contributions and the Employer's - -
Proportionate Share of Contributions - - 1,967,827 (5,569,643) 1,967,827 (5,569,643)
Total 7,936,319$ (14,256,658)$ 20,436,939$ (41,139,301)$ 28,373,258$ (55,395,959)$
The $14,216,559 reported as deferred outflows of resources related to contributions
subsequent to the measurement date will be recognized as a reduction of the net
pension liability in the year ended June 30, 2023. Other amounts reported as deferred
outflows of resources and deferred inflows of resources related to pensions will be
recognized as pension expense as follows:
Fiscal Year Ended June 30,Miscellaneous Safety Total
2023 (2,128,886)$ (5,309,183)$ (7,438,069)$
2024 (2,660,978) (5,836,729) (8,497,707)
2025 (3,443,913) (8,027,111) (11,471,024)
2026 (4,044,233) (9,788,227) (13,832,460)
2027 - - -
E. Payable to the Pension Plan
At June 30, 2022, the City had no outstanding amount of contributions to the pension
plans required for the year ended June 30, 2022.
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB)
A.General Information About the OPEB Plan
Plan Description
Retiree medical and dental benefits are established through the City’s Fringe Benefits
and Salary Resolution as well as individual memoranda of understanding between the
City and the City’s various employee bargaining groups.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(67)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
A. General Information About the OPEB Plan (Continued)
Benefits Provided
Generally, the City will provide a postemployment benefit plan for the employee only to
those who retire at age sixty (60) or later with twenty (20) years of continuous
uninterrupted service up to the age of sixty-five (65). Alternatively, employees who retire
before the age of sixty (60) with twenty (20) years of continuous uninterrupted service,
will be permitted to pay their medical and dental premium cost and upon reaching the
age of fifty (50), the City will pay the premium for the medical and dental plans until they
reach the age of sixty-five (65).
Resolution 2011-129 provided lifetime medical benefits to Police Management
employees and their spouses, who have been employed as sworn safety personnel for a
minimum of twenty (20) years and a minimum of ten (10) years of that services have
been with the City of Vernon. Resolution 2011-127 sets forth the Memorandum of
Understanding of the Vernon Police Officers’ Benefit Association, provided lifetime
medical benefits to those employees and their spouses, who have been employed as
sworn safety personnel for a minimum of twenty (20) years and a minimum of ten (10)
years of that service has been with the City of Vernon. Resolution 2012-217 granted
specific retiree medical benefits to employees who retire during the 2012-2013 fiscal
year in order to provide an incentive for early retirement whereby the City authorized the
payment of medical and dental insurance premiums for eligible retiring employees and
their eligible dependents with at least ten (10) years of service plus 5% for each
additional full year of service above the ten (10) years of service, and that this offer be
extended as an option to safety and safety management groups, at their discretion, in
addition to the related options provided in the Vernon Firefighters Association
Memorandum of Understanding and the Vernon Police Officers’ Benefit Association
Memorandum of Understanding. Resolution 2013-06 declared that the retiree medical
benefits which had not been a vested right for employees will continue to be nonvested
right for employees who continue to be employed by the City on or after July 1, 2013, but
will become a vested right for those who retire during the 2012-2013 fiscal year. The
City’s plan is considered a substantive OPEB plan and the City recognizes cost in
accordance with GASB Statement No 75. The City may terminate its unvested OPEB in
the future.
Funding Policy and Contributions
The City has established an irrevocable OPEB trust with assets dedicated to paying
future retiree medical benefits. The City intends to contribute 100% or more of the
actuarially determined contribution for the explicit subsidy liability only. The portion of the
liability due to the implicit subsidy is not prefunded but is paid as benefits come due.
For the year ended June 30, 2022, the City contributed $1,538,693 to the trust, paid
$905,939 for retiree premiums, and the estimated implied subsidy was $433,399,
resulting in a total contribution of $2,878,031.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(68)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
A. General Information About the OPEB Plan (Continued)
Employees Covered by Benefit Terms
At June 30, 2022, the following employees were covered by the benefit terms:
Category Count
Active Employees 208
Inactive Employees or Beneficiaries Currently
Receiving Benefit Payments 115
B. Net OPEB Liability
The City’s net OPEB liability is measured as of June 30, 2021, and the total OPEB
liability used to calculate the net OPEB liability was determined by an actuarial valuation
as of June 30, 2020. A summary of the principal assumptions and methods used to
determine the total OPEB liability is shown below.
Actuarial Assumptions
The valuation has been prepared on a closed group basis. Assumptions such as age-
related healthcare claims, healthcare trends, retiree participation rates, and spouse
coverage, were selected based on demonstrated plan experience and the best estimate
of expected future experience.
The total OPEB liability in the June 30, 2020, actuarial valuation was rolled forward to
the June 30, 2021, measurement date using standard actuarial techniques. Explicit
subsidy benefit payments by employee group were allocated based on expected benefit
payments. The following actuarial assumptions, applied to all periods included in the
measurement unless otherwise specified:
Funding Method Entry age normal level percent of pay cost method
Inflation 2.25%
Salary Increases 2.75% annual increases
Long-Term Return on Assets 6.25% net of investment expenses
Discount Rate 6.25%
Healthcare Cost Trend Rates
Mortality
6.3% for FY2021, gradually decreasing over several
decades to ultimate rate of 3.8% in FY76 and later years
2017 CalPERS Experience Study. Tables include 15
years of static mortality improvement using 90% of scale
MP-2016
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(69)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
B.Net OPEB Liability (Continued)
Long-Term Expected Rate of Return
The long-term expected rate of return was determined using a building-block method in
which best-estimate ranges of expected future real rates of return (expected returns, net
of OPEB plan investment expense and inflation) are developed for each major asset
class. These ranges are combined to produce the long-term expected rate of return by
weighing the expected future real rates of return by the target asset allocation
percentage and by adding expected inflation. Best estimates of arithmetic real rates of
return for each major asset class included in the OPEB plan’s target asset allocation as
of June 30, 2021 are summarized in the following table:
Long-Term
Target Expected Real
Asset Class Allocation Rate of Return
CERBT Strategy 1:
Equity 59.00 %4.42 %
Fixed Income 25.00 1.00
TIPS 5.00 0.15
Commodities 3.00 3.98
REITs 8.00 1.73
Total 100.00 %
Discount Rate
The discount rate used to measure the total OPEB liability was 6.25%. The projection of
cash flows used to determine the discount rate assumed that City’s contributions will be
made at rates equal to the actuarially determined contribution rates. Based on those
assumptions, the fiduciary net position was projected to be available to make all
projected OPEB payments for current active and inactive employees and beneficiaries.
Therefore, the long-term expected rate of return on plan investments was applied to all
periods of projected benefit payments to determine the total OPEB liability.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(70)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
B.Net OPEB Liability (Continued)
Change in the Net OPEB Liability
Increase (Decrease)
Total Plan Net OPEB
OPEB Fiduciary Liability
Liability Net Position
Balance at June 30, 2020 (Measurement Date) 27,215,028$ 7,003,178$ 20,211,850$
Changes in the Year:
Service Cost 303,057 - 303,057
Interest on the Total OPEB Liability 1,682,954 - 1,682,954
Differences Between Actual and
Expected Experience (677,446) - (677,446)
Changes in Assumptions 66,075 - 66,075
Changes of Benefit Terms -
Investment Income - 2,084,288 (2,084,288)
Contribution - Employer - 3,131,526 (3,131,526)
Benefit Payments (1,199,826) (1,199,826) -
Administrative Expenses - (2,958) 2,958
Net Changes 174,814 4,013,030 (3,838,216)
Balance at June 30, 2021 (Measurement Date) 27,389,842$ 11,016,208$ 16,373,634$
Change of Assumptions
There were no changes of assumptions.
Change of Benefit Terms
There were no changes of benefit terms.
Subsequent Events
There were no subsequent events that would materially affect the results presented in
this disclosure.
Sensitivity of the Net OPEB Liability to Changes in the Discount Rate
The following presents the City’s net OPEB liability if it were calculated using a discount
rate that is 1% point lower or 1% point higher than the current rate:
Discount Rate
One Percent One Percent
Decrease Current Rate Increase
(5.25%) (6.25%) (7.25%)
Net OPEB liability 19,437,875$ 16,373,634$ 13,799,250$
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(71)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
B.Net OPEB Liability (Continued)
Sensitivity of the Net OPEB Liability to Changes in the Healthcare Cost Trend Rates
The following presents the City’s net OPEB liability if it were calculated using a
healthcare cost trend rates that are 1% point lower (5.3% decreasing to an ultimate rate
of 2.8%) or 1% point higher (7.3% decreasing to an ultimate rate of 4.8 %) than the
current rate:
Healthcare Trend Rate
One Percent One Percent
Decrease Current Rate Increase
Net OPEB liability 15,079,060$ 16,373,634$ 17,660,423$
OPEB Expense and Deferred Inflows and Outflows of Resources Related to OPEB
For the year ended June 30, 2022, the City recognized OPEB expense(revenue) of
$(843,086). At June 30, 2022, the City reported deferred outflows of resources and
deferred inflows of resources related to OPEB from the following sources:
Deferred Deferred
Outflows Inflows
of Resources of Resources
Contributions Between Measurement Date and
Reporting Date 2,933,295$ -$
Difference Between Expected and Actual Experience 138,780 (3,529,083)
Changes in Assumptions 446,908 (3,749,862)
Net Differences Between Projected and Actual
Earnings on Investments - (1,106,933)
Total 3,518,983$ (8,385,878)$
The $2,933,295 reported as deferred outflows of resources related to contributions
subsequent to the measurement date will be recognized as a reduction of the net OPEB
liability in the year ended June 30, 2023. Other amounts reported as deferred outflows of
resources and deferred inflows of resources related to OPEB will be recognized as
OPEB expense as follows:
Deferred
Outflows
(Inflows)
Fiscal Year Ending June 30,of Resources
2022 (2,335,409)$
2023 (2,344,060)
2024 (2,330,268)
2025 (628,401)
2026 (74,715)
Thereafter (87,337)
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(72)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
B.Net OPEB Liability (Continued)
Payable to the OPEB Plan
At June 30, 2022, the City had no outstanding amount of contributions to the OPEB plan
required for the year ended June 30, 2022.
NOTE 10 VERNON PUBLIC UTILITIES OPERATIONS AND COMMITMENTS
Bicent Agreements
Asset Sale
On December 13, 2007, the City entered into an Amended and Restated Purchase and
Sale Agreement (the Bicent Agreement), with Bicent (California) Power LLC (Bicent),
which is an affiliate of Bicent Holdings and Natural Gas Partners, to sell to Bicent the
Malburg Generating Station (MGS) and the economic burdens and benefits of the City’s
interests in 22 MW from the Hoover Dam Uprating Project for $287,500,000. This
transaction closed on April 10, 2008.
Bicent agreed to sell the capacity and the energy of the MGS to the City on the terms set
forth in a Power Purchase Tolling Agreement, by and between the City and Bicent, dated
as of April 10, 2008 (the PPTA). City treated the PPTA as an asset lease-back
transaction due to a 30-year ground lease between the City and BCM by deferring most
of the gain from the sale of MGS to be amortized over the 15-year life of the PPTA. The
City also deferred the gain from the CFD to be amortized over the 10-year life of the
CFD.
On December 15, 2021, the City made the determination to reacquire MGS to achieve
potential costs savings and other resource management benefits. In addition to the
potential savings, the City expects there to be other benefits associated with the
acquisition of MGS, which includes having control of the facility and the site, providing
the City with flexibility with respect to the MGS operations and MGS’s role in the City’s
resource portfolio. The City issued Electric System Revenue Bonds, 2021 Series A and
Electric System Revenue Bonds, 2022 Series A in 2022 to finance the acquisition. (See
Note 6)
Southern California Public Power Authority
In 1980, the City entered into a joint powers agreement with nine (9) Southern California
cities and an irrigation district to form the Southern California Public Power Authority (the
Authority). The Authority’s purpose is the planning, financing, acquiring, constructing, and
operating of projects that generate or transmit electric energy for sale to its participants. The
joint powers agreement has a term expiring in 2030 or such later date as all bonds and
notes of SCPPA and interest thereon have been paid in full or adequate provisions for
payments have been made. A copy of SCPPA’s audited financial statements can be
reviewed on their website at www.scppa.org or can be obtained by written request at 225
South Lake Avenue, Suite 1250, Pasadena, CA 91101.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(73)
NOTE 10 VERNON PUBLIC UTILITIES OPERATIONS AND COMMITMENTS (CONTINUED)
Southern California Public Power Authority (Continued)
Take or Pay Contract
The Authority’s interests or entitlements in natural gas, generation, and transmission
projects are jointly owned with other utilities. Under these arrangements, a participating
member has an undivided interest in a utility plant and is responsible for its proportionate
share of the costs of construction and operation and is entitled to its proportionate share
of the energy, available transmission capacity, or natural gas produced. Each joint plant
participant, including the Authority, is responsible for financing its share of construction
and operating costs. The City has the following “take or pay” contract with the Authority:
Palo Verde Project
The Authority purchased a 5.91% interest in the Palo Verde Nuclear Generating
Station (the Station), a nuclear-fired generating station near Phoenix, Arizona, from
the Salt River Project Agricultural Improvement and Power District, and a 6.55%
share of the right to use certain portions of the Arizona Nuclear Power Project Valley
Transmission System. The City has a 4.9% entitlement share of the Authority’s
interest in the station.
Between 1983 and 2008, the Authority issued $3.266 billion in debt of Power Project
Revenue Bonds for the Station to finance the bonds and the purchase of the
Authority’s share of the Station and related transmission rights. The bonds are not
obligations of any member of the Authority or public agency other than the Authority.
Under a power sales contract with the Authority, the City is obligated on a “take or
pay” basis for its proportionate share of power generated, as well as to make
payments for its proportionate share of the operating and maintenance expenses of
the Station, debt service on the bonds and any other debt, whether or not the project
or any part thereof or its output is suspended, reduced or terminated. The City took
its proportionate share of the power generated and its proportionate share of costs
during the fiscal year 2022 was $3,320,768. The City expects no significant
increases in costs related to its nuclear resources.
Power Purchase Commitments
The Authority has entered into power purchase agreements with project participants.
These agreements are substantially “take-and-pay” contracts where there may be other
obligations not associated with the delivery of energy. The City has entered into power
purchase agreements with the Authority related to the following projects:
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(74)
NOTE 10 VERNON PUBLIC UTILITIES OPERATIONS AND COMMITMENTS (CONTINUED)
Southern California Public Power Authority (Continued)
Power Purchase Commitments (Continued)
Astoria 2 Solar Project
On July 23, 2014, the Authority entered into a power purchase agreement with
Recurrent Energy for solar energy from the Astoria 2 Solar Project. SCPPA is
entitled to 35 MW of photovoltaic generating capacity from commercial operation to
December 31, 2021 and 45 MW of generating capacity from January 1, 2022 until
the expected expiration date of December 31, 2036. The commercial operation date
was December 2016. Power and Water Resources Pooling Authority, Lodi, Corona,
Moreno Valley, and Rancho Cucamonga, are each buying the output of a separate
portion of the facility, which is located in Kern County, California. SCPPA has
purchase options in the 10th, 15th, and 20th Contract Years. The project is
forecasted to start at a capacity factor of 31% with a 0.5% annual degradation. ACES
Power Marketing is the third-party scheduling coordinator for the project. The City
contracted to purchase 57.1429% until December 31, 2021, and 66.6667%
thereafter, of the output. The City’s proportionate share of costs during the current
fiscal year was $2,250,667.
Puente Hills Landfill Gas-to-Energy Project
On June 25, 2014, the Authority entered into a power purchase agreement with
County Sanitation District No. 2 of Los Angeles County for 46 MW of the electric
generation from a landfill gas to energy facility, located at Whittier, California. The
project began deliveries to the Authority on January 1, 2017 for a term of 10 years.
The City contracted to purchase 23.2558% of the output. The City’s proportionate
share of costs during the current fiscal year was $1,007,652.
Antelope DSR 1 Solar Project
On July 16, 2015, the Authority, entered into a power purchase agreement with
Antelope DSR 1, LLC for 50 MW solar photovoltaic generating capacity from the
Antelope DSR 1 Solar Facility. The facility is located near Lancaster, California, and
commercial operation occurred on December 16, 2016 for a term of 20 years. The
City contracted to purchase 50.00% of the output. The City’s proportionate share of
costs during the current fiscal year was $1,192,621.
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(75)
NOTE 11 COMMITMENTS AND CONTINGENCIES
Contract with Los Angeles County Fire Department
The City contracted with the County of Los Angeles (LA County) for Fire services on
May 20, 2020, setting forth the terms and conditions under which LA county will provide fire
protection, paramedic, and incidental services in the City for the next ten years. The City is
to pay LA County the annual fee on a monthly basis. During the initial five-year period, the
annual fee limitation shall not exceed 4% per fiscal year, during the sixth year of the
agreement the annual fee limitation shall be the average of the preceding four years’
percentage increases plus 1%. During the seventh year of the agreement and each
subsequent fiscal year, the annual fee limitation shall be the average of the immediately
preceding five years’ percentage increases in the Annual Fee plus o1%. Additionally, there
are conversion costs that will be paid in 36 equal payments. The agreement shall remain in
effect for a minimum of 10 years, subsequently it will be renewed for one-year periods.
Either party may terminate this agreement any time after the expiration of the initial 10-year
period term upon one year’s written notice.
The following was the contract cost for the fiscal year ended June 30, 2022 totaled
$16,785,842.
NOTE 12 SUCCESSOR AGENCY DISCLOSURES
The accompanying financial statements also include the Private-Purpose Trust Fund for the
Successor Agency to the City’s former Redevelopment Agency (Successor Agency). The
City, as the Successor Agency, serves in a fiduciary capacity, as the custodian for the
assets and to wind down the affairs of the former Redevelopment Agency. Its assets are
held in trust for the benefit of the taxing entities within the former Redevelopment Agency’s
boundaries and as such, are not available for the use of the City.
Disclosures related to the certain assets and long-term liabilities of the Successor Agency
are as follows:
Capital Assets
Effective February 1, 2012, due to AB 1X 26, Redevelopment Agencies throughout
California has been dissolved. The activities of the dissolved Vernon Redevelopment
Agency have been recorded in the Vernon Redevelopment Successor Agency fiduciary
fund. In accordance with the Successor Agency’s long-range plan to wind down the affairs
of the Successor Agency, all capital assets of the Successor Agency were either written-off
or transferred over to the City restricted for government purpose use.
Long-Term Liabilities
The long-term liabilities of the Successor Agency at June 30, 2022, were as follows:
CITY OF VERNON
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2022
(76)
NOTE 12 SUCCESSOR AGENCY DISCLOSURES (CONTINUED)
Amounts
Balance Balance Due Within
June 30, 2021 Additions Reductions June 30, 2022 One Year
Bonds Payable 42,300,000$ -$ (3,385,000)$ 38,915,000$ 1,845,000$
Bond Premium 236,866 - (25,869)210,997 -
Bond Discount (439,105) - 43,910 (395,195) -
Total 42,097,761$ -$ (3,366,959)$ 38,730,802$ 1,845,000$
$49,420,000 Industrial Redevelopment Project Tax Allocation Bonds, Series 2005
At June 30, 2022, $30,785,000 remained outstanding. The bonds are special obligation
bonds and are payable from the pledged tax revenues and amounts on deposit in the
reserve account. The debt service remaining on the bonds is $43,289,819, payable through
fiscal 2036. For the current year, debt service amounted to $3,276,800. The bonds were
issued to (i) finance various redevelopment projects, in or benefiting the Agency’s Industrial
Redevelopment Project area, (ii) fund the reserve requirement for the Series 2005 Bonds,
and (iii) pay costs of issuance of the Series 2005 Bonds. Debt service was calculated at the
actual fixed rates of the coupons ranging from 3.25% to 5.25%.
$19,490,000 Industrial Redevelopment Project Tax Allocation Bonds, Series 2011
At June 30, 2022, $8,130,000 remained outstanding. The bonds are special obligation
bonds and are payable from the pledged tax revenues and amounts on deposit in the
reserve account. The debt service remaining on the bonds is $11,882,263, payable through
fiscal 2031. For the current year, debt service amounted to $2,452,425. The bonds were
issued to (i) finance the acquisition of one or more parcels of land, and certain
redevelopment projects, in or benefiting the Agency’s Industrial Redevelopment Project
area, (ii) fund a deposit to the reserve account sufficient to meet the reserve requirement,
and (iii) pay costs of issuance of the Series 2011 Bonds. Debt service was calculated at the
actual fixed rates of the coupons ranging from 3.00% to 9.25%.
The following schedule shows the debt service requirements to maturity for the bonds as of
June 30, 2022:
Fiscal Year Ending June 30,Principal Interest Total
2023 1,845,000$ 2,174,497$ 4,019,497$
2024 2,015,000 2,053,091 4,068,091
2025 2,195,000 1,922,319 4,117,319
2026 2,385,000 1,781,719 4,166,719
2027 2,585,000 1,627,475 4,212,475
2028-2032 15,265,000 5,381,106 20,646,106
2033-2037 12,625,000 1,316,875 13,941,875
Total 38,915,000$ 16,257,081$ 55,172,081$
REQUIRED SUPPLEMENTARY INFORMATION
CITY OF VERNON
BUDGETARY COMPARISON SCHEDULE – GENERAL FUND
YEAR ENDED JUNE 30, 2022
See accompanying Note to Required Supplementary Information.
(78)
Variance with
Final Budget
Budgeted Amounts Positive
Original Final Actual (Negative)
REVENUES
Taxes 54,065,142$ 54,065,142$ 56,686,792$ 2,621,650$
Special Assessments 1,201,200 1,201,200 1,704,159 502,959
Licenses and Permits 1,596,500 1,596,500 2,158,284 561,784
Fines, Forfeitures, and Penalties 140,800 140,800 258,268 117,468
Investment Income 86,700 86,700 100,809 14,109
Intergovernmental Revenues 7,323,810 7,323,810 1,789,300 (5,534,510)
Charges for Services 10,337,306 10,337,306 10,276,400 (60,906)
Rental Income 551,500 551,500 513,701 (37,799)
Other Revenues 676,749 676,749 876,199 199,450
Total Revenues 75,979,707 75,979,707 74,363,912 (1,615,795)
EXPENDITURES
Current:
General Government 17,337,548 17,534,892 17,085,390 449,502
Public Safety 34,936,189 34,936,189 34,345,479 590,710
Public Works 9,507,202 9,880,202 7,688,016 2,192,186
Health Services 1,825,172 1,895,172 1,411,874 483,298
Capital Outlay 12,348,200 12,368,200 2,927,921 9,440,279
Debt Service 25,396 25,396 25,396 -
Total Expenditures 75,979,707 76,640,051 63,484,076 13,155,975
CHANGE IN FUND BALANCE - (660,344)10,879,836 11,540,180
Fund Balance - Beginning of Year 16,967,255 16,967,255 16,967,255 -
FUND BALANCE - END OF YEAR 16,967,255$ 16,306,911$ 27,847,091$ 11,540,180$
CITY OF VERNON
NOTE TO REQUIRED SUPPLEMENTARY INFORMATION
JUNE 30, 2022
(79)
NOTE 1 BUDGET
The City adheres to the following general procedures in establishing its annual budget,
which is reflected in the accompanying General Fund budgetary comparison schedule.
An annual budget is adopted by the City Council that provides for the general
operation of the City. The budget includes authorized expenditures and estimated
revenues of the General Fund.
The budget is adopted on a modified accrual basis and formally integrated into the
accounting system and employed as a management control device during the year.
Encumbrances, which are commitments related to executory contracts for goods and
services, are recorded to assure effective budgetary control and accountability.
Encumbrances outstanding at year-end do not constitute expenditures or liabilities.
Encumbrances outstanding at year-end are reported as committed fund balance for
subsequent year expenditures. Unencumbered appropriations lapse at year-end.
Excess expenditures over appropriations are financed by beginning fund balance.
The final budgeted amounts used in the accompanying General Fund budgetary
comparison schedule include any amendments made during the fiscal year 2022.
Encumbrances carried forward from the prior year are reflected in the original
budget.
For the current year, the General Fund’s total positive variance between the final budgeted
amounts and the actual amount of change in fund balance was $11,450,180. The key
reasons for this variance were due to lower actual revenues than projected of $1,615,795
and lower actual expenditures than appropriated by $13,155,975.
For the current year, the General Fund’s total positive variance between the final budgeted
estimated revenues and actual revenues was $1,615,795. The main reason for the variance,
was that taxes came in higher than expected by $2,621,650, in particular Sales Tax revenue
offset by intergovernmental revenues coming lower by $5,534,510 since expected capital
related work to the Atlantic Bridge Project funded by Caltrans was not completed.
For the current year, the General Fund’s total positive variance between the final budgeted
amount and the actual amount for expenditures was $13,155,975. The key reasons for this
variance were due to higher appropriations than actual expenditures of $9,440,279 in capital
outlay as work and purchases were delayed due to the pandemic and supply chain issues
offset by an increase of $2,192,186 in public works supplies and repairs and maintenance
costs.
CITY OF VERNON
SCHEDULE OF CHANGES IN THE NET PENSION LIABILITY
AND RELATED RATIOS – MISCELLANEOUS PLAN (CONTINUED)
LAST TEN FISCAL YEARS *
(80)
Fiscal Year Ended June 30, 2022 June 30, 2021 June 30, 2020 June 30, 2019
Measurement Period June 30, 2021 June 30, 2020 June 30, 2019 June 30, 2018
Total Pension Liability:
Service Cost 2,735,636$ 2,905,980$ 2,991,388$ 2,826,440$
Interest on Total Pension Liability 13,153,255 12,502,379 11,863,069 11,053,679
Changes of Assumptions - -- (549,432)
Differences Between Expected and
Actual Experience 1,777,340 1,316,307 3,767,030 3,059,775
Benefit Payments, Including Refunds
of Employee Contributions (8,274,278) (7,720,453) (6,652,881) (6,166,082)
Net Change in Total Pension
Liability 9,391,953 9,004,213 11,968,606 10,224,380
Total Pension Liability - Beginning of Year 184,953,577 175,949,364 163,980,758 153,756,378
Total Pension Liability -
End of Year (a) 194,345,530$ 184,953,577$ 175,949,364$ 163,980,758$
Plan Fiduciary Net Position:
Contributions - Employer 4,979,542$ 4,501,532$ 3,908,165$ 3,380,432$
Contributions - Employee 1,161,711 1,271,580 1,357,537 1,214,616
Net Investment Income 30,012,771 6,484,512 8,077,977 9,803,260
Benefit Payments, Including Refunds
of Employee Contributions (8,274,278) (7,720,453) (6,652,881) (6,166,082)
Plan to Plan Resource Movement - -- (296)
Administrative Expenses (138,188) (188,889) (90,906) (186,518)
Other Miscellaneous Income (1) - - 296 (354,202)
Net Change in Plan
Fiduciary Net Position 27,741,558 4,348,282 6,600,188 7,691,210
Plan Fiduciary Net Position -
Beginning of Year 138,335,116 133,986,834 127,386,646 119,695,436
Plan Fiduciary Net Position -
End of Year (b) 166,076,674$ 138,335,116$ 133,986,834$ 127,386,646$
Net Pension Liability - Ending (a)-(b) 28,268,856$ 46,618,461$ 41,962,530$ 36,594,112$
Plan Fiduciary Net Position as a
Percentage of the Total Pension Liability 85.45%74.79%76.15%77.68%
Covered Payroll 15,355,968$ 15,399,491$ 15,996,725$ 15,146,241$
Net Pension Liability as Percentage of
Covered Payroll 184.09% 302.73% 262.32% 241.61%
Notes to Schedule:
Benefit Changes:
There were no changes in benefits.
Changes in Assumptions:
From fiscal year June 30, 2015 to June 30, 2016:
GASB 68, paragraph 68 states that the long-term expected rate of return should be determined net of pension plan
investment expense but without reduction for pension plan administrative expense. The discount rate of 7.50% used
for the June 30, 2014 measurement date was net of administrative expenses. The discount rate of 7.65% used for the
June 30, 2015 measurement date is without reduction of pension plan administrative expense.
From fiscal year June 30, 2016 to June 30, 2017:
There were no changes in assumptions.
From fiscal year June 30, 2017 to June 30, 2018:
The discount rate was reduced from 7.65% to 7.15%.
From fiscal year June 30, 2018 to June 30, 2019:
From fiscal year June 30, 2019 to June 30, 2020:
There were no changes in assumptions.
From fiscal year June 30, 2020 to June 30, 2021:
There were no changes in assumptions.
From fiscal year June 30, 2021 to June 30, 2022:
There were no changes in assumptions.
* Fiscal year 2015 was the first year of implementation and therefore only eight years are shown.
Demographic assumptions and inflation rate were changed in accordance to the CalPERS Experience Study and
Review of Assumptions December 2017
CITY OF VERNON
SCHEDULE OF CHANGES IN THE NET PENSION LIABILITY
AND RELATED RATIOS – MISCELLANEOUS PLAN (CONTINUED)
LAST TEN FISCAL YEARS *
(81)
Fiscal Year Ended
Measurement Period
Total Pension Liability:
Service Cost
Interest on Total Pension Liability
Changes of Assumptions
Differences Between Expected and
Actual Experience
Benefit Payments, Including Refunds
of Employee Contributions
Net Change in Total Pension
Liability
Total Pension Liability - Beginning of Year
Total Pension Liability -
End of Year (a)
Plan Fiduciary Net Position:
Contributions - Employer
Contributions - Employee
Net Investment Income
Benefit Payments, Including Refunds
of Employee Contributions
Plan to Plan Resource Movement
Administrative Expenses
Other Miscellaneous Income (1)
Net Change in Plan
Fiduciary Net Position
Plan Fiduciary Net Position -
Beginning of Year
Plan Fiduciary Net Position -
End of Year (b)
Net Pension Liability - Ending (a)-(b)
Plan Fiduciary Net Position as a
Percentage of the Total Pension Liability
Covered Payroll
Net Pension Liability as Percentage of
Covered Payroll
June 30, 2018 June 30, 2017 June 30, 2016 June 30, 2015
June 30, 2017 June 30, 2016 June 30, 2015 June 30, 2014
2,432,788$ 2,129,659$ 1,962,270$ 1,955,694$
10,383,859 9,969,103 9,447,012 9,609,274
9,321,776 - (2,466,126) -
(711,339) 1,046,363 (9,700,904) -
(6,145,366) (5,748,657) (5,680,624) (2,388,449)
15,281,718 7,396,468 (6,438,372) 9,176,519
138,474,660 131,078,192 137,516,564 128,340,045
153,756,378$ 138,474,660$ 131,078,192$ 137,516,564$
3,629,603$ 3,140,644$ 2,340,002$ 1,825,732$
1,245,990 1,095,824 1,054,426 1,015,741
11,857,647 583,692 2,337,855 16,045,243
(6,145,366) (5,748,657) (5,680,624) (2,388,449)
1,118 (780) 18 -
(161,327) (67,200) (124,052) -
- - - -
10,427,665 (996,477) (72,375) 16,498,267
109,267,771 110,264,248 110,336,623 93,838,356
119,695,436$ 109,267,771$ 110,264,248$ 110,336,623$
34,060,942$ 29,206,889$ 20,813,944$ 27,179,941$
77.85%78.91%84.12%80.24%
13,440,076$ 13,150,103$ 11,708,057$ 11,084,188$
253.43% 222.10% 177.77% 245.21%
CITY OF VERNON
SCHEDULE OF CHANGES IN THE NET PENSION LIABILITY
AND RELATED RATIOS – MISCELLANEOUS PLAN (CONTINUED)
LAST TEN FISCAL YEARS *
(82)
Notes to Schedule:
Benefit Changes:
There were no changes in benefits.
Changes in Assumptions:
From fiscal year June 30, 2015 to June 30, 2016:
GASB 68, paragraph 68 states that the long-term expected rate of return should be determined net of pension plan
investment expense but without reduction for pension plan administrative expense. The discount rate of 7.50% used
for the June 30, 2014 measurement date was net of administrative expenses. The discount rate of 7.65% used for the
June 30, 2015 measurement date is without reduction of pension plan administrative expense.
From fiscal year June 30, 2016 to June 30, 2017:
There were no changes in assumptions.
From fiscal year June 30, 2017 to June 30, 2018:
The discount rate was reduced from 7.65% to 7.15%.
From fiscal year June 30, 2018 to June 30, 2019:
From fiscal year June 30, 2019 to June 30, 2020:
There were no changes in assumptions.
From fiscal year June 30, 2020 to June 30, 2021:
There were no changes in assumptions.
From fiscal year June 30, 2021 to June 30, 2022:
There were no changes in assumptions.
* Fiscal year 2015 was the first year of implementation and therefore only eight years are shown.
Demographic assumptions and inflation rate were changed in accordance to the CalPERS Experience Study and
Review of Assumptions December 2017
CITY OF VERNON
SCHEDULE OF PENSION CONTRIBUTIONS – MISCELLANEOUS PLAN
LAST TEN FISCAL YEARS *
(83)
Fiscal Year Ended June 30, 2022 June 30, 2021 June 30, 2020 June 30, 2019
Contractually Required Contribution
(Actuarially Determined)5,957,671$ 4,979,905$ 4,500,718$ 3,908,165$
Contributions in Relation to
the Actuarially Determined
Contributions (5,957,671) (4,979,905) (4,500,718) (3,908,165)
Contribution Deficiency (Excess)-$ -$ -$ -$
Covered Payroll 19,708,798$ 15,355,968$ 15,399,491$ 15,996,725$
Contributions as a Percentage
of Covered Payroll 30.23%32.43%29.23%24.43%
Notes to Schedule:
Valuation Date 6/30/2019 6/30/2018 6/30/2017 6/30/2016
Methods and Assumptions Used
to Determine Contribution Rates:
Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age
Amortization Method (1)(1)(1)(1)
Asset Valuation Method Fair Value Fair Value Fair Value Fair Value
Inflation 2.625%2.625%2.625%2.75%
Salary Increases (2)(2)(2)(2)
Investment Rate of Return 7.25% (3) 7.25% (3) 7.25% (3) 7.375% (3)
Retirement Age (4)(4)(4)(4)
Mortality (5)(5)(5)(5)
(1) Level percentage of payroll, closed
(2) Depending on age, service, and type of employment
(3) Net of pension plan investment expense, including inflation
(4) 2.0% at 55, 2.7% at 55, 2% at 60, and 2.0% at 62
(5) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study
adopted by the CalPERS Board.
* Fiscal year 2015 was the first year of implementation and therefore only eight years are shown.
CITY OF VERNON
SCHEDULE OF PENSION CONTRIBUTIONS – MISCELLANEOUS PLAN (CONTINUED)
LAST TEN FISCAL YEARS *
(84)
Fiscal Year Ended
Contractually Required Contribution
(Actuarially Determined)
Contributions in Relation to
the Actuarially Determined
Contributions
Contribution Deficiency (Excess)
Covered Payroll
Contributions as a Percentage
of Covered Payroll
Notes to Schedule:
Valuation Date
Methods and Assumptions Used
to Determine Contribution Rates:
Actuarial Cost Method
Amortization Method
Asset Valuation Method
Inflation
Salary Increases
Investment Rate of Return
Retirement Age
Mortality
June 30, 2018 June 30, 2017 June 30, 2016 June 30, 2015
3,380,432$ 3,629,603$ 3,140,644$ 2,340,002$
(3,380,432) (3,629,603) (3,140,644) (2,340,002)
-$ -$-$ -$
15,146,241$ 13,440,076$ 13,150,103$ 11,708,057$
22.32%27.01%23.88%19.99%
6/30/2015 6/30/2014 6/30/2013 6/30/2012
Entry Age Entry Age Entry Age Entry Age
(1)(1)(1)(1)
Fair Value Fair Value Fair Value 15 Year
Smoothed
Market Method
2.75%2.75%2.75%2.75%
(2)(2)(2)(2)
7.50% (3) 7.50% (3) 7.50% (3) 7.50% (3)
(4)(4)(4)(4)
(5)(5)(5)(5)
(1) Level percentage of payroll, closed
(2) Depending on age, service, and type of employment
(3) Net of pension plan investment expense, including inflation
(4) 2.0% at 55, 2.7% at 55, 2% at 60, and 2.0% at 62
(5) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study
adopted by the CalPERS Board.
* Fiscal year 2015 was the first year of implementation and therefore only eight years are shown.
CITY OF VERNON
SCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION LIABILITY – SAFETY PLAN
LAST TEN FISCAL YEARS *
(85)
Fiscal Year Ended June 30, 2022 June 30, 2021
Measurement Period June 30, 2021 June 30, 2020
Plan's Proportion of the Net
Pension Liability 1.702860% 1.331100%
Plan's Proportionate Share of
the Net Pension Liability 59,761,800$ 88,682,300$
Plan's Covered Payroll 7,618,673$ 11,770,766$
Plan's Proportionate Share of
the Net Pension Liability as a
Percentage of Covered Payroll 784.41% 753.41%
Plan's Proportionate Share of
the Fiduciary Net Position as a
Percentage of the Plan's Total
Pension Liability 79.73%69.13%
Plan's Proportionate Share of
Aggregate Employer Contributions 12,561,115$ 10,280,295$
Notes to Schedule:
*Fiscal year 2021 was the first year the City's Safety Plan was converted from an Agent Multiple Plan to a Cost
Sharing Plan therefore only two years are shown.
Safety
CITY OF VERNON
SCHEDULE OF CHANGES IN THE NET PENSION LIABILITY
AND RELATED RATIOS – SAFETY PLAN
LAST TEN FISCAL YEARS *
(86)
Fiscal Year Ended June 30, 2020 June 30, 2019 June 30, 2018 June 30, 2017 June 30, 2016 June 30, 2015
Measurement Period June 30, 2019 June 30, 2018 June 30, 2017 June 30, 2016 June 30, 2015 June 30, 2014
Total Pension Liability:
Service Cost 4,287,003$ 4,414,740$ 4,144,398$ 3,454,025$ 3,388,157$ 3,448,760$
Interest on Total Pension Liability 18,414,262 17,691,261 16,898,830 16,325,879 15,777,736 15,255,372
Changes of Benefit Terms - - -- - -
Changes of Assumptions -(1,533,898)14,134,794 - (3,878,396) -
Differences Between Expected and
Actual Experience (364,199) 2,008,618 (1,380,683) (2,430,394) (2,400,883) -
Benefit Payments, Including Refunds
of Employee Contributions (12,139,668) (10,992,416) (10,147,899) (9,736,302) (9,470,058) (9,639,123)
Net Change in Total Pension
Liability 10,197,398 11,588,305 23,649,440 7,613,208 3,416,556 9,065,009
Total Pension Liability - Beginning of Year 261,832,661 250,244,356 226,594,916 218,981,708 215,565,152 206,500,143
Total Pension Liability -
End of Year (a) 272,030,059$ 261,832,661$ 250,244,356$ 226,594,916$ 218,981,708$ 215,565,152$
Plan Fiduciary Net Position:
Contributions - Employer 7,011,540$ 6,109,373$ 5,476,196$ 5,116,412$ 4,147,441$ 3,234,539$
Contributions - Employee 1,239,891 1,302,308 1,212,646 1,222,561 1,167,329 1,092,012
Net Investment Income 12,275,401 14,666,919 17,760,401 760,559 3,525,241 24,855,525
Benefit Payments, Including Refunds
of Employee Contributions (12,139,668) (10,992,416) (10,147,899) (9,736,302) (9,470,058) (9,639,123)
Plan to Plan Resource Movement -(431)(1,118) 780 24 -
Administrative Expenses (131,969) (272,124)(237,068) (99,525) (191,323) -
Other Miscellaneous Income (1) 431 (516,768) -- - -
Net Change in Plan
Fiduciary Net Position 8,255,626 10,296,861 14,063,158 (2,735,515) (821,346) 19,542,953
Plan Fiduciary Net Position - Beginning
of Year 184,928,220 174,631,359 160,568,201 163,303,716 164,125,062 144,582,109
Plan Fiduciary Net Position -
End of Year (b) 193,183,846$ 184,928,220$ 174,631,359$ 160,568,201$ 163,303,716$ 164,125,062$
Net Pension Liability - Ending (a)-(b) 78,846,213$ 76,904,441$ 75,612,997$ 66,026,715$ 55,677,992$ 51,440,090$
Plan Fiduciary Net Position as a
Percentage of the Total Pension Liability 71.02%70.63%69.78%70.86%74.57%76.14%
Covered Payroll 13,737,311$ 14,292,273$ 13,879,896$ 12,971,888$ 12,740,785$ 12,510,920$
Net Pension Liability as Percentage of
Covered Payroll 573.96% 538.08% 544.77% 509.00% 437.01% 411.16%
Notes to Schedule:
Benefit Changes:
There were no changes in benefits.
Changes in Assumptions:
From fiscal year June 30, 2015 to June 30, 2016:
From fiscal year June 30, 2016 to June 30, 2017:
There were no changes in assumptions.
From fiscal year June 30, 2017 to June 30, 2018:
The discount rate was reduced from 7.65% to 7.15%.
From fiscal year June 30, 2018 to June 30, 2019:
From fiscal year June 30, 2019 to June 30, 2020:
There were no changes in assumptions.
GASB 68, paragraph 68 states that the long-term expected rate of return should be determined net of pension plan investment expense but without
reduction for pension plan administrative expense. The discount rate of 7.50% used for the June 30, 2014 measurement date was net of administrative
expenses. The discount rate of 7.65% used for the June 30, 2015 measurement date is without reduction of pension plan administrative expense.
Demographic assumptions and inflation rate were changed in accordance to the CalPERS Experience Study and Review of Assumptions December 2017
* Fiscal year 2015 was the first year of implementation. Additionally, fiscal year 2021 was the first year the City's Safety Plan was converted from an Agent Multiple
Plan to a Cost Sharing Plan, and therefore only six years are shown.
CITY OF VERNON
SCHEDULE OF PENSION CONTRIBUTIONS – SAFETY PLAN
LAST TEN FISCAL YEARS *
(87)
Fiscal Year Ended June 30, 2022 June 30, 2021 June 30, 2020 June 30, 2019
Contractually Required Contribution
(Actuarially Determined)8,258,888$ 7,650,585$ 7,834,050$ 7,011,540$
Contributions in Relation to
the Actuarially Determined
Contributions (8,258,888) (7,650,585) (7,834,050) (7,011,540)
Contribution Deficiency (Excess)-$ -$ -$ -$
Covered Payroll 5,630,861$ 7,618,673$ 11,770,766$ 13,737,311$
Contributions as a Percentage
of Covered Payroll 146.67% 100.42%66.56%51.04%
Notes to Schedule:
Valuation Date 6/30/2019 6/30/2018 6/30/2017 6/30/2016
Methods and Assumptions Used
to Determine Contribution Rates:
Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age
Amortization Method (1)(1)(1)(1)
Asset Valuation Method Fair Value Fair Value Fair Value Fair Value
Inflation 2.625%2.625%2.625%2.75%
Salary Increases (2)(2)(2)(2)
Investment Rate of Return 7.25% (3) 7.25% (3) 7.25% (3) 7.375% (3)
Retirement Age (4)(4)(4)(4)
Mortality (5)(5)(5)(5)
(1) Level percentage of payroll, closed
(2) Depending on age, service, and type of employment
(3) Net of pension plan investment expense, including inflation
(4) 3.0% at 50, 3.0% at 55, and 2.7% at 57
(5) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study
adopted by the CalPERS Board.
* Fiscal year 2015 was the first year of implementation and therefore only eight years are shown.
CITY OF VERNON
SCHEDULE OF PENSION CONTRIBUTIONS – SAFETY PLAN (CONTINUED)
LAST TEN FISCAL YEARS *
(88)
Fiscal Year Ended
Contractually Required Contribution
(Actuarially Determined)
Contributions in Relation to
the Actuarially Determined
Contributions
Contribution Deficiency (Excess)
Covered Payroll
Contributions as a Percentage
of Covered Payroll
Notes to Schedule:
Valuation Date
Methods and Assumptions Used
to Determine Contribution Rates:
Actuarial Cost Method
Amortization Method
Asset Valuation Method
Inflation
Salary Increases
Investment Rate of Return
Retirement Age
Mortality
June 30, 2018 June 30, 2017 June 30, 2016 June 30, 2015
6,109,373$ 5,476,196$ 5,116,412$ 4,147,441$
(6,109,373) (5,476,196) (5,116,412) (4,147,441)
-$ -$-$ -$
14,292,273$ 13,879,896$ 12,971,888$ 12,740,785$
42.75%39.45%39.44%32.55%
6/30/2015 6/30/2014 6/30/2013 6/30/2012
Entry Age Entry Age Entry Age
(1)(1)(1)Entry Age
Fair Value Fair Value Fair Value (1)
15 Year
Smoothed
2.75%2.75%2.75% Market Method
(2)(2)(2)2.75%
7.50% (3) 7.50% (3) 7.50% (3)(2)
(4)(4)(4)7.50% (3)
(5)(5)(5)(4)
(5)
(1) Level percentage of payroll, closed
(2) Depending on age, service, and type of employment
(3) Net of pension plan investment expense, including inflation
(4) 3.0% at 50, 3.0% at 55, and 2.7% at 57
(5) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study
adopted by the CalPERS Board.
* Fiscal year 2015 was the first year of implementation and therefore only eight years are shown.
CITY OF VERNON
SCHEDULE OF CHANGES IN NET OPEB LIABILITY AND RELATED RATIOS
LAST TEN FISCAL YEARS *
(89)
Fiscal Year End June 30, 2022 June 30, 2021 June 30, 2020 June 30, 2019
Measurement Date June 30, 2021 June 30, 2020 June 30, 2019 June 30, 2018
Total OPEB Liability:
Service Cost 303,057$ 565,922$ 549,137$ 1,204,747$
Interest on Total OPEB Liability 1,682,954 1,699,197 1,641,230 2,063,052
Differences Between Expected and Actual Experience (677,446) 206,148 - (6,680,583)
Assumption Changes 66,075 579,724 (124,861) (7,657,196)
Change of Benefit Terms - (800,265) --
Benefit Payments (1,199,826) (1,222,538) (1,158,450) (1,006,087)
Net Change in Total OPEB Liability 174,814 1,028,188 907,056 (12,076,067)
Total OPEB Liability - Beginning of Year 27,215,028 26,186,840 25,279,784 37,355,851
Total OPEB Liability - End of Year (a)27,389,842$ 27,215,028$ 26,186,840$ 25,279,784$
Plan Fiduciary Net Position:
Contributions - Employer 3,131,526$ 3,915,406$ 2,989,393$ 2,065,407$
Net Investment Income 2,084,288 44,684 258,220 65,276
Benefit Payments
and the Implied Subsidy Benefit Payments (1,199,826) (1,222,538) (1,158,450) (1,006,087)
Administrative Expenses (2,958) (2,563) (629) (808)
Other Deductions - -- (1,400)
Net Change in Plan Fiduciary Net Position 4,013,030 2,734,989 2,088,534 1,122,388
Plan Fiduciary Net Position - Beginning of Year 7,003,178 4,268,189 2,179,655 1,057,267
Plan Fiduciary Net Position - End of Year (b)11,016,208$ 7,003,178$ 4,268,189$ 2,179,655$
Net OPEB Liability - Ending (a)-(b)16,373,634$ 20,211,850$ 21,918,651$ 23,100,129$
Plan Fiduciary Net Position as a Percentage of the
Total OPEB Liability 40.22%25.73%16.30%8.62%
Covered - Employee Payroll 31,702,877$ 31,958,957$ 35,182,647$ 33,496,565$
Net OPEB Liability as Percentage of
Covered - Employee Payroll 51.65%63.24%62.30%68.96%
Notes to Schedule:
Benefit Changes:
There were no changes in benefits.
Changes in Assumptions:
* Fiscal year 2018 was the first year of implementation and therefore only five years are shown.
Fiscal year end June 30, 2018 is the first year of implementation; therefore, there are no previous GASB 75 actuarial reports for comparison.
Fiscal year end June 30, 2022: Medical trend rates have been updated by actual premium increase from 2021 to 2022.
Fiscal year end June 30, 2019: Discount rate for the implicit subsidy liability was changed from 3.56% to 6.5% based on updated expectations of long-term
returns on trust assets and updated valuation methods.
Fiscal year end June 30, 2020: Medical trend rates were updated to exclude Affordable Care Act's Excise Tax on high-cost health insurance plan due to its
repeal.
Fiscal year end June 30, 2021: Discount rate for the implicit subsidy liability was changed from 6.5% to 6.25% based on updated expectations of long-term
returns on trust assets and updated valuation methods. Inflation rate changed from 2.50% to 2.25%.
CITY OF VERNON
SCHEDULE OF CHANGES IN NET OPEB LIABILITY AND RELATED RATIOS
LAST TEN FISCAL YEARS *
(90)
Fiscal Year End
Measurement Date
Total OPEB Liability:
Service Cost
Interest on Total OPEB Liability
Differences Between Expected and Actual Experience
Assumption Changes
Change of Benefit Terms
Benefit Payments
Net Change in Total OPEB Liability
Total OPEB Liability - Beginning of Year
Total OPEB Liability - End of Year (a)
Plan Fiduciary Net Position:
Contributions - Employer
Net Investment Income
Benefit Payments
and the Implied Subsidy Benefit Payments
Administrative Expenses
Other Deductions
Net Change in Plan Fiduciary Net Position
Plan Fiduciary Net Position - Beginning of Year
Plan Fiduciary Net Position - End of Year (b)
Net OPEB Liability - Ending (a)-(b)
Plan Fiduciary Net Position as a Percentage of the
Total OPEB Liability
Covered - Employee Payroll
Net OPEB Liability as Percentage of
Covered - Employee Payroll
June 30, 2018
June 30, 2017
1,166,825$
1,879,025
-
(770,716)
-
(838,818)
1,436,316
35,919,535
37,355,851$
1,898,138$
(2,049)
(838,818)
(4)
-
1,057,267
-
1,057,267$
36,298,584$
2.83%
33,511,114$
108.32%
Notes to Schedule:
Benefit Changes:
There were no changes in benefits.
Changes in Assumptions:
* Fiscal year 2018 was the first year of implementation and therefore only five years are shown.
Fiscal year end June 30, 2018 is the first year of implementation; therefore, there are no previous GASB 75 actuarial reports for comparison.
Fiscal year end June 30, 2022: Medical trend rates have been updated by actual premium increase from 2021 to 2022.
Fiscal year end June 30, 2019: Discount rate for the implicit subsidy liability was changed from 3.56% to 6.5% based on updated expectations of long-term
returns on trust assets and updated valuation methods.
Fiscal year end June 30, 2020: Medical trend rates were updated to exclude Affordable Care Act's Excise Tax on high-cost health insurance plan due to its
repeal.
Fiscal year end June 30, 2021: Discount rate for the implicit subsidy liability was changed from 6.5% to 6.25% based on updated expectations of long-term
returns on trust assets and updated valuation methods. Inflation rate changed from 2.50% to 2.25%.
CITY OF VERNON
SCHEDULE OF OPEB CONTRIBUTIONS
LAST TEN FISCAL YEARS *
(91)
Fiscal Year Ended June 30, 2022 June 30, 2021 June 30, 2020 June 30, 2019 June 30, 2018
Actuarially Determined Contribution 1,538,693$ 1,538,693$ 1,931,700$ 2,692,868$ 2,692,868$
Contributions in Relation to the Actuarially Determined
Contributions (2,933,295) (3,131,526) (3,915,406) (2,989,393) (2,065,407)
Contribution Deficiency (Excess)(1,394,602)$ (1,592,833)$ (1,983,706)$ (296,525)$ 627,461$
Covered - Employee Payroll 31,702,877$ 31,702,877$ 31,958,957$ 35,182,647$ 33,496,565$
Contributions as a Percentage of Covered - Employee
Payroll 9.25%9.88%12.25%8.50%6.17%
Notes to Schedule:
Valuation Date 6/30/2020 6/30/2019 6/30/2018 6/30/2018 6/30/2017
Methods and Assumptions Used to Determine
Contribution Rates:
Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age Entry Age
Amortization Method (1)(1)(1)(1)(1)
Amortization Period 27 Years 27 Years 27 Years 27 Years 29 Years
Asset Valuation Method Market Value Market Value Market Value Market Value Market Value
Inflation 2.25%2.25%2.50%2.50%2.75%
Healthcare Trend Rates (4)(4)(3)(3)(2)
Investment Rate of Return 6.25%6.25%6.50%7.00%7.00%
Mortality (6)(6)(6)(6)(5)
(1) Level percentage of payroll, closed.
(2) 8.50% trending down to 5.00%.
(3) 6.90% trending down to 4.00%.
(4) 6.70% trending down to 3.8%.
(5) CalPERS December 2014 experience study
(6) CalPERS December 2017 experience study
* Fiscal year 2018 was the first year of implementation and therefore five years are shown.
VERNON PUBLIC UTILITIES
(THE ELECTRIC, GAS, WATER, AND
FIBER OPTICS ENTERPRISE FUNDS OF THE
CITY OF VERNON)
FINANCIAL STATEMENTS AND
SUPPLEMENTARY INFORMATION
YEAR ENDED JUNE 30, 2022
CITY OF VERNON
VERNON PUBLIC UTILITIES
TABLE OF CONTENTS
YEAR ENDED JUNE 30, 2022
INTRODUCTORY SECTION
A MESSAGE FROM THE GENERAL MANAGER OF VERNON PUBLIC
UTILITIES i
FINANCIAL SECTION
INDEPENDENT AUDITORS’ REPORT 1
MANAGEMENTS’ DISCUSSION AND ANALYSIS (Required Supplementary
Information – Unaudited) 4
BASIC FINANCIAL STATEMENTS
STATEMENT OF NET POSITION 10
STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN NET
POSITION 12
STATEMENT OF CASH FLOWS 13
NOTES TO BASIC FINANCIAL STATEMENTS 15
REQUIRED SUPPLEMENTARY INFORMATION
SCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION
LIABILITY – CITY’S MISCELLANEOUS AND SAFETY COST SHARING
PLAN 49
SCHEDULE OF PLAN CONTRIBUTIONS – CITY’S MISCELLANEOUS AND
SAFETY COST SHARING PLAN 50
SCHEDULE OF PROPORTIONATE SHARE OF THE NET OPEB LIABILITY 51
SCHEDULE OF OPEB CONTRIBUTIONS 52
SUPPLEMENTARY INFORMATION
COMBINING STATEMENT OF NET POSITION 53
COMBINING STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN
NET POSITION 55
COMBINING STATEMENT OF CASH FLOWS 56
INTRODUCTORY SECTION
Vernon Public Utilities
4305 Santa Fe Avenue, Vernon, CA, 90058
323.583.8811 | CityofVernon.org
Message from the General Manager
As an essential resource to all customers, our job is to provide dependable,
high-quality electric, water, natural gas, and fiber optic services at cost -
effective rates with the highest standards for reliability. We ensure that
electricity will stay on when needed, customers have safe, clean drinking
water, there is a reliable supply of natural gas to meet demand, and our fiber
services offer competitive rates and the latest technology. Our mission focuses
on reliably providing the lowest electric rates in California by 2030.
As a municipally owned utility, every customer is a stakeholder in Vernon Public
Utilities (VPU). VPU enjoys the continued support of the City Council, which has
approved key strategic initiatives for sustained success. These initiatives
include Renewable Energy Projects, such as the Daggett Solar Project
(operational in September 2023) and the Sapphire Solar and Storage Facility Project (operational in
December 2025). With Council support, along with City Administration, VPU remains focused on providing
our customers with reliable services and competitive rates.
Despite the recent supply chain issues and higher costs for energy, materials, and supplies, which are
critical to our operations, VPU is committed to maintaining a strong financial and operational position for
the future. Our strategy focuses on the following initiatives for financial and operational flexibility :
1.Electric load growth with a diversified customer base which includes green commerce.
2.A diversified Energy Resource portfolio, which includes meeting California’s Renewable Portfolio
Standard Targets as outlined in SB100. Specifically, (i) 2027 - 52%, (ii) 2030 - 60%, and (iii) 2045 - 100%
Carbon Neutral. VPU is in the process of updating its Integrated Resource Plan, which focuses on
providing direction for reliability, affordability, and meeting renewable energy requirements.
3.Optimizing the operating profile for the Malburg Generating Station (MGS) for operational savings
and continued coordination with the CAISO to prevent statewide rolling blackouts and requests to
run MGS when energy is needed most across the electric grid.
4.Continued strategic capital investment in electric, water, natural gas, and fiber optic infrastructure to
support high-quality and reliable services. VPU continues to be one of the most reliable electric
systems compared to other utilities. VPU is a three-time recipient of the RP3 Diamond Level Award, the
highest reliability award from APPA, which reflects our continued investment in utility infrastructure and
commitment to safety and workforce development.
5.A focus on the utility’s financial strength, including improving key financial metrics used by the rating
agencies such as Moody’s and S&P Global Ratings, including the implementation of a Utility Financial
Reserves Policy, and keeping rates competitive to ensure businesses can grow in Vernon.
As we enter 2023, I am optimistic about the future. VPU is focused on providing reliable and competitive
electric, water, natural gas, and fiber optic services. In that pursuit, we will excel today and in the future.
Sincerely,
Todd Dusenberry
General Manager
FINANCIAL SECTION
(1)
INDEPENDENT AUDITORS’ REPORT
Honorable Mayor and the Members of the City Council
City of Vernon, California
Report on the Audit of the Financial Statements
Opinion
We have audited the accompanying financial statements of Vernon Public Utilities (VPU) of the City of
Vernon, California (City), which comprise the statement of net position as of June 30, 2022, and the
related statements of revenues, expenses, and changes in net position, and cash flows for the year
then ended, and the related notes to the financial statements, which collectively comprise the VPU’s
basic financial statements as listed in the table of contents.
In our opinion, the financial statements referred to above present fairly, in all material respects, the
financial position of Vernon Public Utilities of the City of Vernon, California, as of June 30, 2022, and
the changes in its financial position and its cash flows for the year then ended in accordance with
accounting principles generally accepted in the United States of America.
Basis for Opinion
We conducted our audit in accordance with auditing standards generally accepted in the United States
of America (GAAS) and the standards applicable to financial audits contained in Government Auditing
Standards, issued by the Comptroller General of the United States. Our responsibilities under those
standards are further described in the Auditors’ Responsibilities for the Audit of the Financial
Statements section of our report. We are required to be independent of the Vernon Public Utilities and
to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating
to our audit. We believe that the audit evidence we have obtained is sufficient and appropriate to
provide a basis for our audit opinion.
Emphasis of Matter
As discussed in Note 1 to the financial statements, the financial statements present only the Vernon
Public Utilities and do not purport to, and do not, present fairly the financial position of the City of
Vernon, California as of June 30, 2022, and the changes in its financial position and its cash flows for
the year then ended in accordance with accounting principles generally accepted in the United States
of America. Our opinion is not modified with respect to this matter.
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in
accordance with accounting principles generally accepted in the United States of America; this includes
the design, implementation, and maintenance of internal control relevant to the preparation and fair
presentation of financial statements that are free from material misstatement, whether due to fraud or
error.
CLA (CliftonLarsonAllen LLP) is an independent network member of CLA Global. See CLAglobal.com/disclaimer.
CliftonLarsonAllen LLP
CLAconnect.com
Honorable Mayor and the Members of the City Council
City of Vernon, California
(2)
Auditors’ Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole
are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that
includes our opinions. Reasonable assurance is a high level of assurance but is not absolute assurance
and therefore is not a guarantee that an audit conducted in accordance with GAAS and Government
Auditing Standards will always detect a material misstatement when it exists. The risk of not detecting a
material misstatement resulting from fraud is higher than for one resulting from error, as fraud may
involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
Misstatements are considered material if there is a substantial likelihood that, individually or in the
aggregate, they would influence the judgment made by a reasonable user based on the financial
statements.
In performing an audit in accordance with GAAS and Government Auditing Standards, we:
Exercise professional judgment and maintain professional skepticism throughout the audit.
Identify and assess the risks of material misstatement of the financial statements, whether due
to fraud or error, and design and perform audit procedures responsive to those risks. Such
procedures include examining, on a test basis, evidence regarding the amounts and disclosures
in the financial statements.
Obtain an understanding of internal control relevant to the audit in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of Vernon Public Utilities’ internal control. Accordingly, no such
opinion is expressed.
Evaluate the appropriateness of accounting policies used and the reasonableness of significant
accounting estimates made by management, as well as evaluate the overall presentation of the
financial statements.
We are required to communicate with those charged with governance regarding, among other matters,
the planned scope and timing of the audit, significant audit findings, and certain internal control related
matters that we identified during the audit.
Required Supplementary Information
Accounting principles generally accepted in the United States of America require that the
management’s discussion and analysis, schedule of proportionate share of the net pension liability,
schedule of plan contributions, schedule of proportionate share of the net OPEB liability, and schedule
of OPEB contributions, identified as required supplementary information (RSI) in the accompanying
table of contents, be presented to supplement the basic financial statements. Such information is the
responsibility of management and, although not a part of the basic financial statements, is required by
the Governmental Accounting Standards Board who considers it to be an essential part of financial
reporting for placing the basic financial statements in an appropriate operational, economic, or historical
context. We have applied certain limited procedures to the required supplementary information in
accordance with auditing standards generally accepted in the United States of America, which
consisted of inquiries of management about the methods of preparing the information and comparing
the information for consistency with management’s responses to our inquiries, the basic financial
Honorable Mayor and the Members of the City Council
City of Vernon, California
(3)
statements, and other knowledge we obtained during our audit of the basic financial statements. We do
not express an opinion or provide any assurance on the information because the limited procedures do
not provide us with sufficient evidence to express an opinion or provide any assurance.
Supplementary Information
Our audit was conducted for the purpose of forming opinions on the financial statements that
collectively comprise the VPU’s basic financial statements. The combining financial statements are
presented for purposes of additional analysis and are not a required part of the basic financial
statements. Such information is the responsibility of management and was derived from and relates
directly to the underlying accounting and other records used to prepare the basic financial statements.
The information has been subjected to the auditing procedures applied in the audit of the basic financial
statements and certain additional procedures, including comparing and reconciling such information
directly to the underlying accounting and other records used to prepare the basic financial statements
or to the basic financial statements themselves, and other additional procedures in accordance with
GAAS. In our opinion, the combining financial statements are fairly stated, in all material respects, in
relation to the basic financial statements as a whole.
Other Information
Management is responsible for the other information included in the annual report. The other
information comprises the introductory section but does not include the basic financial statements and
our auditors’ report thereon. Our opinion on the basic financial statements does not cover the other
information, and we do not express an opinion or any form of assurance thereon.
In connection with our audit of the basic financial statements, our responsibility is to read the other
information and consider whether a material inconsistency exists between the other information and the
basic financial statements, or the other information otherwise appears to be materially misstated. If,
based on the work performed, we conclude that an uncorrected material misstatement of the other
information exists, we are required to describe it in our report.
Other Reporting Required by Government Auditing Standards
In accordance with Government Auditing Standards, we have also issued our report dated August 8,
2023, on our consideration of the VPU’s internal control over the financial reporting and on our tests of
its compliance with certain provisions of laws, regulations, contracts, and grant agreements and other
matters. The purpose of that report is solely to describe the scope of our testing of internal control over
financial reporting and compliance and the results of that testing, and not to provide an opinion on the
effectiveness of the VPU’s internal control over financial reporting or on compliance. That report is an
integral part of an audit performed in accordance with Government Auditing Standards in considering
the VPU’s internal control over financial reporting and compliance.
CliftonLarsonAllen LLP
Irvine, California
August 8, 2023
CITY OF VERNON
VERNON PUBLIC UTILITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(4)
The management of the Vernon Public Utilities (VPU), the electric, gas, water, and fiber optics utilities of the
City of Vernon (“the City”), offers the following overview and analysis of the basic financial statements of the
VPU for the fiscal year ended June 30, 2022. Management encourages readers to utilize information in the
Management’s Discussion and Analysis (MD&A) in conjunction with the accompanying basic financial
statements.
OVERVIEW OF BASIC FINANCIAL STATEMENTS
The MD&A is intended to serve as an introduction to the VPU’s basic financial statements. Included as part
of the financial statements are three separate statements.
The statement of net position presents information on the VPU’s total assets and deferred outflows of
resources and total liabilities and deferred inflows of resources, with the difference between the two reported
as net position.
The statement of revenues, expenses and changes in net position presents information showing how the
VPU's net position changed during the most recent fiscal year. Financial results are recorded using the
accrual basis of accounting. Under this method, all changes in net position are reported as soon as the
underlying events occur, regardless of the timing of cash flows. Thus, revenues and expenses reported in
this statement for some items may affect cash flows in a future fiscal period (examples include billed but
uncollected revenues and employee earned but unused vacation leave).
The statement of cash flows reports cash receipts, cash payments, and net changes in cash and cash
equivalents from operations, noncapital financing, capital, and related financing, and investing activities.
The notes to the basic financial statements provide additional information that is essential to fully understand
the data provided in the financial statements.
CITY OF VERNON
VERNON PUBLIC UTILITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(5)
FINANCIAL HIGHLIGHTS
Net Position
The table below summarizes the VPU’s net position as of the current fiscal year ended June 30, 2022 and
prior fiscal year ended June 30, 2021. The details of the current year’s summary can be found on pages 10-
11 of this report.
City of Vernon
Vernon Public Utilities
Net Position
June 30, 2022 and 2021
CITY OF VERNON
VERNON PUBLIC UTILITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(6)
Net Position (Continued)
The assets and deferred outflows of resources of the VPU exceeded its liabilities and deferred inflows of
resources at the close of the most recent fiscal year by $182,420,864 (net position).
The category of the VPU’s net position with the largest balance totaling $168,787,837 represents resources
that are invested in capital assets, net of related debt.
The second category restricted for debt services totaling $32,836,544 represents resources that are subject
to external restrictions on how they can be used, in this case bond debt.
The remaining category of net position, totaling $(19,203,517) represents a deficit in unrestricted net position
that is expected to be recovered from the VPU’s future revenues and controlling operating and maintenance
expenses.
Total current assets increased by $20,538,011 from the prior year mainly due to an increase in cash and
cash equivalents of $10,600,320, an increase in accounts receivable, net of allowance of $7,165,433, an
increase in accrued unbilled revenue of $2,047,159, and an increase in inventories of $636,909.
Capital assets increased by $203,490,086, net of depreciation, from the prior year mainly due to
acquisitions of new equipment and facility improvements. (See Note 5).
Total liabilities increased by $173,549,288 from the prior year, primarily due to an increase in accounts
payable of $3,393,468, an increase in bonds payable (current and long-term) of $175,776,445, and
partially offset by a decrease of $6,418,886 in the net pension liability.
The VPU’s total net position at fiscal year 2021-22 was $182,420,864, which increased by $35,015,359
from the prior year due to an increase in the net investment in capital assets by $20,345,074, an increase
in the funds restricted for debt service of $8,941,879 and a decrease of the unrestricted deficit net position
of $5,728,406.
CITY OF VERNON
VERNON PUBLIC UTILITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(7)
Changes in Net Position
The table below summarizes the VPU’s changes in net position over the current and prior fiscal years. The
details of the current year’s changes in net position can be found on page 12 of this report.
City of Vernon
Vernon Public Utilities
Net Position
June 30, 2022 and 2021
VPU’s operating income of $50,351,975, less net non-operating revenues (expenses) of $(15,336,616),
resulted in an increase in net position of $35,015,359 during the current year. VPU increased its net
position by $30,996,906 when compared to the prior year, which is due to the significant increase in
operating income of $26,365,629 and lower interest expense of $5,134,307 offset by the loss on the sale
of assets of $2,315,926.
CITY OF VERNON
VERNON PUBLIC UTILITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(8)
CAPITAL ASSET AND DEBT ADMINISTRATION
Capital assets
The VPU’s investment in capital assets as of June 30, 2022 amounted to $458,427,644 (net of accumulated
depreciation). This investment in capital assets includes land, intangible assets, construction in progress,
building, utilities system improvements, and machinery and equipment. The net increase in the VPU's
investment in capital assets for the current fiscal year was $201,169,979.
Additional information on the VPU's capital assets can be found in Note 5 of this report.
Outstanding debt
As of June 30, 2022, the following Electric Fund debt remains outstanding:
$37,895,000 City of Vernon Electric System Revenue Bonds, 2008 Taxable Series A
$11,505,000 City of Vernon Electric System Revenue Bonds, 2012 Taxable Series B
$111,720,000 City of Vernon Electric System Revenue Bonds, 2015 Taxable Series A
$19,305,000 City of Vernon Electric System Revenue Bonds, 2020 Series A
$173,815,000 City of Vernon Electric System Revenue Bonds, 2021 Taxable Series A
$52,070,000 City of Vernon Electric System Revenue Bonds, 2022 Taxable Series A
The City of Vernon Electric System Revenue Bonds, 2008 Taxable Series A were issued to provide funds to
(i) finance the cost of certain capital improvements to the City’s Electric System, (ii) fund a deposit to the
Debt Service Reserve Fund, and (iii) to pay costs of issuance of the 2008 Bonds.
The City of Vernon Electric System Revenue Bonds, 2012 Taxable Series B were issued to provide funds to
(i) refund the $28,680,000 aggregate principal amount of 2009 Bonds maturing on August 1, 2012, (ii) to pay
a portion of the Costs of the 2012 Project, and (iii) to pay costs of issuance of the 2012 Taxable Series B
Bonds.
The City of Vernon Electric System Revenue Bonds, 2015 Taxable Series A were issued to provide funds to
(i) refund a portion of the Outstanding Electric System Revenue Bonds, 2009 Series A; (ii) finance the costs
of certain capital improvements to the City’s Electric System by reimbursing the Electric System for the prior
payment of such costs from the Light and Power Fund; (iii) fund a deposit to the Debt Service Reserve
Fund; and (iv) pay costs of issuance of the 2015 Bonds.
The City of Vernon Electric System Revenue Bonds, 2020 Series A were issued to provide funds to (i)
finance the acquisition and construction of certain capital improvements to the Electric System of the City,
(ii) to refund all of the City’s outstanding Electric System Revenue Bonds, 2009 Series A, and (iii) to pay
costs of issuance of the 2020 Bonds.
The City of Vernon Electric System Revenue Bonds, 2021 Series A were issued to provide funds: (i) to pay
the costs of the acquisition by the City of Vernon of a 134-megawatt natural gas-fired generating facility
located within the city limits on land owned by the City, together with certain related electrical
interconnection facilities and other assets, property, and contractual rights, (ii) to fund a deposit to the Debt
Service Reserve Fund in satisfaction of the Debt Service Reserve Requirement, and (iii) to pay costs of
issuance of the 2021 Bonds.
CITY OF VERNON
VERNON PUBLIC UTILITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(9)
The City of Vernon Electric System Revenue Bonds, 2022 Series A were issued to (i) refund and defease
all the City’s outstanding Electric System Revenue Bonds, 2012 Series A and a portion of the City’s
outstanding Electric System Revenue Bonds, 2012 Taxable Series B and (ii) to pay costs of issuance of
the 2022 Bonds.
As of June 30, 2022, the following Water Fund debt remains outstanding:
$14,600,000 City of Vernon Water System Revenue Bonds, 2020 Taxable Series A
$1,220,930 City of Vernon agreement with the Water Replenishment District of Southern California
The City of Vernon Water System Revenue Bonds, 2020 Series A were issued to provide funds to (i) finance
the acquisition and construction of certain capital improvements to the Water System of the City, (ii)
purchase a municipal bond debt service reserve insurance policy for deposit in the Reserve Fund in
satisfaction of the Reserve Requirement, and (iii) to pay costs of issuance of the 2020 Bonds.
As of June 30, 2022, the ratings on all Electric System Revenue Bonds of the City were BBB+/Stable by
S&P and Baa1/Stable by Moody’s. The rating on Water System Revenue Bonds is A-/Stable by S&P.
Additional information on the VPU's long-term debt can be found in Note 6 of this report.
ECONOMIC FACTORS AND NEW YEAR’S BUDGET AND RATES
These factors were considered in preparing the VPU’s FY 2022-23 operating and capital budgets.
VPU is committed to providing dependable, high-quality electric, water, natural gas, and fiber
services at the lowest competitive rates and the highest standards for reliability.
VPU continues to respond to inflation and supply chain issues, including higher energy, natural
gas, materials and supplies, chemicals, and construction costs to maintain generation,
transmission, and distribution infrastructure to continue to provide exceptionally reliable service.
Continue to implement VPU’s capital plan, manage operating and maintenance expenses, update
the 2018 Integrated Resource Plan, complete an Electric Cost of Service Analysis and Rate
Design study, transition customer load growth to green commerce, optimize the MGS operating
profile, and continue to implement the multi-year water rate adjustment plan approved by City
Council.
REQUESTS FOR INFORMATION
This report is designed to provide an overview of the VPU’s FY 2021-22 results. Questions concerning
the fund’s financial or operating results can be addressed to Scott Williams, Director of Finance,
swilliams@cityofvernon.org, City of Vernon, 4305 Santa Fe Avenue, Vernon, California, 90058.
CITY OF VERNON
VERNON PUBLIC UTILITIES
STATEMENT OF NET POSITION
JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(10)
ASSETS
Current Assets:
Cash and Cash Equivalents 156,960,639$
Accounts Receivable, Net of Allowance 14,262,338
Accrued Unbilled Revenue 19,025,964
Accrued Interest Receivable 89,197
Due from Other City Funds -
Prepaid Items 17,666
Inventories 636,909
Total Current Assets 190,992,713
Noncurrent Assets:
Restricted Cash and Cash Equivalents 46,383,084
Advances to Other City Funds 202,798
Prepaid Items 994,736
Deposits 1,201,423
Capital Assets:
Nondepreciable 70,803,890
Depreciable, Net 387,623,754
Total Noncurrent Assets 507,209,685
Total Assets 698,202,398
DEFERRED OUTFLOWS OF RESOURCES
Deferred Outflows Related to OPEB Liability 662,143
Deferred Outflows Related to Pensions 5,338,797
Deferred Amount on Refunding 1,933,345
Total Deferred Outflows of Resources 7,934,285
CITY OF VERNON
VERNON PUBLIC UTILITIES
STATEMENT OF NET POSITION (CONTINUED)
JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(11)
LIABILITIES
Current Liabilities:
Accounts Payable 17,472,509$
Accrued Wages and Benefits 406,604
Due to Other City Funds 2,966,261
Customer Deposits 500,168
Bond Interest Payable 5,212,226
Bonds Payable 50,360,000
Note Payable 139,535
Compensated Absences 406,135
Total Current Liabilities 77,463,438
Noncurrent Liabilities:
Bonds Payable 412,712,309
Note Payable 1,081,395
Compensated Absences 812,270
Other Postemployment Benefit Liability 3,080,913
Net Pension Liability 16,564,112
Total Noncurrent Liabilities 434,250,999
Total Liabilities 511,714,437
DEFERRED INFLOWS OF RESOURCES
Deferred Inflows Related to OPEB Liability 1,577,912
Deferred Inflows Related to Pensions 10,423,470
Total Deferred Inflows of Resources 12,001,382
NET POSITION
Net Investment in Capital Assets 168,787,837
Restricted for Debt Service 32,836,544
Unrestricted (Deficit)(19,203,517)
Total Net Position 182,420,864$
CITY OF VERNON
VERNON PUBLIC UTILITIES
STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(12)
OPERATING REVENUES
Charges for Services 238,570,758$
Total Operating Revenues 238,570,758
OPERATING EXPENSES
Cost of Sales 170,314,573
Depreciation 17,904,210
Total Operating Expenses 188,218,783
OPERATING INCOME 50,351,975
NONOPERATING REVENUES (EXPENSES)
Intergovernmental 865,403
Investment Income 285,622
Net Decrease in Fair Value of Investments (8,231)
Interest Expense (14,163,484)
Loss on Disposition of Assets (2,315,926)
Total Nonoperating Revenues (Expenses)(15,336,616)
CHANGE IN NET POSITION 35,015,359
Net Position - Beginning of Year 147,405,505
NET POSITION - END OF YEAR 182,420,864$
CITY OF VERNON
VERNON PUBLIC UTILITIES
STATEMENT OF CASH FLOWS
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(13)
CASH FLOWS FROM OPERATING ACTIVITIES
Cash Received from Customers 229,353,795$
Cash Paid to Suppliers for Goods and Services (157,657,823)
Cash Paid to Employees for Services (5,801,226)
Cash Paid to City for Services (5,214,961)
Net Cash Provided by Operating Activities 60,679,785
CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES
Repayment of Bonds (35,215,000)
Issuance of Bonds 235,885,000
Bond Premiums 38,266,557
Payment to Refunding Bond Escrow Agent (62,999,903)
Bond Interest Paid (17,463,242)
Payment of Note Payable (139,535)
Net Acquisition of Capital Assets (221,394,296)
Net Cash Used by Capital and Related Financing Activities (63,060,419)
CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES
Grant Revenue Received 865,403
Payment from (Provided to) Other City Funds 1,915,195
Net Cash Provided by Noncapital Financing Activities 2,780,598
CASH FLOWS FROM INVESTING ACTIVITIES
Investment Income 190,555
Net Cash Provided by Investing Activities 190,555
CHANGE IN CASH AND CASH EQUIVALENTS 590,519
Cash and Cash Equivalents - Beginning of Year 202,753,204
CASH AND CASH EQUIVALENTS - END OF YEAR 203,343,723$
COMPOSITION OF CASH AND CASH EQUIVALENTS
Cash and Cash Equivalents 156,960,639$
Restricted Cash and Investments 46,383,084
Total 203,343,723$
CITY OF VERNON
VERNON PUBLIC UTILITIES
STATEMENT OF CASH FLOWS (CONTINUED)
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(14)
RECONCILIATION OF OPERATING INCOME TO NET CASH
PROVIDED BY OPERATING ACTIVITIES
Operating Income 50,351,975$
Adjustments to Reconcile Operating Income
to Net Cash Provided by Operating Activities:
Depreciation 17,904,210
Deferred Gain from Sale of Generation Assets (6,555,916)
Change in Operating Assets and Liabilities:
Accounts Receivable (7,165,433)
Accrued Unbilled Revenue (2,047,159)
Due from Other Funds 523,087
Prepaid Expenses and Deposits (104,017)
Inventories (636,909)
Deferred Outflows of Resources (418,807)
Accounts Payable 3,393,468
Accrued Wages and Benefits (209,527)
Due to Other City Funds 2,443,174
Customer Deposits (4,371)
Compensated Absences 36,502
Other Postemployment Benefit Liability (352,393)
Net Pension Liability (6,418,886)
Deferred Inflows of Resources 9,940,787
Net Cash Provided by Operating Activities 60,679,785$
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(15)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying financial statements present only the Vernon Public Utilities (VPU) of the
City of Vernon, California (the City), and do not present fairly the financial position and
results of the operations of the City. The VPU accounts for the independent operations and
the maintenance of the City’s electric, gas, water, and fiber optics utilities. A fund, or utility,
administered by the VPU is an independent fiscal and accounting entity with a self-balancing
set of accounts recording resources, related liabilities, obligations, reserves, and equities,
segregated for the purpose of carrying out specific activities or attaining certain objectives in
accordance with special regulations, restrictions, or limitations.
For additional information regarding the City of Vernon, refer to the City’s annual financial
report.
Ordinance No. 1242, adopted May 16, 2017, requires each utility of the City to be
independent with its assets, liabilities, and equities segregated, budgeted, and accounted for
in separate funds. Ordinance No. 1240, adopted March 21, 2017, consolidates all utilities-
related services under the management of the stand-alone entity “Vernon Public Utilities” for
better oversight and management of the day-to-day activities of such independent utilities.
Each of the City’s utilities, namely the electric, gas, water, and fiber optics utilities, were
established by the City under and by virtue of the City Charter and the City Code enacted in
1988. Prior to July 1, 2016, the electric and gas utilities were consolidated and reported as
the Light & Power Enterprise for financial reporting purposes. Ordinance No. 1242 continues
to require each utility to be independent with its assets, liabilities, and equities segregated,
budgeted, and accounted for in separate funds, while Ordinance No. 1240 enables the
consolidated financial reporting of those independent utilities for better oversight and
management.
The financial statements of the VPU have been prepared in conformity with U.S. generally
accepted accounting principles (U.S. GAAP). The Governmental Accounting Standards
Board (GASB) is the accepted standard-setting body for establishing governmental
accounting and financial reporting principles. The VPU’s significant accounting policies are
described below.
A. Basis of Presentation
The VPU’s financial statements are reported using the economic resources
measurement focus and the accrual basis of accounting. Revenues are recorded when
earned and expenses are recorded at the time liabilities are incurred, regardless of when
the related cash flows take place.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(16)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
A. Basis of Presentation (Continued)
The VPU distinguishes operating revenues and expenses from nonoperating items.
Operating revenues, such as charges for services, result from exchange transactions
associated with the sale of electricity, gas, and water. Exchange transactions are those
in which each party receives and gives up essentially equal values. Nonoperating
revenues, such as subsidies and investment earnings, result from nonexchange
transactions or ancillary activities. Operating expenses include the cost of sales and
services, administrative expenses and depreciation on capital assets. All expenses not
meeting this definition are reported as nonoperating expenses.
B. Pooled Cash
Part of the VPU’s operating cash balance is pooled with other City funds for deposit
purposes. The share of each fund in the pooled cash account is recorded in each of the
funds’ books of accounts, and interest income is apportioned to the participating funds
based on the relationship of their average monthly balances to the total of the pooled
cash.
C. Cash Deposits and Investments
For purposes of the statement of cash flows, the VPU considers all highly liquid
investments (including restricted cash and investments) with an original maturity of three
months or less when purchased to be cash equivalents. Investment transactions are
recorded on the settlement date. Investments in nonparticipating interest-earning
investment contracts are reported at cost and all other investments are reported at fair
value. Fair value is defined as the amount that the VPU could reasonably expect to
receive for an investment in a current sale between a willing buyer and a seller and is
generally measured by quoted market prices.
D. Receivables/Payables
Short-term City interfund receivables and payables are classified as “due from other City
funds” and “due to other City funds”, respectively, on the statement of net position. Long-
term City interfund receivables and payables are classified as “advances to/from other
City funds,” respectively, on the statement of net position.
Trade receivables are shown net of an allowance for uncollectible accounts. Allowances
for uncollectible accounts were $1,043,137 as of June 30, 2022. Utility customers are
billed monthly. The estimated value of services provided, but unbilled at year-end has
been included in the accompanying statement of net position.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(17)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
E. Prepaid Item
The VPU made a prepayment to Southern California Public Power Authority (SCPPA)
for the VPU’s share of SCPPA’s payoff of the Hoover Center and Air Slots debt. This
prepaid amount is amortized over the life of the debt based on the annual debt service
obligations. See Note 10 for further information regarding SCPPA.
F. Inventories
All inventories are valued at cost, or estimated historical costs when historical
information is unavailable, using the first-in/first-out (FIFO) method. Inventory costs in
the proprietary funds are recorded as an expense or capitalized into capital assets when
used.
G. Deposits
The VPU has deposits in SCPPA’s Project Stabilization Fund for use within SCPPA’s
project purposes at the VPU’s discretion. At June 30, 2022, the amount of deposits
totaled $1,201,423.
H. Capital Assets
Capital assets (including infrastructure) are recorded at historical cost or at estimated
historical cost if the actual historical cost is not available. Contributed capital assets are
recorded at their estimated acquisition value at the date contributed. Capital assets
include land, intangible assets, construction in progress, and plant assets including
building, improvements, and machinery and equipment. The capitalization threshold for
all capital assets is $5,000. Capital assets used in operations are depreciated using the
straight-line method over their estimated useful lives. Intangible assets with an indefinite
useful life are not amortized but are evaluated annually for any impairment.
The estimated useful lives are as follows:
Utility Plant 3 to 50 Years
Maintenance and repairs are charged to operations when incurred. Betterments and
major improvements, which significantly increase values, change capacities or extend
useful lives, are capitalized. Upon sale or retirement of capital assets, the cost and
related accumulated depreciation are removed from the respective accounts and any
resulting gain or loss is included in the statement of revenues, expenses, and changes in
net position.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(18)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
I. Compensated Absences
Accumulated vacation is accrued when incurred. Upon termination of employment, the
VPU will pay the employee all accumulated vacation leave at 100% of the employee’s
base hourly rate.
J.Deferred Outflows and Inflows of Resources
The VPU recognizes deferred outflows and inflows of resources. A deferred outflow of
resource is defined as consumption of net position by the VPU that is applicable to a
future reporting period. A deferred inflow of resources is defined as an acquisition of net
position by the VPU that is applicable to a future reporting period. On June 30, 2022, the
VPU has deferred outflows of resources representing deferred amounts on bond
refunding, pension-related transactions, and other postemployment benefit-related
transactions, and deferred inflows of resources representing pension-related
transactions and other postemployment benefit-related transactions.
K. Long-Term Obligations
Bond discounts and premiums and deferred amounts on refunding are amortized over
the life of the bonds using the straight-line method.
L. Net Position
The VPU financial statements utilize a net position presentation. Net position is
categorized as invested in capital assets (net of related debt), restricted and
unrestricted.
Net Investment in Capital Assets – This category groups all capital assets into
one component of net position. Accumulated depreciation and the outstanding
balances of liabilities that are attributable to the acquisition, construction or
improvement of these assets reduce the balance in this category.
Restricted Net Position – This category presents external restrictions imposed
by creditors, grantors, contributors or laws or regulations of other governments
and restrictions imposed by law through constitutional provisions or enabling
legislation.
Unrestricted Net Position – This category represents net position of the VPU
not restricted for any project or other purpose.
The VPU’s policy regarding whether to first apply restricted or unrestricted resources
when an expense is incurred for purposes for which both restricted and unrestricted net
position are available is to use restricted resources first.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(19)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
M. Use of Estimates
The preparation of basic financial statements in conformity with U.S. GAAP requires
management to make estimates and assumptions that affect certain reported amounts
and disclosures. Accordingly, actual results could differ from those estimates.
N. Pensions
For purposes of measuring the net pension liability and deferred outflows/inflows of
resources related to pensions and pension expense, information about the fiduciary net
position of the City’s California Public Employees’ Retirement System (CalPERS) plan
and additions to/deductions from the Pension Plans’ fiduciary net position have been
determined on the same basis as they are reported by CalPERS. For this purpose,
benefit payments (including refunds of employee contributions) are recognized when
due and payable in accordance with the benefit terms. Investments are reported at fair
value.
O. Postemployment Benefits Other than Pensions (OPEB)
For purposes of measuring the net OPEB liability, deferred outflows of resources and
deferred inflows of resources related to OPEB, and OPEB expense information about
the fiduciary net position of the City’s OPEB Plan and additions to/deductions from the
OPEB Plan’s fiduciary net position have been determined on the same basis as they are
reported by the OPEB Plan. For this purpose, the OPEB Plan recognizes benefit
payments when due and payable in accordance with the benefit terms. Investments are
reported at fair value.
NOTE 2 CASH AND CASH EQUIVALENTS
Cash and cash equivalents as of June 30, 2022, are classified in the accompanying
statement of net position as follows:
Cash and Cash Equivalents 156,960,639$
Restricted Cash and Cash Equivalents 46,383,084
Total Cash and Cash Equivalents 203,343,723$
Cash and cash equivalents as of June 30, 2022, consist of the following:
Equity in the City's Pooled Cash 19,875,769$
Deposits with Financial Institutions 45,261,169
Short-Term Investments 138,206,785
Total Cash and Cash Equivalents 203,343,723$
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(20)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Equity in the Cash Pool of the City of Vernon
The VPU has equity in the cash pool managed by the City. The VPU is a voluntary
participant in that pool and the pool is governed by and under the regulatory oversight of the
Investment Policy adopted by the City Council of the City. The VPU has not adopted an
investment policy separate from that of the City. The amount of the VPU’s cash in this pool
is reported in the accompanying financial statements based upon the VPU’s pro rata share
of the amount calculated by the City. The balance available for withdrawal is based on the
accounting records maintained by the City.
The City’s Investment Policy
The City’s Investment Policy sets forth the investment guidelines for all funds of the City.
The Investment Policy conforms to the California Government Code Section 53600 et. seq.
The authority to manage the City’s investment program is derived from the City Council.
Pursuant to Section 53607 of the California Government Code, the City Council annually,
appoints the City Treasurer to manage the City’s investment program and approves the
City’s investment policy. The Treasurer is authorized to delegate this authority as deemed
appropriate. No person may engage in investment transactions except as provided under
the terms of the Investment Policy and the procedures established by the Treasurer.
This Investment Policy requires that the investments be made with the prudent person
standard, that is, when investing, reinvesting, purchasing, acquiring, exchanging, selling or
managing public funds, the trustee (Treasurer and staff) will act with care, skill, prudence,
and diligence under the circumstances then prevailing, including but not limited to, the
general economic conditions and the anticipated needs of the City.
The Investment Policy also requires that when following the investing actions cited above,
the primary objective of the trustee be to safeguard the principal, secondarily meet the
liquidity needs of depositors, and then achieve a return on the funds under the trustee’s
control. Further, the intent of the Investment Policy is to minimize the risk of loss on the
City’s held investments from:
A. Credit risk
B. Custodial credit risk
C. Concentration of credit risk
D. Interest rate risk
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(21)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Investments Authorized by the California Government Code and the City’s Investment
Policy
The table below identifies the investment types that are authorized for the City by the
California Government Code and the City’s Investment Policy. The table also identifies
certain provisions of the California Government Code that address interest rate risk, credit
risk, and concentration of credit risk. This table does not address investment of debt
proceeds held by the bond trustee that are governed by the provisions of debt agreements
of the City, rather than the general provisions of the California Government Code or the
City’s Investment Policy.
Maximum Maximum
Authorized Maximum Percentage Investment Minimum
Investment Type Maturity of Portfolio* in One Issuer Rating
U.S. Treasury Bonds 5 Years None None None
State and Local Agency Bonds 5 Years None None None
Securities of the U.S. Government, or
its Agencies 5 Years None None None
Certain Asset-Backed Securities 5 Years 20% None AA
Negotiable Certificates of Deposit 5 Years 30% None None
Bankers' Acceptances 180 Days 40% 30% None
Commercial Paper 270 Days 25% 10% P-1
Repurchase Agreements 1 year None None None
Reverse Repurchase Agreements 92 Days 20% None None
Medium-Term Notes 5 Years 30% None A
Mutual Funds Investing in Eligible Securities N/A 20% 10% AAA
Money Market Mutual Funds N/A 20% 10% AAA
Mortgage Pass-Through Securities 5 Years 20% None AA
State Administered Pool Investment N/A None $75 Million None
* Excluding amounts held by bond trustee that are not subject to California Government Code restrictions.
Investments Authorized by Debt Agreements
Investments of debt proceeds held by bond trustees are governed by provisions of the debt
agreements, rather than the general provisions of the California Government Code or the
City’s Investment Policy. The table below identifies the investment types that are authorized
for investments held by the bond trustee. The table also identifies certain provisions of these
debt agreements that address interest rate risk, credit risk, and concentration of credit risk.
Maximum Maximum
Authorized Maximum Percentage Investment Minimum
Investment Type Maturity of Portfolio in One Issuer Rating
Securities of the U.S. Government, or
its Agencies None None None None
Certain Asset-Backed Securities None None None AA
Certificates of Deposit None None None None
Bankers' Acceptances 1 Year None None None
Commercial Paper None None None P-1
Money Market Mutual Funds N/A None None AAA
State Administered Pool Investment N/A None $75 Million None
Investment Contracts None None None None
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(22)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Disclosure Relating to Interest Rate Risk
Interest rate risk is the risk that changes in market interest rates will adversely affect the fair
value of an investment. Generally, the longer the maturity of an investment, the greater the
sensitivity of its fair value to changes in market interest rates. One of the ways that the City
manages its exposure to interest rate risk is by purchasing a combination of shorter-term
and longer-term investments and by timing cash flows from maturities so that a portion of
the portfolio is maturing or coming close to maturity evenly over time as necessary to
provide the cash flow and liquidity needed for operations. The City has no specific limitations
with respect to this metric. Information about the sensitivity of the fair values of the VPU’s
investments (including investments held by bond trustee) to market interest rate fluctuations
is provided in the following table that shows the distribution of the VPU’s investments by
maturity:
Investment Maturities
Fair Value (in Months)
as of Less than 13 to 25 to
Investment Type 6/30/2022 12 Months 24 Months 60 Months
Local Agency Investment Fund 627,044$ 627,044$ -$ -$
Held by Trustee:
Money Market Mutual Funds 137,579,740 137,579,740 - -
Total investments 138,206,784$ 138,206,784$ -$ -$
Disclosures Relating to Credit Risk
Generally, credit risk is the risk that an issuer of an investment will not fulfill its obligation to
the holder of the investment. This is measured by the assignment of a rating by a nationally
recognized statistical rating organization. Presented below is the minimum rating required by
the California Government Code, the City’s Investment Policy, or debt agreements, and the
actual rating as of the year-end for each investment type.
Minimum Actual Fair Value
Required Credit Rating as of
Investment Type Rating Moody's / S&P June 30, 2022
Local Agency Investment Fund Not Rated Not Rated 627,044$
Held by Trustee:
Money Market Mutual Funds Aaa / AAA Aaa / AAA 137,579,740
Total investments 138,206,784$
Concentration of Credit Risk
The City’s Investment Policy places no limit on the amount the City may invest in any one
issuer excluding a 10% limitation on commercial paper, mutual funds, and money market
mutual funds and a 30% limitation on bankers’ acceptances. The City’s Investment Policy
also places no limit on the amount of debt proceeds held by the bond trustee that the trustee
may invest in one issuer that is governed by the provisions of debt agreements of the City,
rather than the general provisions of the California Government Code or the City’s
Investment Policy. As of June 30, 2022, there were no investments held by the VPU that
exceeded 5% in any one issuer, excluding money market mutual funds.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(23)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Custodial Credit Risk
Custodial credit risk for deposits is the risk that, in the event of the failure of a depository
financial institution, a government will not be able to recover its deposits or will not be able
to recover collateral securities that are in the possession of an outside party. The custodial
credit risk for investments is the risk that, in the event of the failure of the counterparty to a
transaction, a government will not be able to recover the value of its investment or collateral
securities that are in the possession of another party. The California Government Code and
the City’s Investment Policy do not contain legal or policy requirements that would limit the
exposure to custodial credit risk for deposits or investments. Under the California
Government Code, a financial institution is required to secure deposits, in excess of the
FDIC insurance amount of $250,000, made by state or local governmental units by pledging
government securities held in the form of an undivided collateral pool. The market value of
the pledged securities in the collateral pool must equal at least 110% of the total amount
deposited by the public agencies. California law also allows financial institutions to secure
City deposits by pledging first trust deed mortgage notes having a value of 150% of the
secured public deposits. Such collateral is held by the pledging financial institution’s trust
department or agent in the City’s name.
At June 30, 2022, all of the VPU’s deposits were insured or collateralized as required by
Section 53652 of the California Government Code.
Local Agency Investment Fund (LAIF)
The VPU also maintained cash balances with the state of California Local Agency
Investment Fund (LAIF). LAIF is an external investment pool sponsored by the state of
California. The administration of LAIF is provided by the California State Treasurer and
regulatory oversight is provided by the Pooled Money Investment Board and the Local
Investment Advisory Board. The value of the pool shares in LAIF, which may be withdrawn,
is determined on an amortized cost basis, which is different than the fair value of VPU’s
position in the pool.
Fair Value Measurement
The VPU categorizes its fair value measurements within the fair value hierarchy established
by generally accepted accounting principles. The hierarchy is based on the valuation inputs
used to measure the fair value of the asset.
Level 1 inputs are quoted prices for identical assets or liabilities in active markets
that the government can access at the measurement date.
Level 2 inputs are other than quoted prices included in Level 1 that are observable
for an asset or liability, either directly or indirectly.
Level 3 inputs are unobservable inputs for an asset or liability.
The VPU’s investments in money market mutual funds and LAIF are not subject to
categorization in the fair value hierarchy.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(24)
NOTE 3 ACCOUNTS RECEIVABLE
The VPU’s accounts receivable at June 30, 2022, are as follows:
Accounts Receivable 15,305,475$
Less: Allowance for Uncollectible Accounts (1,043,137)
Total Accounts Receivable, Net 14,262,338$
NOTE 4 INTERNAL TRANSACTIONS
Transactions between the VPU and the City commonly occur in the normal course of
business for services received or furnished (accounting, management, engineering, legal
services, and capital projects).
Advances to Other City Funds
The following table summarizes the VPU’s advances to the other City funds at
June 30, 2022:
Advances to Other City Funds - July 1, 2021 2,117,993$
Advance Repaid by City Funds During the Year (1,915,195)
Advances to Other City Funds - June 30, 2022 202,798$
The advances between the other City funds and the VPU does not accrue interest due to
the nature of the City’s operational relationship and capital projects funded by the VPU that
benefits both. On November 6, 2012, the City adopted Resolution No. 2012-215 extending
the repayment term of the loan to the City from 15 months to a period of over 10 years.
The City’s General Fund allocates certain administrative and overhead costs to the VPU
which the VPU financial statements include as part of the cost of sales. The allocated costs
for the year ended June 30, 2022, were $3,813,444.
Transfers from (to) City
The VPU’s electric retail rates are established by the City Council and are not subject to
regulation by the California Public Utility Commission or any other state agency. The retail
rates include a 3% surcharge for payments in lieu of franchise tax to the City’s General
Fund. For the current year, the VPU transferred to the City’s General Fund $5,033,574 in
lieu of franchise tax. This amount is reported in the accompanying financial statements as
part of operating expenses.
Under the City Charter and the VPU’s electric revenue bond indentures, the VPU’s electric
utility is allowed to transfer up to 11.5% of its retail sales after meeting debt service
obligations and certain debt coverage ratios. However, no additional transfers were made
for the year ended June 30, 2022.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(25)
NOTE 5 CAPITAL ASSETS
Capital asset activity of the VPU for the fiscal year ended June 30, 2022, was as follows:
Balance Balance
June 30, 2021 Additions Deletions Transfers June 30, 2022
Capital Assets, Not Being Depreciated:
Electric Utility - Land 13,193,594$ -$ -$ -$ 13,193,594$
Water Utility - Water 467,640 - - - 467,640
Electric Utility - Intangibles - Environmental Credits 1,163,811 3,610,772 - - 4,774,583
Electric Utility - Construction in Progress 45,324,750 129,024 - - 45,453,774
Water Utility - Construction in Progress 4,635,417 2,366,637 - (87,755) 6,914,299
Total Capital Assets, Not Being
Depreciated 64,785,212 6,106,433 - (87,755) 70,803,890
Capital Assets, Being Depreciated:
Electric Utility - Production Plant 16,189,303 196,173,685 - - 212,362,988
Electric Utility - Transmission Plant 4,888,113 - (1,271,649) - 3,616,464
Electric Utility - Distribution Plant 258,451,179 16,781,817 (18,181,346) - 257,051,650
Electric Utility - General Plant 9,587,933 192,379 (25,903) - 9,754,409
Water Utility Plant 23,765,353 1,666,662 (1,789,499) 87,755 23,730,271
Gas Utility Plant 26,973,692 261,506 (34,604) - 27,200,594
Fiber Optic Utility Plant 4,161,378 211,814 (616,583) - 3,756,609
Total Capital Assets, Being Depreciated 344,016,951 215,287,863 (21,919,584) 87,755 537,472,985
Less Accumulated Depreciation for:
Electric Utility - Production Plant (10,757,493) (8,634,043) - - (19,391,536)
Electric Utility - Transmission Plant (3,424,581) (78,093) 1,059,485 - (2,443,189)
Electric Utility - Distribution Plant (101,227,123) (7,438,076) 16,493,501 - (92,171,698)
Electric Utility - General Plant (6,148,921) (360,709) 25,903 - (6,483,727)
Water Utility Plant (15,723,755) (500,102) 1,379,658 - (14,844,199)
Gas Utility Plant (11,142,926) (707,035) 28,528 - (11,821,433)
Fiber Optic Utility Plant (3,123,880) (186,152) 616,583 - (2,693,449)
Total Accumulated Depreciation (151,548,679) (17,904,210) 19,603,658 - (149,849,231)
Total Capital Assets, Being Depreciated, Net:
Electric Utility - Production Plant 5,431,810 187,539,642 - - 192,971,452
Electric Utility - Transmission Plant 1,463,532 (78,093) (212,164) - 1,173,275
Electric Utility - Distribution Plant 157,224,056 9,343,741 (1,687,845) - 164,879,952
Electric Utility - General Plant 3,439,012 (168,330) - - 3,270,682
Water Utility Plant 8,041,598 1,166,560 (409,841) 87,755 8,886,072
Gas Utility Plant 15,830,766 (445,529) (6,076) - 15,379,161
Fiber Optic Utility Plant 1,037,498 25,662 - - 1,063,160
Total 192,468,272 197,383,653 (2,315,926) 87,755 387,623,754
Total Capital Assets, Net 257,253,484$ 203,490,086$ (2,315,926)$ -$ 458,427,644$
The VPU’s total depreciation expense for the year was $17,904,210, broken down as
follows:
Electric Fund 16,510,921$
Gas Fund 707,035
Water Fund 500,102
Fiber Optics Fund 186,152
Total Depreciation Expense 17,904,210$
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(26)
NOTE 6 LONG-TERM OBLIGATIONS
As of June 30, 2022, outstanding debt obligations consisted of the following:
$43,765,000 Electric System Revenue Bonds (2008 Taxable Series A)
At June 30, 2022, $37,895,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $72,050,772, payable through
fiscal year 2039. For the current year, debt service and net electric revenues were
$4,240,768 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2008 Taxable Series A were issued to provide funds to (i) finance the cost of certain capital
improvements to the City’s Electric System, (ii) fund a deposit to the Debt Service Reserve
Fund, and (iii) to pay costs of issuance of the 2008 Bonds.
$37,640,000 Electric System Revenue Bonds (2012 Series A)
On January 10, 2012, the City issued Electric System Revenue Bonds, 2012 Series A, in the
amount of $37,640,000. The City of Vernon Electric System Revenue Bonds, 2012 Series A
were issued to provide funds to (i) pay a portion of the costs of certain capital improvements
to the City’s Electric System, (ii) to provide for capitalized interest on the 2012 Series A
Bonds, and (iii) to pay costs of issuance of the 2012 Series A Bonds. The Electric System
Revenue Bonds were refunded in the current fiscal year with the issuance of the Electric
System Revenue Bonds 2021 Series A.
$35,100,000 Electric System Revenue Bonds (2012 Taxable Series B)
On January 10, 2012, the City issued Electric System Revenue Bonds, 2012 Series B, in the
amount of $35,100,000. During the current fiscal year, a portion of the Electric System
Revenue Bonds were refunded with the issuance of the Electric System Revenue Bonds
2022 Series A. At June 30, 2022, $11,505,000 remained outstanding. The bonds are special
obligation bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $12,752,831, payable through
fiscal year 2027. For the current year, debt service and net electric revenues were
$25,817,900 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2012 Taxable Series B were issued to provide funds to (i) refund the $28,680,000 aggregate
principal amount of 2009 Bonds maturing on August 1, 2012, (ii) to pay a portion of the
Costs of the 2012 Project, and (iii) to pay costs of issuance of the 2012 Taxable Series B
Bonds.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(27)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
$111,720,000 Electric System Revenue Bonds (2015 Taxable Series A)
At June 30, 2022, $111,720,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $124,140,019, payable through
fiscal year 2027. For the current year, debt service and net electric revenues were
$5,087,518 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2015 Taxable Series A were issued to provide funds to (i) refund a portion of the
Outstanding Electric System Revenue Bonds, 2009 Series A; (ii) finance the costs of certain
Capital Improvements to the City’s Electric System by reimbursing the Electric System for
the prior payment of such Costs from the Light and Power Fund; (iii) fund a deposit to the
Debt Service Reserve Fund; and (iv) pay costs of issuance of the 2015 Bonds.
$71,990,000 Electric System Revenue Bonds (2020 Series A)
At June 30, 2022, $19,305,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $30,319,875, payable through
fiscal year 2038. For the current year, debt service and net electric revenues were
$25,596,000 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2020 Series A were issued to provide funds to (i) to finance the acquisition and construction
of certain capital improvements to the Electric System of the City, (ii) to refund all the City’s
outstanding Electric System Revenue Bonds, 2009 Series A, and (iii) to pay costs of
issuance of the 2020 Bonds.
$183,815,000 Electric System Revenue Bonds (2021 Series A)
In December 2021, the City of Vernon issued 2021A Electric System Revenue Bonds in the
amount of $183,815,000 (i) to pay the costs of the acquisition by the City of Vernon of a
134-megawatt natural gas-fired generating facility located within the City limits on land
owned by the City, together with certain related electrical interconnection facilities and other
assets, property, and contractual rights; (ii) to fund a deposit to the Debt Service Reserve
Fund in satisfaction of the Debt Service Reserve Requirement; and (iii) to pay costs of
issuance of the 2021 bonds.
The bonds bear interest rates between 4.00%-5.00% that is payable on a semi-annual basis
on April 1 and October 1, commencing April 1, 2022. At June 30, 2022, $173,815,000
remained outstanding. The bonds are special obligation bonds which are secured by an
irrevocable pledge of electric revenues payable to bondholders. The debt service remaining
on the bonds is $207,098,300, payable through fiscal year 2028. For the current year, debt
service and net electric revenues were $12,671,686 and $69,089,394, respectively.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(28)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
$183,815,000 Electric System Revenue Bonds (2021 Series A) (Continued)
Under the Bond Indenture of Trust, interest and principal on the bonds are payable from Net
Revenues (or Revenues less Operation and Maintenance Expenses) and/or amounts in the
Light and Power Enterprise (as those terms are defined in the Indenture of Trust).
$52,070,000 Electric System Revenue Bonds (2022 Series A)
In December 2021, the City of Vernon issued 2022A Electric System Revenue Bonds in the
amount of $52,070,000 to refund the 2012A Electric System Revenue Bonds, a portion of
the 2012B Electric Revenue Bonds, and provide for the costs of issuing the bonds.
The bonds bear interest rates between 4.00%-5.00% that is payable on a semi-annual basis
beginning February 1 and August 1, commencing on August 1, 2022. At June 30, 2022,
$52,070,000 remained outstanding. The bonds are special obligation bonds which are
secured by an irrevocable pledge of electric revenues payable to bondholders. The debt
service remaining on the bonds is $78,789,447, payable through fiscal year 2042. For the
current year, debt service and net electric revenues were $0 and $69,089,394, respectively.
Under the Bond Indenture of Trust, interest and principal on the bonds are payable from Net
Revenues (or Revenues less Operation and Maintenance Expenses) and/or amounts in the
Light and Power Enterprise (as those terms are defined in the Indenture of Trust). The City
of Vernon Electric System Revenue Bonds, 2021 Series A were issued to (i) refund and
defease all of the City’s outstanding Electric System Revenue Bonds, 2012 Series A and a
portion of the City’s outstanding Electric System Revenue bonds, 2012 Taxable Series B
and (ii) pay costs of issuance of the 2022 Bonds.
$14,840,000 Water System Revenue Bonds (2020 Series A)
At June 30, 2022, $14,600,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of water revenues payable to
bondholders. The debt service remaining on the bonds is $25,040,038, payable through
fiscal 2051. For the current year, debt service and net water revenues were $827,975 and
$3,194,732, respectively. Under the Indenture of Trust dated May 6, 2020, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Water Enterprise (as those terms are
defined in the Indenture of Trust). The City of Vernon Water System Revenue Bonds, 2020
Series A were issued to provide funds to (i) finance the acquisition and construction of
certain capital improvements to the Water System of the City, (ii) purchase a municipal bond
debt service reserve insurance policy for deposit in the Reserve Fund in satisfaction of the
Reserve Requirement, and (iii) to pay costs of issuance of the 2020 Bonds.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(29)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
A summary of bonds payable under the VPU is as follows:
Fixed Annual Original
Interest Principal Issue Outstanding
Bonds Maturity Rates Installments Amount June 30, 2022
Electric System:
City of Vernon 07/01/38 7.40% - To begin 07/01/10: 43,765,000$ 37,895,000$
Electric System Revenue Bonds, 8.59% $265,000 -
2008 Taxable Series A $4,065,000
City of Vernon 08/01/26 6.25% - To begin 08/01/22: 35,100,000 11,505,000
Electric System Revenue Bonds, 6.50% $6,165,000 -
2012 Taxable Series B $7,940,000
City of Vernon 08/01/26 4.05% - To begin 08/01/23: 111,720,000 111,720,000
Electric System Revenue Bonds, 4.85% $15,925,000 -
2015 Taxable Series A $22,540,000
City of Vernon 08/01/50 5.00% To begin 08/03/20: 71,990,000 19,305,000
Electric System Revenue Bonds, $1,525,000 -
2020 Taxable Series A $28,655,000
City of Vernon 04/01/28 4% - To begin 04/01/22: 183,815,000 173,815,000
Electric System Revenue Bonds, 5.00% $10000,000 -
2021 Taxable Series A $54,915,000
City of Vernon 08/01/41 5.00% To begin 05/05/22: 52,070,000 52,070,000
Electric System Revenue Bonds, $950,000 -
2022 Taxable Series A $5,850,000
Premiums 42,795,419
Discounts (1,168,943)
Total Electric System
Revenue Bonds 447,936,476
Water System:
City of Vernon 08/01/50 5.00% To begin 08/01/21: 14,840,000 14,600,000
Water System Revenue Bonds, $240,000 -
2020 Taxable Series A $3,785,000
Premium 535,833
Total Water System
Revenue Bonds 15,135,833
Total Revenue Bonds 463,072,309$
Note Payable – Direct Borrowing
In May 2019, the City entered into an agreement with Water Replenishment District of
Southern California (WRD) for assistance with the construction of a new groundwater well or
rehabilitation of an existing groundwater well. The promissory note is unsecured and has no
interest basis for an amount not to exceed $1,500,000. As of June 30, 2022, WRD has
disbursed all of the funds under the agreement to the City. The note is payable in quarterly
principal payments commencing September 1, 2020, in an amount which, together with all
quarterly payments, will be sufficient to fully amortize the principal balance of the note by the
maturity date of April 1, 2031.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(30)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
Note Payable – Direct Borrowing (Continued)
Upon an event of default, WRD may declare any or all of the outstanding and unpaid
principal balance immediately due and payable, without presentment, demand, protest,
notice of protest, notice of acceleration or of intention to accelerate or any other notice,
declaration or act of any kind, all of which are hereby expressly waived by the City.
Debt Service Requirements
As of June 30, 2022, annual debt service requirements of the VPU to maturity are as
follows:
Electric System Revenue Bonds
2008 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 1,025,000$ 3,211,156$
2024 1,120,000 3,119,029
2025 1,220,000 3,018,526
2026 1,330,000 2,909,004
2027 1,450,000 2,789,603
2028-2032 9,445,000 11,747,040
2033-2037 14,510,000 6,677,437
2038-2041 7,795,000 683,979
Total Requirements 37,895,000$ 34,155,772$
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(31)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
Debt Service Requirements (Continued)
Electric System Revenue Bonds
2012 Taxable Series B
Fiscal Year Ending June 30,Principal Interest
2023 6,165,000$ 531,831$
2024 1,170,000 302,613
2025 1,305,000 225,269
2026 1,390,000 140,181
2027 1,475,000 47,938
Total Requirements 11,505,000$ 1,247,832$
Electric System Revenue Bonds
2015 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 22,540,000$ 4,580,368$
2024 23,520,000 3,596,938
2025 24,585,000 2,530,618
2026 25,780,000 1,341,193
2027 15,295,000 370,904
Total Requirements 111,720,000$ 12,420,019$
Electric System Revenue Bonds
2020 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 -$ 965,250$
2024 - 965,250
2025 - 965,250
2026 - 965,250
2027 - 965,250
2028-2032 6,585,000 4,188,125
2033-2037 10,325,000 1,940,625
2038-2041 2,395,000 59,875
Total Requirements 19,305,000$ 11,014,875$
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(32)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
Debt Service Requirements (Continued)
Fiscal Year Ending June 30,Principal Interest
2023 20,380,000$ 8,385,050$
2024 21,335,000 7,405,125
2025 22,400,000 6,325,000
2026 23,530,000 5,190,875
2027 31,255,000 3,917,875
2028-2032 54,915,000 2,059,375
Total Requirements 173,815,000$ 33,283,300$
Electric System Revenue Bonds
2021 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 -$ 1,923,697$
2024 4,690,000 2,486,250
2025 4,885,000 2,246,875
2026 5,130,000 1,996,500
2027 5,405,000 1,733,125
2028-2032 5,270,000 7,357,500
2033-2037 6,765,000 5,860,625
2038-2042 19,925,000 3,114,875
Total Requirements 52,070,000$ 26,719,447$
Electric System Revenue Bonds
2022 Taxable Series A
Water System Revenue Bonds
2020 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 250,000$ 575,725$
2024 265,000 562,850
2025 275,000 549,350
2026 - 542,475
2027 - 542,475
2028-2032 1,985,000 2,563,500
2033-2037 2,180,000 2,052,625
2038-2042 2,680,000 1,535,450
2043-2047 3,180,000 1,051,925
2048-2051 3,785,000 463,663
Total Requirements 14,600,000$ 10,440,038$
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(33)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
Debt Service Requirements (Continued)
Note Payable- Direct Borrowing
Fiscal Year Ending June 30,Principal Interest
2023 139,535$ -$
2024 139,535 -
2025 139,535 -
2026 139,535 -
2027 139,535 -
2028-2031 523,256 -
Total Requirements 1,220,930$ -$
Changes in Long-Term Liabilities
The following is a summary of long-term liabilities transactions for the fiscal year ended
June 30, 2022:
Amounts
Balance Balance Due Within
June 30, 2021 Additions Reductions June 30, 2022 One Year
Other Debt - Bonds Payable 281,475,000$ 235,885,000$ (96,450,000)$ 420,910,000$ 50,360,000$
Bond Premium 7,744,795 38,266,557 (2,680,100) 43,331,252 -
Bond Discount (1,923,931) - 754,988 (1,168,943) -
Note Payable- Direct Borrowing 1,360,465 - (139,535) 1,220,930 139,535
Compensated Absences (Note 1) 1,181,903 805,554 (769,052) 1,218,405 406,135
Total 289,838,232$ 274,957,111$ (99,283,699)$ 465,511,644$ 50,905,670$
Expense Stabilization Fund
The VPU maintains an Expense Stabilization Fund held by a Trustee in such amounts, at
such times and from sources as shall be determined by the City in its sole discretion. If an
Event of Default under the Indenture has occurred and is continuing, the Trustee shall
transfer all moneys in this fund to the debt service funds as provided in the Indenture.
Moneys on deposit in this Fund may be withdrawn by the City at any time that no Event of
Default exists under the Indenture. As at June 30, 2022, this fund has a balance of
$38,934,149.
Right to Accelerate Upon Default
Notwithstanding anything contrary in the Indenture or in the Bonds, upon the occurrence of
an Event of Default, the Trustee may, with the consent of each Credit Provider whose
consent is required by a Supplemental Indenture or a Credit Support Agreement, and shall,
at the direction of the Owners of a majority in principal amount of Outstanding Bonds (other
than Bonds owned by or on behalf of the City) by written notice to the City, declare the
principal of the Outstanding Bonds and the interest thereon to be immediately due and
payable, whereupon such principal and interest shall, without further action, become and be
immediately due and payable.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(34)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
Credit Ratings
As of June 30, 2022, the ratings on all Electric System Revenue Bonds is BBB+/Stable by
S&P and Baa1/Stable by Moody’s and the ratings on all Water System Revenue Bonds is A-
/Stable by S&P and not rated by Moody’s.
NOTE 7 RISK MANAGEMENT
The VPU is in the City’s self-insurance program as part of its policy to self-insure certain
levels of risk within separate lines of coverage to maximize cost savings.
The City is exposed to various risks of loss related to torts; theft of, damage to, and
destruction of assets, errors, and omissions; injuries to employees, and natural disasters.
The City utilizes insurance policy(s) to transfer these risks. Each policy has either self-
insured retention or deductible, which are parts of the City’s Risk Financing Program. These
expenses are paid on a cash basis as they are incurred. There have been no significant
settlements or reductions in insurance coverage during the past three fiscal years.
Starting in Fiscal 2010, the City chose to establish Risk Financing in the General Fund,
whereby assets are set aside for claim-litigation settlements associated with the above-
mentioned risks up to their self-insured retentions or policy deductibles. Athens
Administrators Inc. is the Third-Party Administrator for the City’s workers’ compensation
program and they provide basic services for general liability claims and litigation.
The insurance limits for the fiscal year 2022 are as follows:
Deductible/SIR
Insurance Type Program Limits (Self-Insured Retention)
Excess Liability Insurance $20,000,000 $2,000,000 SIR per occurrence
D and O Employment Practice $2,000,000 $150,000 SIR non-safety; $150,000 SIR safety
Excess Workers Compensation $50,000,000 $1,500,000 SIR per occurrence for presumptive loss
Employer's Liability $1,000,000 $1,000,000 SIR per occurrence for all employees
Commercial Property Insurance $100,000,000 $25,000 except:
$25,000,000 Flood Sublimit $250,000 power stations
$1.5/kVA transfers, subject to a $250,000 minimum
$500,000 named transformers
Employee Dishonest - Crime $1,000,000 $25,000
Pollution - Site Owned $5,000,000 $25,000 for non-utility locations, divested locations
and scheduled storage tanks
$50,000 for utility locations
$100,000 for natural gas pipeline
Cyber Liability $3,000,000 $100,000
Contractors Equipment/Auto $10,000,000 Maximum Loss Per Occurrence $5,000
Physical Damage $1,000,000 Equipment Limit-loss or damage to
any one piece
Residential Property Insurance $8,023,126 Blanket Building Limit $2,500
$89,013 Blanket Business Personal Property Limit
Terrorism and Sabotage $100,000,000 Policy Aggregate N/A
$5,000,000 Active Shooter and Malicious Attack
Per Occurrence/Aggregate
$5,000,000 Terrorism and Sabotage Liability
Per Occurrence/Aggregate
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(35)
NOTE 7 RISK MANAGEMENT (CONTINUED)
The City has numerous claims and pending litigations, which generally involve accidents
and/or liability or damage to City property. The balance of claims/litigations against the City
is in the opinion of management, ordinary routine matters, incidental to the normal business
conducted by the City. In the opinion of management, such proceedings are substantially
covered by insurance, and the ultimate dispositions of such proceedings are not expected to
have a material adverse effect on the VPU’s financial position, results of operations or cash
flows. Further information regarding the City’s self-insurance program may be found in the
City’s Annual Financial Report.
NOTE 8 PENSION PLAN
A. General Information about the Pension Plans
Plan Descriptions
All full-time safety and miscellaneous personnel and temporary or part-time employees
who have worked a minimum of 1,000 hours in a fiscal year are eligible to participate in
the City’s agent multiple-employer defined benefit pension Safety and Miscellaneous
Plans administered by the California Public Employees’ Retirement System (CalPERS)
that acts as a common investment and administrative agent for participating public
entities within the state of California. The City allocates the costs of these Plans across
all City departments. The VPU’s proportionate share of the net pension liability of these
Plans is reported as a cost-sharing plan in the financial statements. Benefits vest after
five years of service. Employees who retire at the minimum retirement age with five
years of credited service are entitled to retirement benefits. Monthly retirement benefits
are based on a percentage of an employee’s average compensation for his or her
highest consecutive 12 or 36 months of compensation for each year of credited service.
Benefits Provided
Miscellaneous members hired prior to January 1, 2013, with five years of credited
service may retire at age 55 based on a benefit factor derived from the 2.7% at 55
Miscellaneous formula or may retire between ages 50 and 54 with reduced retirement
benefits. New Miscellaneous members (PEPRA) with five years of credited service may
retire at age 62 based on a benefit factor derived from the 2% at 62 Miscellaneous
formula or may retire between age 52 and 61 with reduced retirement benefits. The
benefit factor increases to a maximum of 2.5% at age 67. Safety members with five
years of credited service may retire at age 50 based on a benefit factor derived from the
3% at 50 Safety formula for sworn Police and Fire Department employees. New Safety
members (PEPRA) with five years of credited service may retire at age 57 based on a
benefit factor derived from the 2.7% at 57 Safety (PEPRA) formula or may retire
between age 50 and 56 with reduced retirement benefits for new Safety (PEPRA)
members of both Police and Fire Departments. CalPERS also provides death and
disability benefits. These benefit provisions and all other requirements are established
by State statute provided through a contract between the City and CalPERS.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(36)
NOTE 8 PENSION PLAN (CONTINUED)
A. General Information about the Pension Plans (Continued)
Benefits Provided (Continued)
The Plans’ provisions and benefits in effect for the measurement date of June 30, 2021,
are summarized as follows:
Miscellaneous
Prior to On or After
Hire Date January 1, 2013 January 1, 2013
Benefit Formula 2.7%@55 2%@62
Benefit Vesting Schedule 5 Years of Service 5 Years of Service
Benefit Payments Monthly for Life Monthly for Life
Retirement Age 50 52
Monthly Benefits, as a % of Eligible Compensation 2.0% to 2.7% 1.0% to 2.5%
Required Employee Contribution Rates 8.000% 6.250%
Required Employer Contribution Rates:
Normal Cost Rate 11.380% 11.380%
Payment of Unfunded Liability 3,924,540$ -$
Safety
Prior to On or After
Hire Date January 1, 2013 January 1, 2013
Benefit Formula 3.0%@50 2.7%@57
Benefit Vesting Schedule 5 Years of Service 5 Years of Service
Benefit Payments Monthly for Life Monthly for Life
Retirement Age 50 50
Monthly Benefits, as a % of Eligible Compensation 3.000% 2.0% to 2.7%
Required Employee Contribution Rates 9.000% 13.750%
Required Employer Contribution Rates:
Normal Cost Rate 22.780% 22.780%
Payment of Unfunded Liability 7,063,113$ 15,563$
Contributions
Section 20814(c) of the California Public Employees’ Retirement Law requires that the
employer contribution rates for all public employers be determined on an annual basis by
the actuary and shall be effective on July 1 following notice of a change in the rate.
Funding contributions for both Plans are determined annually on an actuarial basis as of
June 30 by CalPERS. The actuarially determined rate is the estimated amount
necessary to finance the costs of benefits earned by employees during the year, with an
additional amount to finance any unfunded accrued liability. The City is required to
contribute to the difference between the actuarially determined rate and the contribution
rate of employees. For the year ended June 30, 2022, the VPU’s share of employer
contributions made to the plans was $2,674,983.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(37)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions
Actuarial Assumptions
The net pension liability of each of the Plans is measured as of June 30, 2021, using an
annual actuarial valuation as of June 30, 2020, rolled forward to June 30, 2021, using
standard update procedures. A summary of principal assumptions and methods used to
determine the net pension liability is shown below.
Miscellaneous Safety
Valuation Date June 30, 2020 June 30, 2020
Measurement Date June 30, 2021 June 30, 2021
Actuarial Cost Method Entry Age Normal Entry Age Normal
Actuarial Assumptions:
Discount Rate 7.15% 7.15%
Inflation 2.500% 2.500%
Payroll Growth 2.750% 2.750%
Projected Salary Increase (1)(1)
Mortality Rate Table (2)(2)
Post-Retirement Benefit Increase (3)(3)
(1)Varies by entry age and service.
(2)The mortality table used was developed based on CalPERS-specific data. The
probabilities of mortality are based on the 2017 CalPERS Experience Study for the
period from 1997 to 2015. Pre-retirement and Post-retirement mortality rates includes
15 years of projected mortality improvement using 90% of Scale MP-2016 published by
the Society of Actuaries. For more details on this table, please refer to the CalPERS
Experience Study and Review of Actuarial Assumptions report from December 2017
that can be found on the CalPERS website.
(3)The lessor of contract COLA or 2.50% until Purchasing Power Protection Allowance Floor
on purchasing power applies, 2.50% thereafter.
Long-Term Expected Rate of Return
The long-term expected rate of return on pension plan investments was determined
using a building-block method in which expected future real rates of return (expected
returns, net of pension plan investment expense and inflation) are developed for each
major asset class.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(38)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Long-Term Expected Rate of Return (Continued)
In determining the long-term expected rate of return, CalPERS took into account both
short-term and long-term market return expectations as well as the expected pension
fund cash flows. Using historical returns of all the funds’ asset classes, expected
compound (geometric) returns were calculated over the short-term (first 10 years) and
the long-term (11+ years) using a building-block approach. Using the expected nominal
returns for both short-term and long-term, the present value of benefits was calculated
for each fund. The expected rate of return was set by calculating the rounded single
equivalent expected return that arrived at the same present value of benefits for cash
flows as the one calculated using both short-term and long-term returns. The expected
rate of return was then set equal to the single equivalent rate calculated above and
adjusted to account for assumed administrative expenses.
The expected real rates of return by asset class are as follows:
Assumed Real Return Real Return
Asset Years Years
Asset Class (a)Allocation 1 - 10 (b)11+ (c)
Global Equity 50.00 % 4.80% 5.98%
Fixed Income 28.00 1.00% 2.62%
Inflation Assets - 0.77% 1.81%
Private Equity 8.00 6.30% 7.23%
Real Assets 13.00 3.75% 4.93%
Liquidity 1.00 0.00% -0.92%
Total 100.00 %
(a)
(b)An expected inflation of 2.0% used for this period.
(c)An expected inflation of 2.92% used for this period.
In the CalPERS CAFR, Fixed Income is included in Global Debt Securities; Liquidity is
included in Short-term Investments; Inflation Assets are included in both Global Equity
Securities and Global Debt Securities
Discount Rate
The discount rate used to measure the total pension liability was 7.15%. The projection
of cash flows used to determine the discount rate assumed that contributions from plan
members will be made at the current member contribution rates and that contributions
from employers will be made at statutorily required rates, actuarially determined. Based
on those assumptions, the Plan’s fiduciary net position was projected to be available to
make all projected future benefit payments of current plan members. Therefore, the
long-term expected rate of return on plan investments was applied to all periods of
projected benefit payments to determine the total pension liability.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(39)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Subsequent Events
On July 12, 2021, CalPERS reported a preliminary 21.3% net return on investments for
fiscal year 2020-21. Based on the thresholds specified in CalPERS Funding Risk
Mitigation policy, the excess return of 14.3% prescribes a reduction in investment
volatility that corresponds to a reduction in the discount rate used for funding purposes
of 0.20%, from 7.00% to 6.80%. Since CalPERS was in the final stages of the four-year
Asset Liability Management (ALM) cycle, the board elected to defer any changes to the
asset allocation until the ALM process concluded, and the board could make its final
decision on the asset allocation in November 2021.
On November 17, 2021, the board adopted a new strategic asset allocation. The new
asset allocation along with new capital market assumptions, economic assumptions and
administrative expense assumption support a discount rate of 6.90% (net of investment
expense but without a reduction for administrative expense) for financial reporting
purposes. This includes a reduction in the price inflation assumption from 2.50% to
2.30% as recommended in the November 2021 CalPERS Experience Study and Review
of Actuarial Assumptions. This study also recommended modifications to retirement
rates, termination rates, mortality rates and rates of salary increases that were adopted
by the board. These new assumptions will be reflected in the GASB 68 account
valuation repots for the June 30, 2022 measurement date.
Proportionate Share of Net Pension Liability – Allocation of the City’s Pension Plans to
the VPU
The VPU’s net pension liability for the Plans is measured as the proportionate share of
the combined net pension liability of the City’s miscellaneous and safety agent multiple-
employer plans. The VPU’s proportionate share of the combined net pension liability was
based on the VPU’s current year share of contributions to the pension plans relative to
the City’s total current year contributions to the pension plans.
The VPU’s proportionate share of the combined net pension liability for the pension
plans as of the measurement date ended June 30, 2020 and 2021 were as follows:
Increase (Decrease)
Total Plan Net Pension
Pension Fiduciary Liability Proportionate
Liability Net Position (Asset)Share
Balance at June 30, 2020 (MD)87,452,632$ 64,469,634$ 22,982,998$ 16.99%
Balance at June 30, 2021 (MD)120,548,668 103,984,555 16,564,112 18.82%
Net Changes during 2020-21 33,096,036$ 39,514,921$ (6,418,885)$ 1.83%
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(40)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Pension Expense and Deferred Outflows and Inflows of Resources
For the measurement period ended June 30, 2021, the VPU recognized its proportionate
share of the combined pension expense of the Plans which totaled $3,003,538. At
June 30, 2022, the VPU reported its proportionate share of the Plans’ combined deferred
outflows of resources and deferred inflows of resources related to pensions from the
following sources:
Deferred Deferred
Outflows Inflows
of Resources of Resources
Pension Contributions Subsequent
to Measurement Date 2,674,983$ -$
Differences Between Actual and
Expected Experience 2,293,548 -
Net Differences Between Projected and
Actual Earnings on Plan Investments - (9,375,486)
Differences Between Employer Contributions
And Proportionate Share of Contributions - (950,132)
Change in Employer's Proportion 370,266 (97,852)
Total 5,338,797$ (10,423,470)$
$2,674,983 reported as deferred outflows of resources related to contributions
subsequent to the measurement date will be recognized as a reduction of the net
pension liability in the year ending June 30, 2023. Differences between projected and
actual investment earnings are amortized on a five-year straight-line basis and all other
amounts are amortized over the expected average remaining service lives of all
members that are provided with benefits. Other amounts reported as deferred outflows
of resources and deferred inflows of resources related to pensions will be recognized as
pension expense as follows:
Fiscal Year Ended June 30,Total
2023 (1,399,634)$
2024 (1,599,037)
2025 (2,158,527)
2026 (2,602,458)
2027 -
Thereafter -
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(41)
NOTE 8 PENSION PLAN (CONTINUED)
B.Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Sensitivity of the Net Pension Liability to Changes in the Discount Rate
The following presents the VPU’s proportionate share of the Plans’ combined net
pension liability, calculated using a discount rate of 7.15%, as well as what the VPU’s
proportionate share of the Plans’ combined net pension liability would be if it were
calculated using a discount rate that is a 1-percentage point lower or a 1-percentage
point higher than the current rate:
Total
1% Decrease 6.15%
Net Pension Liability 29,168,636$
Current Discount Rate 7.15%
Net Pension Liability 16,564,112$
1% Increase 8.15%
Net Pension Liability 6,222,202$
Pension Plan Fiduciary Net Position
Detailed information about each pension plan’s fiduciary net position is available in the
separately issued CalPERS financial reports.
Payable to the Pension Plan
At June 30, 2022, the VPU had no outstanding amount of contributions to the pension
plans required for the year ended June 30, 2022.
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB)
The other postemployment benefits (OPEB) described in the following paragraphs relate to
the City’s OPEB plan. The VPU’s share of the net pension liability of the City’s OPEB Plan is
reported as a cost-sharing plan in these financial statements since the VPU’s operations are
handled by City employees who are eligible to participate in the City’s OPEB plan.
Benefits Provided
Retiree medical and dental benefits are established through the City’s Fringe Benefits and
Salary Resolution as well as individual memoranda of understanding between the City and
the City’s various employee bargaining groups. Generally, the City will provide
postemployment benefit plan for the employee only to those who retire at age sixty (60) or
later with twenty (20) years of continuous uninterrupted service, up to the age of sixty-five
(65). Alternatively, employees who retire before the age of sixty (60) with twenty (20) years
of continuous uninterrupted service, will be permitted to pay their medical and dental
premium cost and upon reaching the age of sixty (60), the City will pay the premium for the
medical and dental plans until they reach the age of sixty-five (65).
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(42)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
Benefits Provided (Continued)
Resolution 2012-217 granted specific retiree medical benefits to employees who retired
during the 2012-2013 fiscal year in order to provide an incentive for early retirement
whereby the City authorized the payment of medical and dental insurance premiums for
eligible retiring employees and their eligible dependents with at least ten (10) years of
service plus 5% for each additional full year of service above the ten (10) years of service.
Resolution 2013-06 declared that the retiree medical benefits which had not been a vested
right for employees will continue to be a nonvested right for employees who continue to be
employed by the City on or after July 1, 2013, but will be a vested right for those who retire
during the 2012-2013 fiscal year. The City’s plan is considered a substantive OPEB plan
and the City recognizes costs in accordance with GASB Statement No 45. The City may
terminate its unvested OPEB in the future.
Funding Policy and Contributions
The City has established an irrevocable OPEB trust with assets dedicated to paying future
retiree medical benefits. The City intends to contribute 100% or more of the actuarially
determined contribution for the explicit subsidy liability only. The portion of the liability due to
the implicit subsidy is not prefunded but is paid as benefits come due. For the fiscal year
ended June 30, 2022, the VPU’s proportionate share of contributions made was $551,938
($289,520 contributed to the OPEB trust, $170,456 paid for retiree premiums, and the
estimated implied subsidy of $91,962).
Net OPEB Liability
The City’s net OPEB liability is measured as of June 30, 2021, and the total OPEB liability
used to calculate the net OPEB liability was determined by an actuarial valuation as of
June 30, 2021. A summary of the principal assumptions and methods used to determine the
total OPEB liability is shown on the next page.
Actuarial Assumptions
The valuation has been prepared on a closed group basis. Assumptions such as age-related
healthcare claims, healthcare trends, retiree participation rates, and spouse coverage, were
selected based on demonstrated plan experience and the best estimate of expected future
experience.
Explicit subsidy benefit payments by employee group were allocated based on expected
benefit payments. The following actuarial assumptions, applied to all periods included in the
measurement unless otherwise specified:
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(43)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
Actuarial Assumptions (Continued)
Funding Method Entry age normal level percent of pay cost method
Inflation 2.25%
Salary Increases 2.75% annual increases
Long-Term Return on Assets 6.25% net of investment expenses
Discount Rate 6.25%
Healthcare Cost Trend Rates 6.3% for FY2021, gradually decreasing over several
decades to ultimate rate of 3.8% in FY76 and later
years
Mortality 2017 CalPERS Experience Study. Tables include
15 years of static mortality improvement using 90%
of scale MP-2016
Long-Term Expected Rate of Return
The long-term expected rate of return was determined using a building-block method in
which best-estimate ranges of expected future real rates of return (expected returns, net of
OPEB plan investment expense and inflation) are developed for each major asset class.
These ranges are combined to produce the long-term expected rate of return by weighing
the expected future real rates of return by the target asset allocation percentage and by
adding expected inflation. Best estimates of arithmetic real rates of return for each major
asset class included in the OPEB plan’s target asset allocation as of June 30, 2021 are
summarized in the following table:
Long-Term
Target Expected Real
Asset Class Allocation Rate of Return
CERBT Strategy 1:
Equity 59.00 % 4.42%
Fixed Income 25.00 1.00%
TIPS 5.00 0.15%
Commodities 3.00 3.98%
REITs 8.00 1.73%
Total 100.00 %
Discount Rate
The discount rate used to measure the total OPEB liability was 6.25%. The projection of
cash flows used to determine the discount rate assumed that City’s contributions will be
made at rates equal to the actuarially determined contribution rates. Based on those
assumptions, the fiduciary net position was projected to be available to make all projected
OPEB payments for current active and inactive employees and beneficiaries. Therefore, the
long-term expected rate of return on plan investments was applied to all periods of projected
benefit payments to determine the total OPEB liability.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(44)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
Allocation of the Net OPEB Liability
The VPU’s proportionate share of the net OPEB liability as of the measurement dates ended
June 30, 2020 and 2021 was as follows:
Increase (Decrease)
Total Plan Net OPEB
OPEB Fiduciary Liability Proportionate
Liability Net Position (Asset)Share
Balance at June 30, 2020 (MD)4,622,908$ 1,189,602$ 3,433,306$ 16.99%
Balance at June 30, 2021 (MD)5,153,673 2,072,760 3,080,913 18.82%
Net Changes during FY 2020-21 530,765$ 883,158$ (352,393)$ 1.83%
Sensitivity of the Net OPEB Liability to Changes in the Discount Rate
The following presents the VPU’s proportionate share of the net OPEB liability if it were
calculated using a discount rate that is 1% point lower or 1% point higher than the current
rate:
Discount Rate
1% Decrease Current Rate 1% Increase
(5.25%)(6.25%)(7.25%)
Net OPEB Liability 3,657,431$ 3,080,913$ 2,596,467$
Sensitivity of the Net OPEB Liability to Changes in the Healthcare Cost Trend Rates
The following presents the VPU’s proportionate share of the net OPEB liability if it were
calculated using a healthcare cost trend rates that are 1% point lower (5.3% decreasing to
an ultimate rate of 2.8%) or 1% point higher (7.3% decreasing to an ultimate rate of 4.8%)
than the current rate:
Healthcare Trend Rate
1% Decrease Current Rate 1% Increase
Net OPEB Liability 2,837,276$ 3,080,913$ 3,322,985$
OPEB Expense and Deferred Inflows and Outflows of Resources Related to OPEB
For the year ended June 30, 2022, the VPU recognized its proportionate share of the OPEB
expense(revenue) of $(158,635). At June 30, 2022, the VPU reported deferred outflows of
resources and deferred inflows of resources related to OPEB from the following sources:
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(45)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
OPEB Expense and Deferred Inflows and Outflows of Resources Related to OPEB
(Continued)
Deferred Deferred
Outflows Inflows
of Resources of Resources
Contributions Between Measurement Date and
Reporting Date 551,938$ -$
Difference Between Expected and Actual Liability 26,113 (664,032)
Changes of Assumptions 84,092 (705,599)
Net Differences Between Projected and Actual
Earnings on Investments - (208,281)
Total 662,143$ (1,577,912)$
The $551,938 reported as deferred outflows of resources related to contributions
subsequent to the measurement date will be recognized as a reduction of the net OPEB
liability in the year ended June 30, 2023. Differences between projected and actual
investment earnings are amortized on a five-year straight-line basis and all other amounts
are amortized over the expected average remaining service lives of all members that are
provided with benefits. Other amounts reported as deferred outflows of resources and
deferred inflows of resources related to OPEB will be recognized as OPEB expense as
follows:
Deferred
Outflows
(Inflows)
Fiscal Year Ending June 30,of Resources
2023 (439,431)$
2024 (441,059)
2025 (438,463)
2026 (118,239)
2027 (14,058)
Thereafter (16,457)
Payable to the OPEB Plan
At June 30, 2022, the VPU had no outstanding amount of contributions to the OPEB plan
required for the year ended June 30, 2022.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(46)
NOTE 10 VERNON PUBLIC UTILITIES OPERATIONS AND COMMITMENTS
Bicent Agreements
Asset Sale
On December 13, 2007, the City entered into an Amended and Restated Purchase and
Sale Agreement (the Bicent Agreement), with Bicent (California) Power LLC (Bicent),
which is an affiliate of Bicent Holdings and Natural Gas Partners, to sell to Bicent the
Malburg Generating Station (MGS) and the economic burdens and benefits of the City’s
interests in 22 MW from the Hoover Dam Uprating Project for $287,500,000. This
transaction closed on April 10, 2008.
Bicent agreed to sell the capacity and the energy of the MGS to the City on the terms set
forth in a Power Purchase Tolling Agreement, by and between the City and Bicent, dated
as of April 10, 2008 (the PPTA). City treated the PPTA as an asset lease-back
transaction due to a 30-year ground lease between the City and BCM by deferring most
of the gain from the sale of MGS to be amortized over the 15-year life of the PPTA. The
City also deferred the gain from the CFD to be amortized over the 10-year life of the
CFD.
On December 15, 2021, the City made the determination to reacquire MGS to achieve
potential costs savings and other resource management benefits. In addition to the
potential savings, the City expects there to be other benefits associated with the
acquisition of MGS, which includes having control of the facility and the site, providing
the City with flexibility with respect to the MGS operations and MGS’s role in the City’s
resource portfolio. The City issued Electric System Revenue Bonds, 2021 Series A to
finance the acquisition. (See Note 6)
Southern California Public Power Authority
In 1980, the City entered into a joint powers agreement with nine (9) Southern California
cities and an irrigation district to form the Southern California Public Power Authority (the
Authority). The Authority’s purpose is the planning, financing, acquiring, constructing, and
operating of projects that generate or transmit electric energy for sale to its participants. The
joint powers agreement has a term expiring in 2030 or such later date as all bonds and
notes of SCPPA and interest thereon have been paid in full or adequate provisions for
payments have been made. A copy of SCPPA’s audited financial statements can be
reviewed on their website at www.scppa.org or can be obtained by written request at
225 South Lake Avenue, Suite 1250, Pasadena, CA 91101.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(47)
NOTE 10 VERNON PUBLIC UTILITIES OPERATIONS AND COMMITMENTS (CONTINUED)
Southern California Public Power Authority (Continued)
Take or Pay Contract
The Authority’s interests or entitlements in natural gas, generation, and transmission
projects are jointly owned with other utilities. Under these arrangements, a participating
member has an undivided interest in a utility plant and is responsible for its proportionate
share of the costs of construction and operation and is entitled to its proportionate share
of the energy, available transmission capacity, or natural gas produced. Each joint plant
participant, including the Authority, is responsible for financing its share of construction
and operating costs. The City has the following “take or pay” contract with the Authority:
Palo Verde Project
The Authority purchased a 5.91% interest in the Palo Verde Nuclear Generating
Station (the Station), a nuclear-fired generating station near Phoenix, Arizona, from
the Salt River Project Agricultural Improvement and Power District, and a 6.55%
share of the right to use certain portions of the Arizona Nuclear Power Project Valley
Transmission System. The City has a 4.9% entitlement share of the Authority’s
interest in the station.
Between 1983 and 2008, the Authority issued $3.266 billion in debt of Power Project
Revenue Bonds for the Station to finance the bonds and the purchase of the
Authority’s share of the Station and related transmission rights. The bonds are not
obligations of any member of the Authority or public agency other than the Authority.
Under a power sales contract with the Authority, the City is obligated on a “take or
pay” basis for its proportionate share of power generated, as well as to make
payments for its proportionate share of the operating and maintenance expenses of
the Station, debt service on the bonds and any other debt, whether or not the project
or any part thereof or its output is suspended, reduced or terminated. The City took
its proportionate share of the power generated and its proportionate share of costs
during the fiscal year 2022 was $3,320,768. The City expects no significant
increases in costs related to its nuclear resources.
CITY OF VERNON
VERNON PUBLIC UTILITIES
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(48)
NOTE 10 VERNON PUBLIC UTILITIES OPERATIONS AND COMMITMENTS (CONTINUED)
Southern California Public Power Authority (Continued)
Power Purchase Commitments
The Authority has entered into power purchase agreements with project participants.
These agreements are substantially “take-and-pay” contracts where there may be other
obligations not associated with the delivery of energy. The City has entered into power
purchase agreements with the Authority related to the following projects:
Astoria 2 Solar Project
On July 23, 2014, the Authority entered into a power purchase agreement with
Recurrent Energy for solar energy from the Astoria 2 Solar Project. SCPPA is
entitled to 35 MW of photovoltaic generating capacity from commercial operation to
December 31, 2021 and 45 MW of generating capacity from January 1, 2022 until
the expected expiration date of December 31, 2036. The commercial operation date
was December 2016. Power and Water Resources Pooling Authority, Lodi, Corona,
Moreno Valley, and Rancho Cucamonga, are each buying the output of a separate
portion of the facility, which is located in Kern County, California. SCPPA has
purchase options in the 10th, 15th, and 20th Contract Years. The project is
forecasted to start at a capacity factor of 31% with a 0.5% annual degradation. ACES
Power Marketing is the third-party scheduling coordinator for the project. The City
contracted to purchase 57.1429% until December 31, 2021, and 66.6667%
thereafter, of the output. The City’s proportionate share of costs during the current
fiscal year was $2,250,667.
Puente Hills Landfill Gas-to-Energy Project
On June 25, 2014, the Authority entered into a power purchase agreement with
County Sanitation District No. 2 of Los Angeles County for 46 MW of the electric
generation from a landfill gas-to-energy facility, located at Whittier, California. The
project began deliveries to the Authority on January 1, 2017 for a term of 10 years.
The City contracted to purchase 23.2558% of the output. The City’s proportionate
share of costs during the current fiscal year was $1,007,652.
Antelope DSR 1 Solar Project
On July 16, 2015, the Authority, entered into a power purchase agreement with
Antelope DSR 1, LLC for 50 MW solar photovoltaic generating capacity from the
Antelope DSR 1 Solar Facility. The facility is located near Lancaster, California, and
commercial operation occurred on December 16, 2016 for a term of 20 years. The
City contracted to purchase 50.00% of the output. The City’s proportionate share of
costs during the current fiscal year was $1,192,621.
REQUIRED SUPPLEMENTARY INFORMATION
CITY OF VERNON
VERNON PUBLIC UTILITIES
SCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION LIABILITY
CITY’S MISCELLANEOUS AND SAFETY COST SHARING PLAN
LAST TEN FISCAL YEARS *
(49)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017
Measurement Date 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017 6/30/2016
Plan’s Proportion of the
Net Pension Liability 18.82% 16.99% 15.47% 14.86% 15.55% 15.41%
Plan’s Proportionate Share of the
Net Pension Liability 16,563,816$ 22,982,998$ 18,692,374$ 16,866,107$ 17,052,279$ 14,675,830$
Plan’s Covered Payroll 3,902,610 4,203,972 4,418,536 4,577,147 4,210,103 2,026,477
Plan’s Proportionate Share of the
Net Pension Liability as a
Percentage of Covered Payroll 424.43% 546.70% 423.04% 368.49% 405.03% 724.20%
Plan Fiduciary Net Position as a
Percentage of the Total
Pension Liability 85.45% 74.79% 76.15% 77.68% 77.85% 78.91%
Notes to Schedule:
Benefit Changes:
There were no changes in benefits.
Changes in Assumptions:
From fiscal year June 30, 2017 to June 30, 2018:
The discount rate was reduced from 7.65% to 7.15%.
From fiscal year June 30, 2018 to June 30, 2019:
There were no significant changes in assumptions.
From fiscal year June 30, 2019 to June 30, 2020:
There were no significant changes in assumptions.
From fiscal year June 30, 2020 to June 30, 2021:
The inflation rate was increased from 2.5% to 2.625%
The payroll growth rate was reduced from 3.00% to 2.875%.
From fiscal year June 30, 2021 to June 30, 2022:
The inflation rate was decreased from 2.625% to 2.5%
The payroll growth rate was reduced from 2.875% to 2.75%.
The investment rate of return was decreased from 7.15% to 7.00%.
* Fiscal year 2017 was the first year the City allocated a portion of the net pension liability to the VPU; therefore only six years are shown.
CITY OF VERNON
VERNON PUBLIC UTILITIES
SCHEDULE OF PLAN CONTRIBUTIONS
CITY’S MISCELLANEOUS AND SAFETY COST SHARING PLAN
LAST TEN FISCAL YEARS *
(50)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017
Actuarially Determined
Contribution 2,674,983$ 2,145,491$ 1,908,522$ 1,622,690$ 1,475,490$ 1,403,235$
Contributions in Relation to the
Actuarially Determined
Contribution (2,674,983) (2,145,491) (1,908,522) (1,622,690) (1,475,490) (1,403,235)
Contribution:
Deficiency (Excess) -$ -$ -$ -$ -$ -$
Covered Payroll 4,767,901$ 3,902,610$ 4,203,972$ 4,418,536$ 4,577,147$ 4,210,103$
Contributions as a Percentage
of Covered Payroll 56.10% 54.98% 45.40% 36.72% 32.24% 33.33%
Notes to Schedule:
Valuation Date 6/30/2019 6/30/2018 6/30/2017 6/30/2016 6/30/2015 6/30/2014
Methods and Assumptions Used to
Determine Contribution Rates:
Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age Entry Age Entry Age
Amortization Method (1) (1) (1) (1) (1) (1)
Asset Valuation Method Fair Value Fair Value Fair Value Fair Value Fair Value Fair Value
Inflation 2.625% 2.625% 2.625% 2.75% 2.75% 2.75%
Salary Increases (2) (2) (2) (2) (2) (2)
Investment Rate of Return 7.00% (3) 7.25% (3) 7.25% (3) 7.375% (3) 7.50% (3) 7.50% (3)
Mortality (4) (4) (4) (4) (4) (4)
(1) Level percentage of payroll, closed
(2) Depending on age, service, and type of employment
(3) Net of pension plan investment expense, including inflation
(4) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study
adopted by the CalPERS Board.
* Fiscal year 2017 was the first year the City allocated a portion of the net pension liability to the VPU; therefore only six years are shown.
CITY OF VERNON
VERNON PUBLIC UTILITIES
SCHEDULE OF PROPORTIONATE SHARE OF THE NET OPEB LIABILITY
LAST TEN FISCAL YEARS *
(51)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018
Measurement Date 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017
Plan’s Proportion of the
Net OPEB Liability 18.82% 16.99% 15.47% 14.86% 10.71%
Plan’s Proportionate Share of the
Net OPEB Liability 3,080,913$ 3,433,306$ 3,391,408$ 3,432,725$ 3,887,475$
Plan’s Covered-Employee Payroll 5,385,241 4,944,915 5,228,211 3,587,387 3,588,945
Plan’s Proportionate Share of the
Net OPEB Liability as a Percentage
of Covered-Employee Payroll 57.21% 69.43% 64.87% 95.69% 108.32%
Plan Fiduciary Net Position as a
Percentage of the Total OPEB Liability 40.20% 25.70% 16.30% 8.62% 2.83%
Notes to Schedule:
Changes in Assumptions:
* Fiscal year 2018 was the first year of implementation; therefore only five years are shown.
In the June 30, 2018 measurement period, the pre-65 waived retiree re-election was updated to be 10% after age 65.
The discount rate was changed from 2.85% to 3.58% for the measurement period ended June 30, 2017. The discount
rate for the measurement periods ended June 30, 2018 and 2019 was 6.50%. The discount rate for the measurement
period ended June 30, 2020 was reduced to 6.25%.
The mortality, retirement, disability, and termination rates for the measurement periods ended June 30, 2017 and
2018 were based on the CalPERS 1997-2011 Experience Study and CalPERS 1997-2015 Experience Study,
respectively.
The mortality improvement rates for the measurement periods ended June 30, 2017 and 2018 were based on the
Scale MP-2016 and Scale-2018, respectively.
CITY OF VERNON
VERNON PUBLIC UTILITIES
SCHEDULE OF OPEB CONTRIBUTIONS
LAST TEN FISCAL YEARS *
(52)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018
Actuarially Determined
Contribution 289,525$ 261,372$ 298,886$ 400,166$ 288,398$
Contributions in Relation to the
Actuarially Determined
Contribution (551,938) (531,940) (605,820) (444,230) (221,199)
Contribution:
Deficiency (Excess) (262,413)$ (270,568)$ (306,934)$ (44,064)$ 67,199$
Covered Payroll 5,965,311$ 5,385,241$ 4,944,915$ 5,228,211$ 3,587,387$
Contributions as a Percentage
of Covered Payroll 4.85% 4.85% 6.04% 7.65% 8.04%
Notes to Schedule:
Valuation Date 6/30/2019 6/30/2018 6/30/2018 6/30/2016 6/30/2016
Methods and Assumptions Used to
Determine Contribution Rates:
Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age Entry Age
Amortization Method (1) (1) (1) (1) (1)
Amortization Period 28 years 28 years 27 years 27 Years 29 Years
Asset Valuation Method Market Value Market Value Market Value Market Value Market Value
Inflation 2.25% 2.25% 2.50% 2.50% 2.75%
Healthcare Trend Rates (7) (6) (3) (3) (2)
Investment Rate of Return 6.25% 6.25% 6.50% 7.00% 7.00%
Mortality (5) (5) (5) (5) (4)
(1) Level percentage of payroll, closed.
(2) 8.50% trending down to 5.00%.
(3) 6.90% trending down to 4.00%.
(4) CalPERS December 2014 experience study
(5) CalPERS December 2017 experience study
(6) 6.70% trending down to 3.80%.
(7) 6.30% trending down to 3.80%.
* Fiscal year 2018 was the first year of implementation; therefore five years year are shown.
SUPPLEMENTARY INFORMATION
CITY OF VERNON
VERNON PUBLIC UTILITIES
COMBINING STATEMENT OF NET POSITION
JUNE 30, 2022
(53)
Electric Gas Water Fiber Optics Eliminating
Fund Fund Fund Fund Entry Totals
ASSETS
Current Assets:
Cash and Cash Equivalents 130,758,591$ 8,692,417$ 17,015,777$ 493,854$ -$ 156,960,639$
Accounts Receivable, Net of
Allowance 12,396,047 580,100 1,141,938 144,253 - 14,262,338
Accrued Unbilled Revenue 16,411,782 1,240,987 1,373,195 - - 19,025,964
Accrued Interest Receivable 84,749 - 4,448 - - 89,197
Due from Other City Funds 70,399 - - - (70,399) -
Prepaid Items 17,666 - - - - 17,666
Prepaid Natural Gas 636,909 - - - - 636,909
Total Current Assets 160,376,143 10,513,504 19,535,358 638,107 (70,399) 190,992,713
Noncurrent Assets:
Restricted Cash and Cash
Equivalents 39,025,025 - 7,358,059 - - 46,383,084
Advances to Other City Funds 27,079,890 - 202,798 - (27,079,890) 202,798
Prepaid Items 994,736 - - - - 994,736
Deposits 1,201,423 - - - - 1,201,423
Capital Assets:
Nondepreciable 63,421,951 - 7,381,939 - - 70,803,890
Depreciable, Net 362,295,361 15,379,161 8,886,072 1,063,160 - 387,623,754
Total Noncurrent Assets 494,018,386 15,379,161 23,828,868 1,063,160 (27,079,890) 507,209,685
Total Assets 654,394,529 25,892,665 43,364,226 1,701,267 (27,150,289) 698,202,398
DEFERRED OUTFLOWS OF
RESOURCES
Deferred Outflows Related to Pensions 4,016,377 397,282 917,279 7,859 - 5,338,797
Deferred Outflows Related to OPEB
Liability 498,130 49,273 113,765 975 - 662,143
Deferred Amount on Debt Refunding 1,933,345 - - - - 1,933,345
Total Deferred Outflows of
Resources 6,447,852 446,555 1,031,044 8,834 - 7,934,285
CITY OF VERNON
VERNON PUBLIC UTILITIES
COMBINING STATEMENT OF NET POSITION (CONTINUED)
JUNE 30, 2022
(54)
Electric Gas Water Fiber Optics Eliminating
Fund Fund Fund Fund Entry Totals
LIABILITIES
Current Liabilities:
Accounts Payable 15,828,391$ 215,122$ 1,415,262$ 13,734$ -$ 17,472,509$
Accrued Wages and Benefits 333,914 28,032 44,295 363 - 406,604
Due to Other City Funds 2,965,077 71,583 - - (70,399) 2,966,261
Customer Deposits 425,426 13,558 61,184 - - 500,168
Bond Interest Payable 4,969,736 - 242,490 - - 5,212,226
Bonds Payable 50,110,000 - 250,000 - - 50,360,000
Note Payable - - 139,535 - - 139,535
Compensated Absences 369,608 8,377 28,069 81 - 406,135
Total Current Liabilities 75,002,152 336,672 2,180,835 14,178 (70,399) 77,463,438
Noncurrent Liabilities:
Advances from Other City Funds - 23,226,198 - 3,853,692 (27,079,890) -
Bonds Payable 397,826,476 - 14,885,833 - - 412,712,309
Note Payable - - 1,081,395 - - 1,081,395
Compensated Absences 739,215 16,754 56,139 162 - 812,270
Net Other Postemployment Benefit
Liability 2,317,770 229,264 529,343 4,536 - 3,080,913
Net Pension Liability 12,461,180 1,232,605 2,845,943 24,384 - 16,564,112
Total Noncurrent Liabilities 413,344,641 24,704,821 19,398,653 3,882,774 (27,079,890) 434,250,999
Total Liabilities 488,346,793 25,041,493 21,579,488 3,896,952 (27,150,289) 511,714,437
DEFERRED INFLOWS OF
RESOURCES
Deferred Inflows Related to Pensions 7,841,575 775,654 1,790,896 15,345 - 10,423,470
Deferred Inflows Related to OPEB
Liability 1,187,063 117,419 271,107 2,323 - 1,577,912
Total Deferred Inflows of
Resources 9,028,638 893,073 2,062,003 17,668 - 12,001,382
NET POSITION
Net Investment in Capital Assets 145,563,396 15,301,360 6,869,387 1,053,694 - 168,787,837
Restricted for Debt Service 32,836,544 - - - - 32,836,544
Unrestricted (Deficit) (14,932,990) (14,896,706) 13,884,392 (3,258,213) - (19,203,517)
Total Net Position 163,466,950$ 404,654$ 20,753,779$ (2,204,519)$ -$ 182,420,864$
CITY OF VERNON
VERNON PUBLIC UTILITIES
COMBINING STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION
YEAR ENDED JUNE 30, 2022
(55)
Electric Gas Water Fiber Optics
Fund Fund Fund Fund Totals
OPERATING REVENUES
Charges for Services 208,539,519$ 18,705,573$ 10,845,652$ 480,014$ 238,570,758$
Total Operating Revenues 208,539,519 18,705,573 10,845,652 480,014 238,570,758
OPERATING EXPENSES
Cost of Sales 144,582,543 17,765,508 7,743,964 222,558 170,314,573
Depreciation 16,510,921 707,035 500,102 186,152 17,904,210
Total Operating Expenses 161,093,464 18,472,543 8,244,066 408,710 188,218,783
OPERATING INCOME 47,446,055 233,030 2,601,586 71,304 50,351,975
NONOPERATING REVENUES
(EXPENSES)
Intergovernmental 665,887 5,029 194,487 - 865,403
Investment Income 269,257 4,128 11,991 246 285,622
Net Decrease in Fair Value of
Investments (8,231) - - - (8,231)
Interest Expense (13,599,589) - (563,895) - (14,163,484)
Loss on Disposition of Assets (1,900,009) (6,076) (409,841) - (2,315,926)
Total Nonoperating
Revenues (Expenses) (14,572,685) 3,081 (767,258) 246 (15,336,616)
CHANGE IN NET POSITION 32,873,370 236,111 1,834,328 71,550 35,015,359
Net Position (Deficit) - Beginning
of Year 130,593,580 168,543 18,919,451 (2,276,069) 147,405,505
NET POSITION (DEFICIT) -
END OF YEAR 163,466,950$ 404,654$ 20,753,779$ (2,204,519)$ 182,420,864$
CITY OF VERNON
VERNON PUBLIC UTILITIES
COMBINING STATEMENT OF CASH FLOWS
YEAR ENDED JUNE 30, 2022
(56)
Electric Gas Water Fiber Optics
Fund Fund Fund Fund Totals
CASH FLOWS FROM OPERATING
ACTIVITIES
Cash Received from Customers 199,972,221$ 18,586,393$ 10,427,677$ 367,504$ 229,353,795$
Cash Paid to Suppliers for Goods and Services (133,793,435) (16,770,406) (6,851,398) (242,584) (157,657,823)
Cash Paid to Employees for Services (3,090,696) (724,165) (1,818,089) (168,276) (5,801,226)
Cash Paid to City for Services (5,214,961) - - - (5,214,961)
Net Cash Provided (Used) by Operating
Activities 57,873,129 1,091,822 1,758,190 (43,356) 60,679,785
CASH FLOWS FROM CAPITAL AND
RELATED FINANCING ACTIVITIES
Repayment of Bonds (34,975,000) - (240,000) - (35,215,000)
Issuance of Bonds 235,885,000 - - - 235,885,000
Bond Premiums 38,266,557 - - - 38,266,557
Payment to Refunding Bond Escrow Agent (62,999,903) - - - (62,999,903)
Bond Interest Paid (16,875,267) - (587,975) - (17,463,242)
Payment of Note Payable - - (139,535) - (139,535)
Net Acquisition of Capital Assets (216,887,677) (261,506) (4,033,299) (211,814) (221,394,296)
Net Cash Used by Capital
and Related Financing Activities (57,586,290) (261,506) (5,000,809) (211,814) (63,060,419)
CASH FLOWS FROM NONCAPITAL
FINANCING ACTIVITIES
Grant Revenue Received 665,887 5,029 194,487 - 865,403
Payment from (Provided to) Other City Funds 114,065 (59) 1,915,195 (114,006) 1,915,195
Net Cash Provided (Used) by
Noncapital Financing Activities 779,952 4,970 2,109,682 (114,006) 2,780,598
CASH FLOWS FROM INVESTING
ACTIVITIES
Investment Income 178,598 4,128 7,583 246 190,555
Net Cash Provided by Investing Activities 178,598 4,128 7,583 246 190,555
CHANGE IN CASH AND CASH
EQUIVALENTS 1,245,389 839,414 (1,125,354) (368,930) 590,519
Cash and Cash Equivalents - Beginning of Year 168,538,227 7,853,003 25,499,190 862,784 202,753,204
CASH AND CASH EQUIVALENTS -
END OF YEAR 169,783,616$ 8,692,417$ 24,373,836$ 493,854$ 203,343,723$
COMPOSITION OF CASH AND CASH
EQUIVALENTS
Cash and Cash Equivalents 130,758,591$ 8,692,417$ 17,015,777$ 493,854$ 156,960,639$
Restricted Cash and Investments 39,025,025 - 7,358,059 - 46,383,084
Total 169,783,616$ 8,692,417$ 24,373,836$ 493,854$ 203,343,723$
CITY OF VERNON
VERNON PUBLIC UTILITIES
COMBINING STATEMENT OF CASH FLOWS (CONTINUED)
YEAR ENDED JUNE 30, 2022
(57)
Electric Gas Water Fiber Optics
Fund Fund Fund Fund Totals
RECONCILIATION OF OPERATING
INCOME TO NET CASH
PROVIDED (USED) BY OPERATING
ACTIVITIES
Operating Income 47,446,055$ 233,030$ 2,601,586$ 71,304$ 50,351,975$
Adjustments to Reconcile Operating Income
to Net Cash Provided (Used) by
Operating Activities:
Depreciation 16,510,921 707,035 500,102 186,152 17,904,210
Deferred gain from sale of generation assets (6,555,916) - --(6,555,916)
Change in Operating Assets and Liabilities:
Accounts Receivable (6,672,318) (216,191) (164,414) (112,510) (7,165,433)
Accrued Unbilled Revenue (1,889,809) 97,011 (254,361) -(2,047,159)
Due from Other Funds 523,087 - --523,087
Prepaid Expenses and Deposits (104,017) - --(104,017)
Prepaid Natural Gas (636,909) - --(636,909)
Deferred Outflows of Resources (564,694) 5,199 102,727 37,961 (418,807)
Accounts Payable 3,257,996 164,516 (1,292)(27,752) 3,393,468
Accrued Wages and Benefits (115,466) (22,058)(67,916)(4,087)(209,527)
Due to Other City Funds 2,965,077 71,583 (593,486) -2,443,174
Customer Deposits (5,171)-800 -(4,371)
Compensated Absences 56,427 1,347 (18,983)(2,289)36,502
Other Postemployment Benefit Liability (111,573) (48,588)(167,986)(24,246) (352,393)
Net Pension Liability (3,801,160) (627,374) (1,822,068) (168,284) (6,418,886)
Deferred Inflows of Resources 7,570,599 726,312 1,643,481 395 9,940,787
Net Cash Provided (Used) by
Operating Activities 57,873,129$ 1,091,822$ 1,758,190$ (43,356)$ 60,679,785$
CITY OF VERNON
ELECTRIC FUND
(AN ENTERPRISE FUND OF THE
CITY OF VERNON)
FINANCIAL STATEMENTS AND
SUPPLEMENTARY INFORMATION
YEAR ENDED JUNE 30, 2022
CITY OF VERNON
ELECTRIC FUND
TABLE OF CONTENTS
YEAR ENDED JUNE 30, 2022
INTRODUCTORY SECTION
A MESSAGE FROM THE GENERAL MANAGER OF VERNON PUBLIC
UTILITIES i
FINANCIAL SECTION
INDEPENDENT AUDITORS’ REPORT 1
MANAGEMENTS’ DISCUSSION AND ANALYSIS (Required Supplementary
Information – Unaudited) 4
BASIC FINANCIAL STATEMENTS
STATEMENT OF NET POSITION 10
STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN NET
POSITION 12
STATEMENT OF CASH FLOWS 13
NOTES TO BASIC FINANCIAL STATEMENTS 15
REQUIRED SUPPLEMENTARY INFORMATION
SCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION
LIABILITY – CITY’S MISCELLANEOUS AND SAFETY COST SHARING
PLAN 48
SCHEDULE OF PLAN CONTRIBUTIONS – CITY’S MISCELLANEOUS AND
SAFETY COST SHARING PLAN 49
SCHEDULE OF PROPORTIONATE SHARE OF THE NET OPEB LIABILITY 50
SCHEDULE OF OPEB CONTRIBUTIONS 51
INTRODUCTORY SECTION
Vernon Public Utilities
4305 Santa Fe Avenue, Vernon, CA, 90058
323.583.8811 | CityofVernon.org
Message from the General Manager
As an essential resource to all customers, our job is to provide dependable,
high-quality electric, water, natural gas, and fiber optic services at cost -
effective rates with the highest standards for reliability. We ensure that
electricity will stay on when needed, customers have safe, clean drinking
water, there is a reliable supply of natural gas to meet demand, and our fiber
services offer competitive rates and the latest technology. Our mission focuses
on reliably providing the lowest electric rates in California by 2030.
As a municipally owned utility, every customer is a stakeholder in Vernon Public
Utilities (VPU). VPU enjoys the continued support of the City Council, which has
approved key strategic initiatives for sustained success. These initiatives
include Renewable Energy Projects, such as the Daggett Solar Project
(operational in September 2023) and the Sapphire Solar and Storage Facility Project (operational in
December 2025). With Council support, along with City Administration, VPU remains focused on providing
our customers with reliable services and competitive rates.
Despite the recent supply chain issues and higher costs for energy, materials, and supplies, which are
critical to our operations, VPU is committed to maintaining a strong financial and operational position for
the future. Our strategy focuses on the following initiatives for financial and operational flexibility :
1.Electric load growth with a diversified customer base which includes green commerce.
2.A diversified Energy Resource portfolio, which includes meeting California’s Renewable Portfolio
Standard Targets as outlined in SB100. Specifically, (i) 2027 - 52%, (ii) 2030 - 60%, and (iii) 2045 - 100%
Carbon Neutral. VPU is in the process of updating its Integrated Resource Plan, which focuses on
providing direction for reliability, affordability, and meeting renewable energy requirements.
3.Optimizing the operating profile for the Malburg Generating Station (MGS) for operational savings
and continued coordination with the CAISO to prevent statewide rolling blackouts and requests to
run MGS when energy is needed most across the electric grid.
4.Continued strategic capital investment in electric, water, natural gas, and fiber optic infrastructure to
support high-quality and reliable services. VPU continues to be one of the most reliable electric
systems compared to other utilities. VPU is a three-time recipient of the RP3 Diamond Level Award, the
highest reliability award from APPA, which reflects our continued investment in utility infrastructure and
commitment to safety and workforce development.
5.A focus on the utility’s financial strength, including improving key financial metrics used by the rating
agencies such as Moody’s and S&P Global Ratings, including the implementation of a Utility Financial
Reserves Policy, and keeping rates competitive to ensure businesses can grow in Vernon.
As we enter 2023, I am optimistic about the future. VPU is focused on providing reliable and competitive
electric, water, natural gas, and fiber optic services. In that pursuit, we will excel today and in the future.
Sincerely,
Todd Dusenberry
General Manager
(i)
FINANCIAL SECTION
CLA (CliftonLarsonAllen LLP) is an independent network member of CLA Global. See CLAglobal.com/disclaimer.
CliftonLarsonAllen LLP
CLAconnect.com
(1)
INDEPENDENT AUDITORS’ REPORT
Honorable Mayor and the Members of the City Council
City of Vernon, California
Report on the Audit of the Financial Statements
Opinion
We have audited the accompanying financial statements of the Electric Fund of the City of Vernon
(Electric Fund), an enterprise fund of the City of Vernon, California (City), which comprise the statement
of net position as of June 30, 2022, and the related statements of revenues, expenses, and changes in
net position, and cash flows for the year then ended, and the related notes to the financial statements,
which collectively comprise the Electric Fund’s basic financial statements as listed in the table of
contents.
In our opinion, the financial statements referred to above present fairly, in all material respects, the
financial position of the Electric Fund as of June 30, 2022, and the changes in its financial position and
its cash flows for the year then ended in accordance with accounting principles generally accepted in
the United States of America.
Basis for Opinion
We conducted our audit in accordance with auditing standards generally accepted in the United States
of America (GAAS) and the standards applicable to financial audits contained in Government Auditing
Standards, issued by the Comptroller General of the United States. Our responsibilities under those
standards are further described in the Auditors’ Responsibilities for the Audit of the Financial
Statements section of our report. We are required to be independent of the City’s Electric Fund and to
meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to
our audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide
a basis for our audit opinion.
Emphasis of Matter
As discussed in Note 1, the financial statements present only the Electric Enterprise Fund and do not
purport to, and do not, present fairly the financial position of the City of Vernon as of June 30, 2022,
and the changes in its financial position and its cash flows for the year then ended in accordance with
accounting principles generally accepted in the United States of America. Our opinion is not modified
with respect to this matter.
Honorable Mayor and the Members of the City Council
City of Vernon, California
(2)
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in
accordance with accounting principles generally accepted in the United States of America; this includes
the design, implementation, and maintenance of internal control relevant to the preparation and fair
presentation of financial statements that are free from material misstatement, whether due to fraud or
error.
Auditors’ Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole
are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that
includes our opinions. Reasonable assurance is a high level of assurance but is not absolute assurance
and therefore is not a guarantee that an audit conducted in accordance with GAAS and Government
Auditing Standards will always detect a material misstatement when it exists. The risk of not detecting a
material misstatement resulting from fraud is higher than for one resulting from error, as fraud may
involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
Misstatements are considered material if there is a substantial likelihood that, individually or in the
aggregate, they would influence the judgment made by a reasonable user based on the financial
statements.
In performing an audit in accordance with GAAS and Government Auditing Standards, we:
Exercise professional judgment and maintain professional skepticism throughout the audit.
Identify and assess the risks of material misstatement of the financial statements, whether due
to fraud or error, and design and perform audit procedures responsive to those risks. Such
procedures include examining, on a test basis, evidence regarding the amounts and disclosures
in the financial statements.
Obtain an understanding of internal control relevant to the audit in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Electric Fund’s internal control. Accordingly, no such opinion
is expressed.
Evaluate the appropriateness of accounting policies used and the reasonableness of significant
accounting estimates made by management, as well as evaluate the overall presentation of the
financial statements.
We are required to communicate with those charged with governance regarding, among other matters,
the planned scope and timing of the audit, significant audit findings, and certain internal control related
matters that we identified during the audit.
Honorable Mayor and the Members of the City Council
City of Vernon, California
(3)
Required Supplementary Information
Accounting principles generally accepted in the United States of America require that the
management’s discussion and analysis, schedule of proportionate share of the City’s net pension
liability, schedule of plan contributions, schedule of proportionate share of the City’s net OPEB liability,
and schedule of OPEB contributions, identified as Required Supplementary Information (RSI) in the
accompanying table of contents, be presented to supplement the basic financial statements. Such
information, although not a part of the basic financial statements, is required by the Governmental
Accounting Standards Board who considers it to be an essential part of financial reporting for placing
the basic financial statements in an appropriate operational, economic, or historical context. We have
applied certain limited procedures to the required supplementary information in accordance with
auditing standards generally accepted in the United States of America, which consisted of inquiries of
management about the methods of preparing the information and comparing the information for
consistency with management’s responses to our inquiries, the basic financial statements, and other
knowledge we obtained during our audit of the basic financial statements. We do not express an
opinion or provide any assurance on the information because the limited procedures do not provide us
with sufficient evidence to express an opinion or provide any assurance.
Other Information
Management is responsible for the other information included in the annual report. The other
information comprises the introductory section but does not include the basic financial statements and
our auditors’ report thereon. Our opinion on the basic financial statements does not cover the other
information, and we do not express an opinion or any form of assurance thereon.
In connection with our audit of the basic financial statements, our responsibility is to read the other
information and consider whether a material inconsistency exists between the other information and the
basic financial statements, or the other information otherwise appears to be materially misstated. If,
based on the work performed, we conclude that an uncorrected material misstatement of the other
information exists, we are required to describe it in our report.
Other Reporting Required by Government Auditing Standards
In accordance with Government Auditing Standards, we have also issued our report dated August 8,
2023, on our consideration of the Electric Fund’s internal control over the financial reporting and on our
tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and
other matters. The purpose of that report is solely to describe the scope of our testing of internal control
over financial reporting and compliance and the results of that testing, and not to provide an opinion on
the effectiveness of the Electric Fund’s internal control over financial reporting or on compliance. That
report is an integral part of an audit performed in accordance with Government Auditing Standards in
considering the Electric Fund’s internal control over financial reporting and compliance.
CliftonLarsonAllen LLP
Irvine, California
August 8, 2023
CITY OF VERNON
ELECTRIC FUND
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(4)
The management of the Electric Fund of the City of Vernon (“the City”), offers the following overview
and analysis of the basic financial statements of the Electric Fund for the fiscal year ended June 30,
2022. Management encourages readers to utilize information in the Management’s Discussion and
Analysis (MD&A) in conjunction with the accompanying basic financial statements.
OVERVIEW OF BASIC FINANCIAL STATEMENTS
The MD&A is intended to serve as an introduction to the Electric Fund’s basic financial statements.
Included as part of the financial statements are three separate statements.
The statement of fund net position presents information on the Electric Fund’s total assets and
deferred outflows of resources and total liabilities and deferred inflows of resources, with the difference
between the two reported as net position.
The statement of revenues, expenses, and changes in fund net position presents information showing
how the Electric Fund's net position changed during the most recent fiscal year. Financial results are
recorded using the accrual basis of accounting. Under this method, all changes in net position are
reported as soon as the underlying events occur, regardless of the timing of cash flows. Thus,
revenues and expenses reported in this statement for some items may affect cash flows in a future
fiscal period (examples include billed but uncollected revenues and employee earned but unused
vacation leave).
The statement of cash flows reports cash receipts, cash payments, and net changes in cash and cash
equivalents from operations, noncapital financing, capital and related financing, and investing
activities.
The notes to the financial statements provide additional information that is essential.
CITY OF VERNON
ELECTRIC FUND
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(5)
FINANCIAL HIGHLIGHTS
Fund Net Position
The table below summarizes the Electric Fund’s net position as of the current fiscal year ended
June 30, 2022, and prior fiscal year ended June 30, 2021. The details of the current year’s summary
can be found on page 10-11 of this report.
City of Vernon
Electric Fund
Fund Net Position
June 30, 2022 and 2021
The category of the Electric Fund’s net position with the largest balance totaling $145.6 million
represents resources that are invested in capital assets, net of the related debt.
The second category restricted for debt services totaling $32.8 million represents resources that are
subject to external restrictions on how they can be used, in this case bond debt.
The remaining category of net position, totaling ($14.9) million represents a deficit in the unrestricted net
position that is expected to be recovered from the Electric Fund’s estimated load growth, future
revenues, including rate adjustments, and control of operating expenses.
CITY OF VERNON
ELECTRIC FUND
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(6)
Fund Net Position (Continued):
Current assets increased by $16 million from the prior year while restricted and other assets
decreased by $6 million from the prior year due to the drawdowns funding the electric capital
improvement projects.
Capital assets increased by $198.5 million from the prior year mainly due to the continued
capital investment in the Electric Fund infrastructure.
Current liabilities increased by $29.8 million from the prior year while long-term liabilities
increased by $147 million from the prior year mainly due to higher debt service requirements.
The total net position of the Electric Fund increased by $32.9 million from the prior year
primarily due to a $21.3 million increase in net investment in capital assets, an increase of
$8.9 million in debt service restrictions, and an increase in the unrestricted (deficit) of $2.7
million.
CITY OF VERNON
ELECTRIC FUND
MANAGEMENT’S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(7)
Changes in Fund Net Position
The table below summarizes the Electric Fund’s changes in net position over the current and prior
fiscal years. The details of the current year’s changes in net position can be found on page 12 of this
report.
City of Vernon
Electric Fund
Changes in Fund Net Position
June 30, 2022 and 2021
The Electric Fund’s operating income of $47.4 million, less non-operating revenue (expenses) of $14.6
million resulted in an increase in net position by $32.8 million during the current year. The Electric
Fund’s $30.7 million increase in its change in net position is primarily due to higher billed amount to
customers of $19.5 million or 10%, higher consumption of 18.0 or 1%, and lower cost of sale
(operating expenses) of $11.2 million or 7%.
CITY OF VERNON
ELECTRIC FUND
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(8)
CAPITAL ASSET AND DEBT ADMINISTRATION
Capital assets
The Electric Fund’s investment in capital assets as of June 30, 2022 amounted to $425.7 million (net of
accumulated depreciation). This investment in capital assets includes land, intangible assets,
construction in progress, building, utility system improvements, and machinery and equipment. The total
increase in the Electric Fund's investment in capital assets for the current fiscal year was $216.9 million,
offset by the depreciation of $16.5 million representing total capital assets, net of $200.4 million.
Additional information on the Electric Fund's capital assets can be found in Note 5 of this report.
Outstanding debt
As of June 30, 2022, the following debt remains outstanding:
$ 37,895,000 City of Vernon Electric System Revenue Bonds, 2008 Taxable Series A
$ 11,505,000 City of Vernon Electric System Revenue Bonds, 2012 Taxable Series B
$111,720,000 City of Vernon Electric System Revenue Bonds, 2015 Taxable Series A
$ 19,305,000 City of Vernon Electric System Revenue Bonds, 2020 Series A
$173,815,000 City of Vernon Electric System Revenue Bonds, 2021 Taxable Series A
$ 52,070,000 City of Vernon Electric System Revenue Bonds, 2022 Taxable Series A
The City of Vernon Electric System Revenue Bonds, 2008 Taxable Series A were issued to provide
funds to (i) finance the cost of certain capital improvements to the City’s Electric System, (ii) fund a
deposit to the Debt Service Reserve Fund, and (iii) to pay costs of issuance of the 2008 Bonds.
The City of Vernon Electric System Revenue Bonds, 2012 Taxable Series B were issued to provide
funds to (i) refund the $28,680,000 aggregate principal amount of 2009 Bonds maturing on August 1,
2012, (ii) to pay a portion of the Costs of the 2012 Project, and (iii) to pay costs of issuance of the 2012
Taxable Series B Bonds.
The City of Vernon Electric System Revenue Bonds, 2015 Taxable Series A were issued to provide
funds to (i) refund a portion of the Outstanding Electric System Revenue Bonds, 2009 Series A; (ii)
finance the costs of certain capital improvements to the City’s Electric System by reimbursing the
Electric System for the prior payment of such costs from the Light and Power Fund; (iii) fund a deposit to
the Debt Service Reserve Fund; and (iv) pay costs of issuance of the 2015 Bonds.
The City of Vernon Electric System Revenue Bonds, 2020 Series A were issued to provide funds to (i)
finance the acquisition and construction of certain capital improvements to the Electric System of the City,
(ii) to refund all of the City’s outstanding Electric System Revenue Bonds, 2009 Series A, and (iii) to pay
costs of issuance of the 2020 Bonds.
The City of Vernon Electric System Revenue Bonds, 2021 Series A were issued to provide funds: (i) to pay
the costs of the acquisition by the City of Vernon of a 134-megawatt natural gas-fired generating facility
located within the city limits on land owned by the City, together with certain related electrical
interconnection facilities and other assets, property, and contractual rights, (ii) to fund a deposit to the Debt
Service Reserve Fund in satisfaction of the Debt Service Reserve Requirement, and (iii) to pay costs of
issuance of the 2021 Bonds.
CITY OF VERNON
ELECTRIC FUND
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(9)
The City of Vernon Electric System Revenue Bonds, 2022 Series A were issued to (i) refund and defease
all of the City’s outstanding Electric System Revenue Bonds, 2012 Series A and a portion of the City’s
outstanding Electric System Revenue Bonds, 2012 Taxable Series B and (ii) to pay costs of issuance of
the 2022 Bonds.
As of June 30, 2022, the ratings on all Electric System Revenue Bonds of the City were BBB+/Stable rating
by S&P and Baa1/Stable rating by Moody’s.
Additional information on the Electric Fund's long-term debt can be found in Note 6 of this report.
ECONOMIC FACTORS AND NEW YEAR’S BUDGET AND RATES
These factors were considered in preparing the Electric Fund’s FY 2022-23 operating and capital budgets:
VPU is committed to providing dependable, high-quality electric, water, natural gas, and fiber
services at the lowest competitive rates and the highest standards for reliability.
VPU continues to respond to inflation and supply chain issues, including energy, natural gas,
materials and supplies, and construction costs to maintain generation, transmission, and
distribution infrastructure to continue to provide exceptionally reliable service.
Continue to implement VPU’s capital plan, manage operating and maintenance expenses, update
the 2018 Integrated Resource Plan, and complete an Electric Cost of Service Analysis and Rate
Design study.
REQUESTS FOR INFORMATION
This report is designed to provide an overview of the Electric Fund's FY 2021-22 results. Questions
concerning the fund’s financial or operating results can be addressed to Scott Williams, Director of Finance,
swilliams@cityofvernon.org, City of Vernon, 4305 Santa Fe Avenue, Vernon, California, 90058.
CITY OF VERNON
ELECTRIC FUND
STATEMENT OF NET POSITION
JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(10)
ASSETS
Current Assets:
Cash and Cash Equivalents 130,758,591$
Accounts Receivable, Net of Allowance of $971,686 12,396,047
Accrued Unbilled Revenue 16,411,782
Accrued Interest Receivable 84,749
Due from Other City Funds 70,399
Prepaid Items 17,666
Inventories 636,909
Total Current Assets 160,376,143
Noncurrent Assets:
Restricted Cash and Cash Equivalents 39,025,025
Advances to Other City Funds 27,079,890
Prepaid Items 994,736
Deposits 1,201,423
Capital Assets:
Nondepreciable 63,421,951
Depreciable, Net 362,295,361
Total Noncurrent Assets 494,018,386
Total Assets 654,394,529
DEFERRED OUTFLOWS OF RESOURCES
Deferred Outflows Related to Pensions 4,016,377
Deferred Outflows Related to OPEB Liability 498,130
Deferred Amount on Refunding 1,933,345
Total Deferred Outflows of Resources 6,447,852
CITY OF VERNON
ELECTRIC FUND
STATEMENT OF NET POSITION (CONTINUED)
JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(11)
LIABILITIES
Current Liabilities:
Accounts Payable 15,828,391$
Accrued Wages and Benefits 333,914
Due to Other City Funds 2,965,077
Customer Deposits 425,426
Bond Interest Payable 4,969,736
Bonds Payable, Net 50,110,000
Compensated Absences 369,608
Total Current Liabilities 75,002,152
Noncurrent Liabilities:
Bonds Payable, Net 397,826,476
Compensated Absences 739,215
Other Postemployment Benefit Liability 2,317,770
Net Pension Liability 12,461,180
Total Noncurrent Liabilities 413,344,641
Total Liabilities 488,346,793
DEFERRED INFLOWS OF RESOURCES
Deferred Inflows Related to Pensions 7,841,575
Deferred Inflows Related to OPEB Liability 1,187,063
Total Deferred Inflows of Resources 9,028,638
NET POSITION
Net Investment in Capital Assets 145,563,396
Restricted for Debt Service 32,836,544
Unrestricted (Deficit)(14,932,990)
Total Net Position 163,466,950$
CITY OF VERNON
ELECTRIC FUND
STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(12)
OPERATING REVENUES
Charges for Services 208,539,519$
Total Operating Revenue 208,539,519
OPERATING EXPENSES
Cost of Sales 144,582,543
Depreciation 16,510,921
Total Operating Expenses 161,093,464
OPERATING INCOME 47,446,055
NONOPERATING REVENUES (EXPENSES)
Intergovernmental 665,887
Investment Income 269,257
Net Decrease in Fair Value of Investments (8,231)
Interest Expense (13,599,589)
Loss on Disposition of Assets (1,900,009)
Total Nonoperating Revenues (Expenses)(14,572,685)
CHANGE IN NET POSITION 32,873,370
Net Position - Beginning of Year 130,593,580
NET POSITION - END OF YEAR 163,466,950$
CITY OF VERNON
ELECTRIC FUND
STATEMENT OF CASH FLOWS
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(13)
CASH FLOWS FROM OPERATING ACTIVITIES
Cash Received from Customers 199,972,221$
Cash Paid to Suppliers for Goods and Services (133,793,435)
Cash Paid to Employees for Services (3,090,696)
Cash Paid to City for Services (5,214,961)
Net Cash Provided by Operating Activities 57,873,129
CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES
Repayment of Bonds (34,975,000)
Issuance of Bonds 235,885,000
Bond Premiums 38,266,557
Payment to Refunding Bond Escrow Agent (62,999,903)
Bond Interest Paid (16,875,267)
Net Acquisition of Capital Assets (216,887,677)
Net Cash Used by Capital and Related Financing Activities (57,586,290)
CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES
Grant Revenue Received 665,887
Payments from Other City Funds 114,065
Net Cash Provided by Noncapital Financing Activities 779,952
CASH FLOWS FROM INVESTING ACTIVITIES
Investment Income 178,598
Net Cash Provided by Investing Activities 178,598
CHANGE IN CASH AND CASH EQUIVALENTS 1,245,389
Cash and Cash Equivalents - Beginning of Year 168,538,227
CASH AND CASH EQUIVALENTS - END OF YEAR 169,783,616$
COMPOSITION OF CASH AND CASH EQUIVALENTS
Cash and Cash Equivalents 130,758,591$
Restricted Cash and Investments 39,025,025
Total 169,783,616$
CITY OF VERNON
ELECTRIC FUND
STATEMENT OF CASH FLOWS (CONTINUED)
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(14)
RECONCILIATION OF OPERATING INCOME TO NET CASH
PROVIDED BY OPERATING ACTIVITIES
Operating Income 47,446,055$
Adjustments to Reconcile Operating Income
to Net Cash Provided by Operating Activities:
Depreciation 16,510,921
Deferred Gain from Sale of Generation Assets (6,555,916)
Change in Operating Assets and Liabilities:
Accounts Receivable (6,672,318)
Accrued Unbilled Revenue (1,889,809)
Due from Other City Funds 523,087
Prepaid Expenses and Deposits (104,017)
Prepaid Natural Gas (636,909)
Deferred Outflows of Resources (564,694)
Accounts Payable 3,257,996
Accrued Wages and Benefits (115,466)
Due to Other City Funds 2,965,077
Customer Deposits (5,171)
Compensated Absences 56,427
Other Postemployment Benefit Liability (111,573)
Net Pension Liability (3,801,160)
Deferred Inflows of Resources 7,570,599
Net Cash Provided by Operating Activities 57,873,129$
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(15)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying financial statements present only the Electric Enterprise Fund (the
Electric Fund) of the City of Vernon, California (the City), and do not present fairly the
financial position and results of the operations of the City. The Electric Fund accounts for the
independent operations and the maintenance of the City’s electric utility. The Electric Fund
is administered as an independent fiscal and accounting entity with a self-balancing set of
accounts recording resources, related liabilities, obligations, reserves, and equities,
segregated for the purpose of carrying out specific activities or attaining certain objectives in
accordance with special regulations, restrictions, or limitations.
For additional information regarding the City of Vernon, refer to the City’s annual financial
report.
The financial statements of the Electric Fund have been prepared in conformity with the U.S.
generally accepted accounting principles (U.S. GAAP). The Governmental Accounting
Standards Board (GASB) is the accepted standard-setting body for establishing
governmental accounting and financial reporting principles. The Electric Fund’s significant
accounting policies are described below.
A. Basis of Presentation
The Electric Fund’s financial statements are reported using the economic resources
measurement focus and the accrual basis of accounting. Revenues are recorded when
earned and expenses are recorded at the time liabilities are incurred, regardless of when
the related cash flows take place.
The Electric Fund distinguishes operating revenues and expenses from nonoperating
items. Operating revenues, such as charges for services, result from exchange
transactions associated with the sale of electricity and gas. Exchange transactions are
those in which each party receives and gives up essentially equal values. Nonoperating
revenues, such as subsidies and investment earnings, result from nonexchange
transactions or ancillary activities. Operating expenses include the cost of sales and
services, administrative expenses and depreciation on capital assets. All expenses not
meeting this definition are reported as nonoperating expenses.
B. Pooled Cash
Part of the Electric Fund’s operating cash balance is pooled with various other City funds
for deposit purposes. The share of each fund in the pooled cash account is recorded in
each of the fund’s books of accounts, and interest income is apportioned to the
participating funds based on the relationship of their average monthly balances to the
total of the pooled cash.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(16)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
C. Cash and Cash Equivalents
For purposes of the statement of cash flows, the Electric Fund considers all highly liquid
investments (including restricted cash and investments) with an original maturity of three
months or less when purchased to be cash equivalents. Investment transactions are
recorded on the settlement date. Investments in nonparticipating interest-earning
investment contracts are reported at cost and all other investments are reported at fair
value. Fair value is defined as the amount that the Electric Fund could reasonably
expect to receive for an investment in a current sale between a willing buyer and a seller
and is generally measured by quoted market prices.
D. Receivables/Payables
Short-term City interfund receivables and payables are classified as “due from other City
funds” and “due to other City funds”, respectively, on the statement of net position. Long-
term City interfund receivables and payables are classified as “advances to/from other
City funds,” respectively, on the statement of net position.
Trade receivables are shown net of an allowance for uncollectible accounts. Allowances
for uncollectible receivables were $971,686 as of June 30, 2022. The Electric Fund’s
customers are billed monthly. The estimated value of services provided, but unbilled at
year-end has been included in the accompanying statement of net position.
E. Prepaid Item
The City made a prepayment to Southern California Public Power Authority (SCPPA) for
the VPU’s share of SCPPA’s payoff of the Hoover Center and Air Slots debt. This
prepaid amount is amortized over the life of the debt based on the annual debt service
obligations. See Note 10 for further information regarding SCPPA.
F. Inventories
All inventories are valued at cost, or estimated historical costs when historical
information is unavailable, using the first-in/first-out (FIFO) method. Inventory costs in
the proprietary funds are recorded as an expense or capitalized into capital assets when
used.
G. Deposits
The City has deposits in SCPPA’s Project Stabilization Fund for use within SCPPA’s
project purposes at the City’s discretion. At June 30, 2022, the amount of deposits
totaled $1,201,423.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(17)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
H. Capital Assets
Capital assets (including infrastructure) are recorded at historical cost or at estimated
historical cost if the actual historical cost is not available. Contributed capital assets are
recorded at their estimated acquisition value at the date contributed. Capital assets
include land, intangible assets, construction in progress, and plant assets including
building, improvements, and machinery and equipment. The capitalization threshold for
all capital assets is $5,000. Capital assets used in operations are depreciated using the
straight-line method over their estimated useful lives. Intangible assets with an indefinite
useful life are not amortized but are evaluated annually for any impairment.
The estimated useful lives are as follows:
Utility Infrastructure and Buildings 25 to 50 Years
Improvements 10 to 20 Years
Machinery and Equipment 3 to 35 Years
Maintenance and repairs are charged to operations when incurred. Betterments and
major improvements, which significantly increase values, change capacities or extend
useful lives, are capitalized. Upon sale or retirement of capital assets, the cost and
related accumulated depreciation are removed from the respective accounts and any
resulting gain or loss is included in the statement of revenues, expenses, and changes in
net position.
I. Compensated Absences
Accumulated vacation is accrued when incurred. Upon termination of employment, the
City will pay the employee all accumulated vacation leave at 100% of the employee’s
base hourly rate.
J. Deferred Outflows and Inflows of Resources
The Electric Fund recognizes deferred outflows and inflows of resources. A deferred
outflow of resource is defined as consumption of net position by the Electric Fund that is
applicable to a future reporting period. A deferred inflow of resources is defined as an
acquisition of net position by the Electric Fund that is applicable to a future reporting
period. On June 30, 2022, the Electric Fund has deferred outflows of resources
representing deferred amounts on bond refunding, pension-related transactions, and
postemployment benefit-related transactions, and deferred inflows of resources
representing pension-related transactions and postemployment benefit-related
transactions.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(18)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
K. Long-Term Obligations
Bond discounts, premiums and deferred amounts on refunding are amortized over the
life of the bonds.
L. Net Position
The Electric Fund’s financial statements utilize a net position presentation. Net position
is categorized as invested in capital assets (net of related debt), restricted and
unrestricted.
Net Investment in Capital Assets – This category groups all capital assets into
one component of net position. Accumulated depreciation and the outstanding
balances of liabilities that are attributable to the acquisition, construction or
improvement of these assets reduce the balance in this category.
Restricted Net Position – This category presents external restrictions imposed
by creditors, grantors, contributors or laws or regulations of other governments
and restrictions imposed by law through constitutional provisions or enabling
legislation.
Unrestricted Net Position – This category represents the net position of the
Electric Fund not restricted for any project or other purposes or included in Net
Investment in Capital Assets.
The City’s policy regarding whether to first apply restricted or unrestricted resources
when an expense is incurred for purposes for which both restricted and unrestricted net
position are available is to use restricted resources first.
M. Use of Estimates
The preparation of basic financial statements in conformity with U.S. GAAP requires
management to make estimates and assumptions that affect certain reported amounts
and disclosures. Accordingly, actual results could differ from those estimates.
N. Pensions
For purposes of measuring the net pension liability and deferred outflows/inflows of
resources related to pensions and pension expense, information about the fiduciary net
position of the City’s California Public Employees’ Retirement System (CalPERS) plan
and additions to/deductions from the Pension Plans’ fiduciary net position have been
determined on the same basis as they are reported by CalPERS. For this purpose,
benefit payments (including refunds of employee contributions) are recognized when
due and payable in accordance with the benefit terms. Investments are reported at fair
value.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(19)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
O. Postemployment Benefits Other than Pensions (OPEB)
For purposes of measuring the net OPEB liability, deferred outflows of resources and
deferred inflows of resources related to OPEB, and OPEB expense information about
the fiduciary net position of the City’s OPEB Plan and additions to/deductions from the
OPEB Plan’s fiduciary net position have been determined on the same basis as they are
reported by the OPEB Plan. For this purpose, the OPEB Plan recognizes benefit
payments when due and payable in accordance with the benefit terms. Investments are
reported at fair value.
NOTE 2 CASH AND CASH EQUIVALENTS
Cash and cash equivalents as of June 30, 2022 are classified in the accompanying
statement of net position as follows:
Cash and Cash Equivalents 130,758,591$
Restricted Cash and Cash Equivalents 39,025,025
Total Cash and Cash Equivalents 169,783,616$
Cash and cash equivalents as of June 30, 2022 consist of the following:
Equity in the City's Pooled Cash 8,340,938$
Deposits with Financial Institutions 30,593,952
Short-Term Investments 130,848,726
Total Cash and Cash Equivalents 169,783,616$
Equity in the Cash Pool of the City of Vernon
The Electric Fund has equity in the cash pool managed by the City. The Electric Fund is a
voluntary participant in that pool and the pool is governed by and under the regulatory
oversight of the Investment Policy adopted by the City Council of the City. The Electric Fund
has not adopted an investment policy separate from that of the City. The amount of the
Electric Fund cash in this pool is reported in the accompanying financial statements based
upon the Electric Fund’s pro rata share of the amount calculated by the City. The balance
available for withdrawal is based on the accounting records maintained by the City.
The City’s Investment Policy
The City’s Investment Policy sets forth the investment guidelines for all funds of the City.
The Investment Policy conforms to the California Government Code Section 53600 et. seq.
The authority to manage the City’s investment program is derived from the City Council.
Pursuant to Section 53607 of the California Government Code, the City Council annually
appoints the City Treasurer to manage the City’s investment program and approves the
City’s investment policy. The Treasurer is authorized to delegate this authority as deemed
appropriate. No person may engage in investment transactions except as provided under
the terms of the Investment Policy and the procedures established by the Treasurer.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(20)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
The City’s Investment Policy (Continued)
This Investment Policy requires that the investments be made with the prudent person
standard, that is, when investing, reinvesting, purchasing, acquiring, exchanging, selling or
managing public funds, the trustee (Treasurer and staff) will act with care, skill, prudence,
and diligence under the circumstances then prevailing, including but not limited to, the
general economic conditions and the anticipated needs of the City.
The Investment Policy also requires that when following the investing actions cited above,
the primary objective of the trustee be to safeguard the principal, secondarily meet the
liquidity needs of depositors, and then achieve a return on the funds under the trustee’s
control. Further, the intent of the Investment Policy is to minimize the risk of loss on the
City’s held investments from:
A. Credit risk
B. Custodial credit risk
C. Concentration of credit risk
D. Interest rate risk
Investments Authorized by the California Government Code and the City’s Investment
Policy
The table below identifies the investment types that are authorized for the City by the
California Government Code and the City’s Investment Policy. The table also identifies
certain provisions of the California Government Code that address interest rate risk, credit
risk, and concentration of credit risk. This table does not address investment of debt
proceeds held by the bond trustee that are governed by the provisions of debt agreements
of the City, rather than the general provisions of the California Government Code or the
City’s Investment Policy.
Maximum Maximum
Authorized Maximum Percentage Investment Minimum
Investment Type Maturity of Portfolio* in One Issuer Rating
U.S. Treasury Bonds 5 Years None None None
State and Local Agency Bonds 5 Years None None None
Securities of the U.S. Government, or
its Agencies 5 Years None None None
Certain Asset-Backed Securities 5 Years 20% None AA
Negotiable Certificates of Deposit 5 Years 30% None None
Bankers' Acceptances 180 Days 40% 30% None
Commercial Paper 270 Days 25% 10% P-1
Repurchase Agreements 1 year None None None
Reverse Repurchase Agreements 92 Days 20% None None
Medium-Term Notes 5 Years 30% None A
Mutual Funds Investing in Eligible Securities N/A 20% 10% AAA
Money Market Mutual Funds N/A 20% 10% AAA
Mortgage Pass-Through Securities 5 Years 20% None AA
State Administered Pool Investment N/A None $75 Million None
* Excluding amounts held by bond trustee that are not subject to California Government Code restrictions.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(21)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Investments Authorized by Debt Agreements
Investments of debt proceeds held by bond trustees are governed by provisions of the debt
agreements, rather than the general provisions of the California Government Code or the
City’s Investment Policy. The table below identifies the investment types that are authorized
for investments held by the bond trustee. The table also identifies certain provisions of these
debt agreements that address interest rate risk, credit risk, and concentration of credit risk.
Maximum Maximum
Authorized Maximum Percentage Investment Minimum
Investment Type Maturity of Portfolio in One Issuer Rating
Securities of the U.S. Government, or
its Agencies None None None None
Certain Asset-Backed Securities None None None AA
Certificates of Deposit None None None None
Bankers' Acceptances 1 Year None None None
Commercial Paper None None None P-1
Money Market Mutual Funds N/A None None AAA
State Administered Pool Investment N/A None $75 Million None
Investment Contracts None None None None
Disclosure Relating to Interest Rate Risk
Interest rate risk is the risk that changes in market interest rates will adversely affect the fair
value of an investment. Generally, the longer the maturity of an investment, the greater the
sensitivity of its fair value to changes in market interest rates. One of the ways that the City
manages its exposure to interest rate risk is by purchasing a combination of shorter-term
and longer-term investments and by timing cash flows from maturities so that a portion of
the portfolio is maturing or coming close to maturity evenly over time as necessary to
provide the cash flow and liquidity needed for operations. The City has no specific limitations
with respect to this metric. Information about the sensitivity of the fair values of the Electric
Fund’s investments (including investments held by bond trustee) to market interest rate
fluctuations is provided in the following table that shows the distribution of the Electric
Fund’s investments by maturity:
Investment Maturities
Fair Value (in Months)
as of Less than 13 to 25 to
Investment Type 6/30/2022 12 Months 24 Months 60 Months
Local Agency Investment Fund 627,044$ 627,044$ -$ -$
Held by Trustee:
Money Market Mutual Funds 130,221,682 130,221,682 - -
Total investments 130,848,726$ 130,848,726$ -$ -$
Disclosures Relating to Credit Risk
Generally, credit risk is the risk that an issuer of an investment will not fulfill its obligation to
the holder of the investment. This is measured by the assignment of a rating by a nationally
recognized statistical rating organization. Presented below is the minimum rating required by
the California Government Code, the City’s Investment Policy, or debt agreements, and the
actual rating as of the year-end for each investment type.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(22)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Disclosures Relating to Credit Risk (Continued)
Minimum Actual Fair Value
Required Credit Rating as of
Investment Type Rating Moody's / S&P June 30, 2022
Local Agency Investment Fund Not Rated Not Rated 627,044$
Held by Trustee:
Money Market Funds Aaa / AAA Aaa / AAA 130,221,682
Total in Custody of Trustee 130,848,726$
Concentration of Credit Risk
The City’s Investment Policy places no limit on the amount the City may invest in any one
issuer excluding a 10% limitation on commercial paper, mutual funds, and money market
mutual funds and a 30% limitation on bankers’ acceptances. The City’s Investment Policy
also places no limit on the amount of debt proceeds held by the bond trustee that the trustee
may invest in one issuer that is governed by the provisions of debt agreements of the City,
rather than the general provisions of the California Government Code or the City’s
Investment Policy. As of June 30, 2022, there were no investments held by the Electric Fund
that exceeded 5% in any one issuer, excluding money market mutual funds.
Custodial Credit Risk
Custodial credit risk for deposits is the risk that, in the event of the failure of a depository
financial institution, a government will not be able to recover its deposits or will not be able
to recover collateral securities that are in the possession of an outside party. The custodial
credit risk for investments is the risk that, in the event of the failure of the counterparty to a
transaction, a government will not be able to recover the value of its investment or collateral
securities that are in the possession of another party.
The California Government Code and the City’s Investment Policy do not contain legal or
policy requirements that would limit the exposure to custodial credit risk for deposits or
investments. Under the California Government Code, a financial institution is required to
secure deposits, in excess of the FDIC insurance amount of $250,000, made by state or
local governmental units by pledging government securities held in the form of an undivided
collateral pool. The market value of the pledged securities in the collateral pool must equal
at least 110% of the total amount deposited by the public agencies. California law also
allows financial institutions to secure City deposits by pledging first trust deed mortgage
notes having a value of 150% of the secured public deposits. Such collateral is held by the
pledging financial institution’s trust department or agent in the City’s name.
At June 30, 2022, all of the Electric Fund’s deposits were insured or collateralized as
required by Section 53652 of the California Government Code.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(23)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Local Agency Investment Fund (LAIF)
The Electric Fund also maintained cash balances with the state of California Local Agency
Investment Fund (LAIF). LAIF is an external investment pool sponsored by the state of
California. The administration of LAIF is provided by the California State Treasurer and
regulatory oversight is provided by the Pooled Money Investment Board and the Local
Investment Advisory Board. The value of the pool shares in LAIF, which may be withdrawn,
is determined on an amortized cost basis, which is different than the fair value of the Electric
Fund’s position in the pool.
Fair Value Measurement
The Electric Fund categorizes its fair value measurements within the fair value hierarchy
established by generally accepted accounting principles. The hierarchy is based on the
valuation inputs used to measure the fair value of the asset.
Level 1 inputs are quoted prices for identical assets or liabilities in active markets
that the government can access at the measurement date.
Level 2 inputs are other than quoted prices included in Level 1 that are observable
for an asset or liability, either directly or indirectly.
Level 3 inputs are unobservable inputs for an asset or liability.
The Electric Fund’s investments in money market mutual funds and LAIF are not subject to
categorization in the fair value hierarchy.
NOTE 3 ACCOUNTS RECEIVABLE
The Electric Fund’s accounts receivable at June 30, 2022, are as follows:
Accounts Receivable 13,367,733$
Less: Allowance for Uncollectible Accounts (971,686)
Total Accounts Receivable, Net 12,396,047$
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(24)
NOTE 4 INTERNAL TRANSACTIONS
Transactions between the Electric Fund and the other City funds commonly occur in the
normal course of business for services received or furnished (accounting, management,
engineering, legal services, and capital projects).
Advances to Other City Funds
The following table summarizes the Electric Fund’s advances to the other City funds at
June 30, 2022:
Advances to Other City Funds - July 1, 2021 27,193,955$
Advance Repaid by City Funds During the Year (114,065)
Advances to Other City Funds - June 30, 2022 27,079,890$
The advances between the other City funds and the Electric Fund do not accrue interest due
to the nature of the City’s operational relationship and capital projects funded by the Electric
Fund that benefits both. On November 6, 2012, the City adopted Resolution No. 2012-215
extending the repayment term of the advance to the other City funds from 15 months to a
period of over 10 years.
The City’s General Fund allocates certain administrative and overhead costs to the Electric
Fund which is included as part of the cost of sales. The allocated cost for the year ended
June 30, 2022, was $3,203,444.
Transfers to City
The Electric Fund’s retail rates are established by the City Council and are not subject to
regulation by the California Public Utility Commission or any other state agency. The retail
rates include a 3% surcharge for payments in lieu of franchise tax to the City’s General
Fund. For the current year, the Electric Fund paid the City’s General Fund $5,033,574 in lieu
of franchise tax. Additionally, for the current year, the Electric Fund paid the City’s General
Fund $181,387 for 40% of the cost of the new ERP system. This amount is reported in the
accompanying financial statements as part of operating expenses.
Under the City Charter and the Electric Fund’s electric revenue bond indentures, the Electric
Fund is allowed to transfer up to 11.5% of its retail sales after meeting debt service
obligations and certain debt coverage ratios. However, no additional transfers were made
for the year ended June 30, 2022.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(25)
NOTE 5 CAPITAL ASSETS
Capital asset activity of the Electric Fund for the fiscal year ended June 30, 2022, was as
follows:
Balance Balance
June 30, 2021 Additions Deletions Transfers June 30, 2022
Capital Assets, Not Being Depreciated:
Electric Utility - Land 13,193,594$ -$ -$ -$ 13,193,594$
Electric Utility - Intangibles - Environmental Credits 1,163,811 3,610,772 - - 4,774,583
Electric Utility - Construction In Progress 45,324,750 129,024 - - 45,453,774
Total Capital Assets, Not Being
Depreciated 59,682,155 3,739,796 - - 63,421,951
Capital Assets, Being Depreciated:
Electric Utility - Production Plant 16,189,303 196,173,685 - - 212,362,988
Electric Utility - Transmission Plant 4,888,113 - (1,271,649) - 3,616,464
Electric Utility - Distribution Plant 258,451,179 16,781,817 (18,181,346) - 257,051,650
Electric Utility - General Plant 9,587,933 192,379 (25,903) - 9,754,409
Total Capital Assets, Being Depreciated 289,116,528 213,147,881 (19,478,898) - 482,785,511
Less Accumulated Depreciation for:
Electric Utility - Production Plant (10,757,493) (8,634,043) - - (19,391,536)
Electric Utility - Transmission Plant (3,424,581) (78,093) 1,059,485 - (2,443,189)
Electric Utility - Distribution Plant (101,227,123) (7,438,076) 16,493,501 - (92,171,698)
Electric Utility - General Plant (6,148,921) (360,709) 25,903 - (6,483,727)
Total Accumulated Depreciation (121,558,118) (16,510,921) 17,578,889 - (120,490,150)
Total Capital Assets, Being Depreciated, Net
Electric Utility - Production Plant 5,431,810 187,539,642 - - 192,971,452
Electric Utility - Transmission Plant 1,463,532 (78,093) (212,164) - 1,173,275
Electric Utility - Distribution Plant 157,224,056 9,343,741 (1,687,845) - 164,879,952
Electric Utility - General Plant 3,439,012 (168,330) - - 3,270,682
Net Depreciable Assets 167,558,410 196,636,960 (1,900,009) - 362,295,361
Total Capital Assets, Net 227,240,565$ 200,376,756$ (1,900,009)$ -$ 425,717,312$
The Electric Fund’s total depreciation expense for the year was $16,510,921.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(26)
NOTE 6 LONG-TERM OBLIGATIONS
As of June 30, 2022, outstanding debt obligations consisted of the following:
$43,765,000 Electric System Revenue Bonds (2008 Taxable Series A)
At June 30, 2022, $37,895,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $72,050,772, payable through
fiscal year 2039. For the current year, debt service and net electric revenues were
$4,240,768 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2008 Taxable Series A were issued to provide funds to (i) finance the cost of certain capital
improvements to the City’s Electric System, (ii) fund a deposit to the Debt Service Reserve
Fund, and (iii) to pay costs of issuance of the 2008 Bonds.
$37,640,000 Electric System Revenue Bonds (2012 Series A)
On January 10, 2012, the City issued Electric System Revenue Bonds, 2012 Series A, in the
amount of $37,640,000. The City of Vernon Electric System Revenue Bonds, 2012 Series A
were issued to provide funds to (i) pay a portion of the costs of certain capital improvements
to the City’s Electric System, (ii) to provide for capitalized interest on the 2012 Series A
Bonds, and (iii) to pay costs of issuance of the 2012 Series A Bonds. The Electric System
Revenue Bonds were refunded in the current fiscal year with the issuance of the Electric
System Revenue Bonds 2021 Series A.
$35,100,000 Electric System Revenue Bonds (2012 Taxable Series B)
On January 10, 2012, the City issued Electric System Revenue Bonds, 2012 Series B, in the
amount of $35,100,000. During the current fiscal year, a portion of the Electric System
Revenue Bonds were refunded with the issuance of the Electric System Revenue Bonds
2022 Series A. At June 30, 2022, $11,505,000 remained outstanding. The bonds are special
obligation bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $12,752,831, payable through
fiscal year 2027. For the current year, debt service and net electric revenues were
$25,817,900 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2012 Taxable Series B were issued to provide funds to (i) refund the $28,680,000 aggregate
principal amount of 2009 Bonds maturing on August 1, 2012, (ii) to pay a portion of the
Costs of the 2012 Project, and (iii) to pay costs of issuance of the 2012 Taxable Series B
Bonds.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(27)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
$111,720,000 Electric System Revenue Bonds (2015 Taxable Series A)
At June 30, 2022, $111,720,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $124,140,019, payable through
fiscal year 2027. For the current year, debt service and net electric revenues were
$5,087,518 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2015 Taxable Series A were issued to provide funds to (i) refund a portion of the
Outstanding Electric System Revenue Bonds, 2009 Series A; (ii) finance the Costs of certain
Capital Improvements to the City’s Electric System by reimbursing the Electric System for
the prior payment of such Costs from the Light and Power Fund; (iii) fund a deposit to the
Debt Service Reserve Fund; and (iv) pay costs of issuance of the 2015 Bonds.
$71,990,000 Electric System Revenue Bonds (2020 Series A)
At June 30, 2022, $19,305,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of electric revenues payable to
bondholders. The debt service remaining on the bonds is $30,319,875, payable through
fiscal year 2038. For the current year, debt service and net electric revenues were
$25,596,000 and $69,089,394, respectively. Under the Bond Indenture of Trust, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Light and Power Enterprise (as those terms
are defined in the Indenture of Trust). The City of Vernon Electric System Revenue Bonds,
2020 Series A were issued to provide funds to (i) to finance the acquisition and construction
of certain capital improvements to the Electric System of the City, (ii) to refund all the City’s
outstanding Electric System Revenue Bonds, 2009 Series A, and (iii) to pay costs of
issuance of the 2020 Bonds.
$183,815,000 Electric System Revenue Bonds (2021 Series A)
In December 2021, the City of Vernon issued 2021A Electric System Revenue Bonds in the
amount of $183,815,000 (i) to pay the costs of the acquisition by the City of Vernon of a
134-megawatt natural gas-fired generating facility located within the City limits on land
owned by the City, together with certain related electrical interconnection facilities and other
assets, property, and contractual rights; (ii) to fund a deposit to the Debt Service Reserve
Fund in satisfaction of the Debt Service Reserve Requirement; and (iii) to pay costs of
issuance of the 2021 bonds.
The bonds bear interest rates between 4.00%-5.00% that is payable on a semi-annual basis
on April 1 and October 1, commencing April 1, 2022. At June 30, 2022, $173,815,000
remained outstanding. The bonds are special obligation bonds which are secured by an
irrevocable pledge of electric revenues payable to bondholders. The debt service remaining
on the bonds is $207,098,300, payable through fiscal year 2028. For the current year, debt
service and net electric revenues were $12,671,686 and $69,089,394, respectively.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(28)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
$183,815,000 Electric System Revenue Bonds (2021 Series A) (Continued)
Under the Bond Indenture of Trust, interest and principal on the bonds are payable from Net
Revenues (or Revenues less Operation and Maintenance Expenses) and/or amounts in the
Light and Power Enterprise (as those terms are defined in the Indenture of Trust).
$52,070,000 Electric System Revenue Bonds (2022 Series A)
In December 2021, the City of Vernon issued 2022A Electric System Revenue Bonds in the
amount of $52,070,000 to refund the 2012A Electric System Revenue Bonds, a portion of
the 2012B Electric Revenue Bonds, and provide for the costs of issuing the bonds.
The bonds bear interest rates between 4.00%-5.00% that is payable on a semi-annual basis
beginning February 1 and August 1, commencing on August 1, 2022. At June 30, 2022,
$52,070,000 remained outstanding. The bonds are special obligation bonds which are
secured by an irrevocable pledge of electric revenues payable to bondholders. The debt
service remaining on the bonds is $78,789,447, payable through fiscal year 2042. For the
current year, debt service and net electric revenues were $-0- and $69,089,394,
respectively.
Under the Bond Indenture of Trust, interest and principal on the bonds are payable from Net
Revenues (or Revenues less Operation and Maintenance Expenses) and/or amounts in the
Light and Power Enterprise (as those terms are defined in the Indenture of Trust). The City
of Vernon Electric System Revenue Bonds, 2021 Series A were issued to (i) refund and
defease all of the City’s outstanding Electric System Revenue Bonds, 2012 Series A and a
portion of the City’s outstanding Electric System Revenue bonds, 2012 Taxable Series B
and (ii) pay costs of issuance of the 2022 Bonds.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(29)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
A summary of bonds payable under the Electric Fund is as follows:
Fixed Annual Original
Interest Principal Issue Outstanding
Bonds Maturity Rates Installments Amount June 30, 2022
City of Vernon 07/01/38 7.40% - To begin 07/01/10: 43,765,000$ 37,895,000$
Electric System Revenue Bonds, 8.59% $265,000 -
2008 Taxable Series A $4,065,000
City of Vernon 08/01/26 6.25% - To begin 08/01/22: 35,100,000 11,505,000
Electric System Revenue Bonds, 6.50% $6,165,000 -
2012 Taxable Series B $7,940,000
City of Vernon 08/01/26 4.05% - To begin 08/01/23: 111,720,000 111,720,000
Electric System Revenue Bonds, 4.85% $15,925,000 -
2015 Taxable Series A $22,540,000
City of Vernon 08/01/50 5.00% To begin 08/03/20: 71,990,000 19,305,000
Electric System Revenue Bonds, $1,525,000 -
2020 Taxable Series A $28,655,000
City of Vernon 04/01/28 4% - To begin 04/01/22: 183,815,000 173,815,000
Electric System Revenue Bonds, 5.00% $10000,000 -
2021 Taxable Series A $54,915,000
City of Vernon 08/01/41 5.00% To begin 05/05/22: 52,070,000 52,070,000
Electric System Revenue Bonds, $950,000 -
2022 Taxable Series A $5,850,000
Premium 42,795,419
Discounts (1,168,943)
Total Revenue Bonds 447,936,476$
As of June 30, 2022, annual debt service requirements of the Electric Fund to maturity are
as follows:
Electric System Revenue Bonds
2008 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 1,025,000$ 3,211,156$
2024 1,120,000 3,119,029
2025 1,220,000 3,018,526
2026 1,330,000 2,909,004
2027 1,450,000 2,789,603
2028-2032 9,445,000 11,747,040
2033-2037 14,510,000 6,677,437
2038-2041 7,795,000 683,979
Total Requirements 37,895,000$ 34,155,772$
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(30)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
Electric System Revenue Bonds
2012 Taxable Series B
Fiscal Year Ending June 30,Principal Interest
2023 6,165,000$ 531,831$
2024 1,170,000 302,613
2025 1,305,000 225,269
2026 1,390,000 140,181
2027 1,475,000 47,938
Total Requirements 11,505,000$ 1,247,832$
Electric System Revenue Bonds
2015 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 22,540,000$ 4,580,368$
2024 23,520,000 3,596,938
2025 24,585,000 2,530,618
2026 25,780,000 1,341,193
2027 15,295,000 370,904
Total Requirements 111,720,000$ 12,420,019$
Electric System Revenue Bonds
2020 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 -$ 965,250$
2024 - 965,250
2025 - 965,250
2026 - 965,250
2027 - 965,250
2028-2032 6,585,000 4,188,125
2033-2037 10,325,000 1,940,625
2038-2041 2,395,000 59,875
Total Requirements 19,305,000$ 11,014,875$
Electric System Revenue Bonds
2021 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 20,380,000$ 8,385,050$
2024 21,335,000 7,405,125
2025 22,400,000 6,325,000
2026 23,530,000 5,190,875
2027 31,255,000 3,917,875
2028 54,915,000 2,059,375
Total Requirements 173,815,000$ 33,283,300$
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(31)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
Electric System Revenue Bonds
2022 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 -$ 1,923,697$
2024 4,690,000 2,486,250
2025 4,885,000 2,246,875
2026 5,130,000 1,996,500
2027 5,405,000 1,733,125
2028-2032 5,270,000 7,357,500
2033-2037 6,765,000 5,860,625
2038-2042 19,925,000 3,114,875
Total Requirements 52,070,000$ 26,719,447$
Changes in Long-Term Liabilities
The following is a summary of long-term liabilities transactions for the fiscal year ended
June 30, 2022.
Amounts
Balance Balance Due Within
June 30, 2021 Additions Reductions June 30, 2022 One Year
Other Debt - Bonds Payable 266,635,000$ 235,885,000$ (96,210,000)$ 406,310,000$ 50,110,000$
Bond Premium 7,189,882 38,266,557 (2,661,020) 42,795,419 -
Bond Discount (1,923,931) - 754,988 (1,168,943) -
Compensated Absences (Note 1) 1,052,396 724,315 (667,888) 1,108,823 369,608
Total 272,953,347$ 274,875,872$ (98,783,920)$ 449,045,299$ 50,479,608$
Expense Stabilization Fund
The Electric Fund maintains an Expense Stabilization Fund held by a Trustee in such
amounts, at such times and from sources as shall be determined by the City in its sole
discretion. If an Event of Default under the Indenture has occurred and is continuing, the
Trustee shall transfer all moneys in this fund to the debt service funds as provided in the
Indenture. Moneys on deposit in this Fund may be withdrawn by the City at any time that no
Event of Default exists under the Indenture. As at June 30, 2022, this fund has a balance of
$38,934,149.
Right to Accelerate Upon Default
Notwithstanding anything contrary in the Indenture or in the Bonds, upon the occurrence of
an Event of Default, the Trustee may, with the consent of each Credit Provider whose
consent is required by a Supplemental Indenture or a Credit Support Agreement, and shall,
at the direction of the Owners of a majority in principal amount of Outstanding Bonds (other
than Bonds owned by or on behalf of the City) by written notice to the City, declare the
principal of the Outstanding Bonds and the interest thereon to be immediately due and
payable, whereupon such principal and interest shall, without further action, become and be
immediately due and payable.
Credit Ratings
As of June 30, 2022, the ratings on all Electric System Revenue Bonds of the City were
BBB+/Stable by S&P and Baa1/Stable by Moody’s.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(32)
NOTE 7 RISK MANAGEMENT
The Electric Fund is in the City’s self-insurance program as part of its policy to self-insure
certain levels of risk within separate lines of coverage to maximize cost savings.
The City is exposed to various risks of loss related to torts; theft of, damage to, and
destruction of assets, errors, and omissions; injuries to employees, and natural disasters.
The City utilizes insurance policy(s) to transfer these risks. Each policy has either self-
insured retention or deductible, which are parts of the City’s Risk Financing Program. These
expenses are paid on a cash basis as they are incurred. There have been no significant
settlements or reductions in insurance coverage during the past three fiscal years.
Starting in Fiscal 2010, the City chose to establish Risk Financing in the General Fund,
whereby assets are set aside for claim-litigation settlements associated with the
abovementioned risks up to their self-insured retentions or policy deductibles. Athens
Administrators Inc. is the Third-Party Administrator for the City’s workers’ compensation
program, and they provide basic services for general liability claims and litigation. The
insurance limits for the fiscal year 2022 are as follows:
Deductible/SIR
Insurance Type Program Limits (Self-Insured Retention)
Excess Liability Insurance $20,000,000 $2,000,000 SIR per occurrence
D and O Employment Practice $2,000,000 $150,000 SIR non-safety; $150,000 SIR safety
Excess Workers Compensation $50,000,000 $1,500,000 SIR per occurrence for presumptive loss
Employer's Liability $1,000,000 $1,000,000 SIR per occurrence for all employees
Commercial Property Insurance $100,000,000 $25,000 except:
$25,000,000 Flood Sublimit $250,000 power stations
$1.5/kVA transfers, subject to a $250,000 minimum
$500,000 named transformers
Employee Dishonest - Crime $1,000,000 $25,000
Pollution - Site Owned $5,000,000 $25,000 for non-utility locations, divested locations
and scheduled storage tanks
$50,000 for utility locations
$100,000 for natural gas pipeline
Cyber Liability $3,000,000 $100,000
Contractors Equipment/Auto $10,000,000 Maximum Loss Per Occurrence $5,000
Physical Damage $1,000,000 Equipment Limit-loss or damage to
any one piece
Residential Property Insurance $8,023,126 Blanket Building Limit $2,500
$89,013 Blanket Business Personal Property Limit
Terrorism and Sabotage $100,000,000 Policy Aggregate N/A
$5,000,000 Active Shooter and Malicious Attack
Per Occurrence/Aggregate
$5,000,000 Terrorism and Sabotage Liability
Per Occurrence/Aggregate
The City has numerous claims and pending litigations, which generally involve accidents
and/or liability or damage to City property. The balance of claims/litigations against the City
is in the opinion of management, ordinary routine matters, incidental to the normal business
conducted by the City. In the opinion of management, such proceedings are substantially
covered by insurance, and the ultimate dispositions of such proceedings are not expected to
have a material adverse effect on the Electric Fund’s financial position, results of operations
or cash flows. Further information regarding the City’s self-insurance program may be found
in the City’s Annual Financial Report.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(33)
NOTE 8 PENSION PLAN
A. General Information About the Pension Plans
Plan Descriptions
All full-time safety and miscellaneous personnel and temporary or part-time employees
who have worked a minimum of 1,000 hours in a fiscal year are eligible to participate in
the City’s cost-sharing and agent multiple-employer defined benefit pension Safety and
Miscellaneous Plans, respectively, administered by the California Public Employees’
Retirement System (CalPERS) that acts as a common investment and administrative
agent for participating public entities within the state of California. The City allocates the
costs of these Plans across all City departments. The Electric Fund’s proportionate
share of the net pension liability of these Plans is reported as a cost-sharing plan in the
financial statements. Benefits vest after five years of service. Employees who retire at
the minimum retirement age with five years of credited service are entitled to retirement
benefits. Monthly retirement benefits are based on a percentage of an employee’s
average compensation for his or her highest consecutive 12 or 36 months of
compensation for each year of credited service.
Benefits Provided
Miscellaneous members hired prior to January 1, 2013, with five years of credited
service may retire at age 55 based on a benefit factor derived from the 2.7% at 55
Miscellaneous formula or may retire between ages 50 and 54 with reduced retirement
benefits. New Miscellaneous members (PEPRA) with five years of credited service may
retire at age 62 based on a benefit factor derived from the 2% at 62 Miscellaneous
formula or may retire between age 52 and 61 with reduced retirement benefits. The
benefit factor increases to a maximum of 2.5% at age 67. Safety members with five
years of credited service may retire at age 50 based on a benefit factor derived from the
3% at 50 Safety formula for sworn Police and Fire Department employees. New Safety
members (PEPRA) with five years of credited service may retire at age 57 based on a
benefit factor derived from the 2.7% at 57 Safety (PEPRA) formula or may retire
between age 50 and 56 with reduced retirement benefits for new Safety (PEPRA)
members of both Police and Fire Departments. CalPERS also provides death and
disability benefits. These benefit provisions and all other requirements are established
by state statute provided through a contract between the City and CalPERS.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(34)
NOTE 8 PENSION PLAN (CONTINUED)
A. General Information About the Pension Plans (Continued)
The Plans’ provisions and benefits in effect at the measurement date of June 30, 2021,
are summarized as follows:
Miscellaneous
Prior to On or After
Hire Date January 1, 2013 January 1, 2013
Benefit Formula 2.7%@55 2%@62
Benefit Vesting Schedule 5 Years of Service 5 Years of Service
Benefit Payments Monthly for Life Monthly for Life
Retirement Age 50 52
Monthly Benefits, as a % of Eligible Compensation 2.0% to 2.7% 1.0% to 2.5%
Required Employee Contribution Rates 8.000% 6.250%
Required Employer Contribution Rates:
Normal Cost Rate 11.380% 11.380%
Payment of Unfunded Liability 3,924,540$ -$
Safety
Prior to On or After
Hire Date January 1, 2013 January 1, 2013
Benefit Formula 3.0%@50 2.7%@57
Benefit Vesting Schedule 5 Years of Service 5 Years of Service
Benefit Payments Monthly for Life Monthly for Life
Retirement Age 50 50
Monthly Benefits, as a % of Eligible Compensation 3.000% 2.0% to 2.7%
Required Employee Contribution Rates 9.000% 13.750%
Required Employer Contribution Rates:
Normal Cost Rate 22.780% 22.780%
Payment of Unfunded Liability 7,063,113$ 15,563$
Contributions
Section 20814(c) of the California Public Employees’ Retirement Law requires that the
employer contribution rates for all public employers be determined on an annual basis by
the actuary and shall be effective on July 1 following notice of a change in the rate.
Funding contributions for both Plans are determined annually on an actuarial basis as of
June 30 by CalPERS. The actuarially determined rate is the estimated amount
necessary to finance the costs of benefits earned by employees during the year, with an
additional amount to finance any unfunded accrued liability. The City is required to
contribute to the difference between the actuarially determined rate and the contribution
rate of employees. For the year ended June 30, 2022, the Electric Fund’s share of
employer contributions made to the Plans was $2,012,496.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(35)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions
Actuarial Assumptions
The net pension liability of each of the Plans is measured as of June 30, 2021, using an
annual actuarial valuation as of June 30, 2020, rolled forward to June 30, 2021, using
standard update procedures. A summary of principal assumptions and methods used to
determine the net pension liability is shown below.
Miscellaneous Safety
Valuation Date June 30, 2020 June 30, 2020
Measurement Date June 30, 2021 June 30, 2021
Actuarial Cost Method Entry Age Normal Entry Age Normal
Actuarial Assumptions:
Discount Rate 7.15% 7.15%
Inflation 2.500% 2.500%
Payroll Growth 2.750% 2.750%
Projected Salary Increase (1) (1)
Mortality Rate Table (2)(2)
Post-Retirement Benefit Increase (3)(3)
(1)Varies by entry age and service.
(2)The mortality table used was developed based on CalPERS-specific data. The
probabilities of mortality are based on the 2017 CalPERS Experience Study for the
period from 1997 to 2015. Pre-retirement and Post-retirement mortality rates includes
15 years of projected mortality improvement using 90% of Scale MP-2016 published by
the Society of Actuaries. For more details on this table, please refer to the CalPERS
Experience Study and Review of Actuarial Assumptions report from December 2017
that can be found on the CalPERS website.
(3)The lessor of contract COLA or 2.50% until Purchasing Power Protection Allowance Floor
on purchasing power applies, 2.50% thereafter.
Long-Term Expected Rate of Return
The long-term expected rate of return on pension plan investments was determined
using a building-block method in which expected future real rates of return (expected
returns, net of pension plan investment expense and inflation) are developed for each
major asset class.
In determining the long-term expected rate of return, CalPERS took into account both
short-term and long-term market return expectations as well as the expected pension
fund cash flows. Using historical returns of all the funds’ asset classes, expected
compound (geometric) returns were calculated over the short-term (first 10 years) and
the long-term (11+ years) using a building-block approach. Using the expected nominal
returns for both short-term and long-term, the present value of benefits was calculated
for each fund. The expected rate of return was set by calculating the rounded single
equivalent expected return that arrived at the same present value of benefits for cash
flows as the one calculated using both short-term and long-term returns. The expected
rate of return was then set equal to the single equivalent rate calculated above and
adjusted to account for assumed administrative expenses.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(36)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
The expected real rates of return by asset class are as follows:
Assumed Real Return Real Return
Asset Years Years
t Class (a)Allocation 1 - 10 (b)11+ (c)
Global Equity 50.00% 4.80% 5.98%
Fixed Income 28.00% 1.00% 2.62%
Inflation Assets 0.00% 0.77% 1.81%
Private Equity 8.00% 6.30% 7.23%
Real Assets 13.00% 3.75% 4.93%
Liquidity 1.00% 0.00% -0.92%
Total 100.00%
(a) In the CalPERS CAFR, Fixed
(b)An expected inflation of 2.0% used for this period.
(c)An expected inflation of 2.92% used for this period.
Discount Rate
The discount rate used to measure the total pension liability was 7.15%. The projection
of cash flows used to determine the discount rate assumed that contributions from plan
members will be made at the current member contribution rates and that contributions
from employers will be made at statutorily required rates, actuarially determined. Based
on those assumptions, the Plan’s fiduciary net position was projected to be available to
make all projected future benefit payments of current plan members. Therefore, the
long-term expected rate of return on plan investments was applied to all periods of
projected benefit payments to determine the total pension liability.
Subsequent Events
On July 12, 2021, CalPERS reported a preliminary 21.3% net return on investments for
fiscal year 2020-21. Based on the thresholds specified in CalPERS Funding Risk
Mitigation policy, the excess return of 14.3% prescribes a reduction in investment
volatility that corresponds to a reduction in the discount rate used for funding purposes
of 0.20%, from 7.00% to 6.80%. Since CalPERS was in the final stages of the four-year
Asset Liability Management (ALM) cycle, the board elected to defer any changes to the
asset allocation until the ALM process concluded, and the board could make its final
decision on the asset allocation in November 2021.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(37)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Subsequent Events (Continued)
On November 17, 2021, the board adopted a new strategic asset allocation. The new
asset allocation along with new capital market assumptions, economic assumptions and
administrative expense assumption support a discount rate of 6.90% (net of investment
expense but without a reduction for administrative expense) for financial reporting
purposes. This includes a reduction in the price inflation assumption from 2.50% to
2.30% as recommended in the November 2021 CalPERS Experience Study and Review
of Actuarial Assumptions. This study also recommended modifications to retirement
rates, termination rates, mortality rates and rates of salary increases that were adopted
by the board. These new assumptions will be reflected in the GASB 68 account
valuation repots for the June 30, 2022 measurement date.
Proportionate Share of Net Pension Liability – Allocation of the City’s Pension Plans to
the Electric Fund
The Electric Funds’ net pension liability for the Plans is measured as the proportionate
share of’ the combined net pension liability of the City’s miscellaneous and safety agent
multiple-employer plans. The Electric Fund’s proportionate share of the combined net
pension liability was based on the Electric Fund’s current year share of contributions to
the pension plans relative to the City’s total current year contributions to the pension
plans.
The Electric Funds’ proportionate share of the combined net pension liability for the
pension plans as of the measurement date ended June 30, 2020 and 2021 was as
follows:
Increase (Decrease)
Total Plan Net Pension
Pension Fiduciary Liability Proportionate
Liability Net Position (Asset)Share
Balance at June 30, 2020 (MD)61,879,846$ 45,617,506$ 16,262,340$ 12.02%
Balance at June 30, 2021 (MD)69,252,712 56,791,532 12,461,180 14.16%
Net Changes during 2020-21 7,372,866$ 11,174,026$ (3,801,160)$ 2.14%
Pension Expense and Deferred Outflows and Inflows of Resources
For the measurement period ended June 30, 2021, the Electric Fund recognized its
proportionate share of the combined pension expense of the Plans, totaling $3,093,351.
At June 30, 2022, the Electric Fund reported its proportionate share of the Plans’
combined deferred outflows of resources and deferred inflows of resources related to
pensions from the following sources:
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(38)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Pension Expense and Deferred Outflows and Inflows of Resources (Continued)
Deferred Deferred
Outflows Inflows
of Resources of Resources
Pension Contributions Subsequent
to Measurement Date 2,012,496$ -$
Differences Between Actual and
Expected Experience 1,725,314 -
Change in Assumptions - -
Net Differences Between Projected and
Actual Earnings on Plan Investments - (7,053,136)
Differences Between Employer Contributions
And Proportionate Share of Contributions - (714,821)
Change in Employer's Proportion 278,567 (73,618)
Total 4,016,377$ (7,841,575)$
$2,012,496 reported as deferred outflows of resources related to contributions
subsequent to the measurement date will be recognized as a reduction of the net
pension liability in the year ending June 30, 2023. Differences between projected and
actual investment earnings are amortized on a five-year straight-line basis and all other
amounts are amortized over the expected average remaining service lives of all
members that are provided with benefits. Other amounts reported as deferred outflows
of resources and deferred inflows of resources related to pensions will be recognized as
pension expense as follows:
Fiscal Year Ended June 30,Total
2023 (1,053,016)$
2024 (1,203,219)
2025 (1,623,974)
2026 (1,957,485)
2027 -
Thereafter -
Sensitivity of the Net Pension Liability to Changes in the Discount Rate
The following presents the Electric Fund’s proportionate share of the Plans’ combined
net pension liability, calculated using a discount rate of 7.15%, as well as what the
Electric Fund’s proportionate share of the Plans’ combined net pension liability would be
if it were calculated using a discount rate that is a 1-percentage point lower or a
1-percentage point higher than the current rate:
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(39)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Sensitivity of the Net Pension Liability to Changes in the Discount Rate (Continued)
Total
1% Decrease 6.15%
Net Pension Liability 21,944,686$
Current Discount Rate 7.15%
Net Pension Liability 12,461,180$
1% Increase 8.15%
Net Pension Liability 4,681,201$
Pension Plan Fiduciary Net Position
Detailed information about each pension plan’s fiduciary net position is available in the
separately issued CalPERS financial reports.
Payable to the Pension Plan
At June 30, 2022, the Electric Fund had no outstanding amount of contributions to the
pension plans required for the year ended June 30, 2022.
NOTE 9 OTHER POSTEMPLOYMENT BENEFITS (OPEB)
The other postemployment benefits (OPEB) described in the following paragraphs relate to
the City’s OPEB plan. The Electric Fund’s share of the net pension liability of the City’s
OPEB Plan is reported as a cost-sharing plan in these financial statements since the Electric
Fund’s operations are handled by City employees who are eligible to participate in the City’s
OPEB Plan.
Benefits Provided
Retiree medical and dental benefits are established through the City’s Fringe Benefits and
Salary Resolution as well as individual memoranda of understanding between the City and
the City’s various employee bargaining groups. Generally, the City will provide a
postemployment benefit only to those employees who retire at age sixty (60) or later with
twenty (20) years of continuous uninterrupted service, up to the age of sixty-five (65).
Alternatively, employees who retire before the age of sixty (60) with twenty (20) years of
continuous uninterrupted service, will be permitted to pay their medical and dental premium
cost and upon reaching the age of sixty (60), the City will pay the premium for the medical
and dental plans until they reach the age of sixty-five (65).
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(40)
NOTE 9 OTHER POSTEMPLOYMENT BENEFITS (OPEB) (CONTINUED)
Benefits Provided (Continued)
Resolution 2012-217 granted specific retiree medical benefits to employees who retired
during the 2012-2013 fiscal year in order to provide an incentive for early retirement
whereby the City authorized the payment of medical and dental insurance premiums for
eligible retiring employees and their eligible dependents with at least ten (10) years of
service plus 5% for each additional full year of service above the ten (10) years of service.
Resolution 2013-06 declared that the retiree medical benefits which had not been a vested
right for employees will continue to be a nonvested right for employees who continue to be
employed by the City on or after July 1, 2013, but will be a vested right for those who retire
during the 2012-2013 fiscal year. The City’s plan is considered a substantive OPEB plan
and the City recognizes costs in accordance with GASB Statement No 75. The City may
terminate its unvested OPEB in the future.
Funding Policy and Contributions
The City has established an irrevocable OPEB trust with assets dedicated to paying future
retiree medical benefits. The City intends to contribute 100% or more of the actuarially
determined contribution for the explicit subsidy liability only. The portion of the liability due to
the implicit subsidy is not prefunded but is paid as benefits come due. For the fiscal year
ended June 30, 2022, the Electric Fund’s proportionate share of contributions made was
$415,223 ($217,817 contributed to the OPEB trust, $128,240 paid for retiree premiums, and
the estimated implied subsidy of $69,166).
Net OPEB Liability
The City’s net OPEB liability is measured as of June 30, 2021, and the total OPEB liability
used to calculate the net OPEB liability was determined by an actuarial valuation as of
June 30, 2021. A summary of the principal assumptions and methods used to determine the
total OPEB liability is shown on the next page.
Actuarial Assumptions
The valuation has been prepared on a closed group basis. Assumptions such as age-related
healthcare claims, healthcare trends, retiree participation rates, and spouse coverage, were
selected based on demonstrated plan experience and the best estimate of expected future
experience. Explicit subsidy benefit payments by employee group were allocated based on
expected benefit payments. The following actuarial assumptions, applied to all periods
included in the measurement unless otherwise specified:
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(41)
NOTE 9 OTHER POSTEMPLOYMENT BENEFITS (OPEB) (CONTINUED)
Actuarial Assumptions (Continued)
Funding Method Entry age normal level percent of pay cost method
Inflation 2.25%
Salary Increases 2.75% annual increases
Long-Term Return on Assets 6.25% net of investment expenses
Discount Rate 6.25%
Healthcare Cost Trend Rates 6.3% for FY2022, gradually decreasing over several
decades to ultimate rate of 3.8% in FY76 and later
years
Mortality 2017 CalPERS Experience Study. Tables include
15 years of static mortality improvement using 90%
of scale MP-2016
Long-Term Expected Rate of Return
The long-term expected rate of return was determined using a building-block method in
which best-estimate ranges of expected future real rates of return (expected returns, net of
OPEB plan investment expense and inflation) are developed for each major asset class.
These ranges are combined to produce the long-term expected rate of return by weighing
the expected future real rates of return by the target asset allocation percentage and by
adding expected inflation. Best estimates of arithmetic real rates of return for each major
asset class included in the OPEB plan’s target asset allocation as of June 30, 2021 are
summarized in the following table:
Long-Term
Target Expected Real
Asset Class Allocation Rate of Return
CERBT Strategy 1:
Equity 59.00% 4.42%
Fixed Income 25.00 1.00%
TIPS 5.00 0.15%
Commodities 3.00 3.98%
REITs 8.00 1.73%
Total 100.00%
Discount Rate
The discount rate used to measure the total OPEB liability was 6.25%. The projection of
cash flows used to determine the discount rate assumed that City’s contributions will be
made at rates equal to the actuarially determined contribution rates. Based on those
assumptions, the fiduciary net position was projected to be available to make all projected
OPEB payments for current active and inactive employees and beneficiaries. Therefore, the
long-term expected rate of return on plan investments was applied to all periods of projected
benefit payments to determine the total OPEB liability.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(42)
NOTE 9 OTHER POSTEMPLOYMENT BENEFITS (OPEB) (CONTINUED)
Change of Assumptions
Medical trend rates were updated to exclude the Affordable Care Act’s Excise Tax on high-
cost health insurance plan due to its repeal.
Allocation of the Net OPEB Liability
The Electric Fund’s proportionate share of the net OPEB liability as of the measurement
dates ended June 30, 2020 and 2021 was as follows:
Increase (Decrease)
Total Plan Net OPEB
OPEB Fiduciary Liability Proportionate
Liability Net Position (Asset)Share
Balance at June 30, 2020 (MD)3,271,125$ 841,782$ 2,429,343$ 12.02%
Balance at June 30, 2021 (MD)3,877,225 1,559,455 2,317,770 14.16%
Net Changes during FY 2021-22 606,100$ 717,673$ (111,573)$ 2.14%
Sensitivity of the Net OPEB Liability to Changes in the Discount Rate
The following presents the Electric Fund’s proportionate share of net OPEB liability if it were
calculated using a discount rate that is 1% point lower or 1% point higher than the current
rate:
Discount Rate
1% Decrease Current Rate 1% Increase
(5.25%)(6.25%)(7.25%)
Net OPEB Liability 2,751,626$ 2,317,770$ 1,953,422$
Sensitivity of the Net OPEB Liability to Changes in the Healthcare Cost Trend Rates
The following presents the Electric Fund’s proportionate share of the net OPEB liability if it
were calculated using a healthcare cost trend rates that are 1% point lower (5.3%
decreasing to an ultimate rate of 2.8%) or 1% point higher (7.3% decreasing to an ultimate
rate of 4.8%) than the current rate:
Healthcare Trend Rate
1% Decrease Current Rate 1% Increase
Net OPEB Liability 2,134,592$ 2,317,770$ 2,500,009$
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(43)
NOTE 9 OTHER POSTEMPLOYMENT BENEFITS (OPEB) (CONTINUED)
OPEB Expense and Deferred Inflows and Outflows of Resources Related to OPEB
For the year ended June 30, 2022, the Electric Fund recognized its proportionate share of
the OPEB expense(revenue) of $(119,343). At June 30, 2022, the Electric Fund reported
deferred outflows of resources and deferred inflows of resources related to OPEB from the
following sources:
Deferred Deferred
Outflows Inflows
of Resources of Resources
Contributions Between Measurement Date and
Reporting Date 415,223$ -$
Difference Between Expected and Actual Liability 19,646 (499,577)
Changes of Assumptions 63,261 (530,789)
Net Differences Between Projected and Actual
Earnings on Investments - (156,697)
Total 498,130$ (1,187,063)$
The $415,223 reported as deferred outflows of resources related to contributions
subsequent to the measurement date will be recognized as a reduction of the net OPEB
liability in the year ended June 30, 2023. Differences between projected and actual
investment earnings are amortized on a five-year straight-line basis and all other amounts
are amortized over the expected average remaining service lives of all members that are
provided with benefits. Other amounts reported as deferred outflows of resources and
deferred inflows of resources related to OPEB will be recognized as OPEB expense as
follows:
Deferred
Outflows
(Inflows)
Fiscal Year Ending June 30,of Resources
2022 (330,601)$
2023 (331,825)
2024 (329,873)
2025 (88,956)
2026 (10,577)
Thereafter (12,324)
Subsequent Events
There were no subsequent events that would materially affect the results presented in this
disclosure.
Payable to the OPEB Plan
At June 30, 2022, the Electric Fund had no outstanding amount of contributions to the
OPEB plan required for the year ended June 30, 2022.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(44)
NOTE 10 ELECTRIC FUND OPERATIONS AND COMMITMENTS
Bicent Agreements
Asset Sale
On December 13, 2007, the City entered into an Amended and Restated Purchase and
Sale Agreement (the Bicent Agreement), with Bicent (California) Power LLC (Bicent),
which is an affiliate of Bicent Holdings and Natural Gas Partners, to sell to Bicent the
Malburg Generating Station (MGS) and the economic burdens and benefits of the City’s
interests in 22 MW from the Hoover Dam Uprating Project for $287,500,000. This
transaction closed on April 10, 2008.
Bicent agreed to sell the capacity and the energy of the MGS to the City on the terms set
forth in a Power Purchase Tolling Agreement, by and between the City and Bicent, dated
as of April 10, 2008 (the PPTA). City treated the PPTA as an asset lease-back
transaction due to a 30-year ground lease between the City and BCM by deferring most
of the gain from the sale of MGS to be amortized over the 15-year life of the PPTA. The
City also deferred the gain from the CFD to be amortized over the 10-year life of the
CFD.
On December 15, 2021, the City made the determination to reacquire MGS to achieve
potential costs savings and other resource management benefits. In addition to the
potential savings, the City expects there to be other benefits associated with the
acquisition of MGS, which includes having control of the facility and the site, providing
the City with flexibility with respect to the MGS operations and MGS’s role in the City’s
resource portfolio. The City issued Electric System Revenue Bonds, 2021 Series A to
finance the acquisition. (See Note 6)
Southern California Public Power Authority
In 1980, the City entered into a joint powers agreement with nine (9) Southern California
cities and an irrigation district to form the Southern California Public Power Authority (the
Authority). The Authority’s purpose is the planning, financing, acquiring, constructing, and
operating of projects that generate or transmit electric energy for sale to its participants. The
joint powers agreement has a term expiring in 2030 or such later date as all bonds and
notes of SCPPA and interest thereon have been paid in full or adequate provisions for
payments have been made. A copy of SCPPA’s audited financial statements can be
reviewed on their website at www.scppa.org or can be obtained by written request at 225
South Lake Avenue, Suite 1250, Pasadena, CA 91101.
Take or Pay Contract
The Authority’s interests or entitlements in natural gas, generation, and transmission
projects are jointly owned with other utilities. Under these arrangements, a participating
member has an undivided interest in a utility plant and is responsible for its proportionate
share of the costs of construction and operation and is entitled to its proportionate share
of the energy, available transmission capacity, or natural gas produced. Each joint plant
participant, including the Authority, is responsible for financing its share of construction
and operating costs. The City has the following “take or pay” contract with the Authority:
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(45)
NOTE 10 ELECTRIC FUND OPERATIONS AND COMMITMENTS (CONTINUED)
Southern California Public Power Authority (Continued)
Take or Pay Contract (Continued)
Palo Verde Project
The Authority purchased a 5.91% interest in the Palo Verde Nuclear Generating
Station (the Station), a nuclear-fired generating station near Phoenix, Arizona, from
the Salt River Project Agricultural Improvement and Power District, and a 6.55%
share of the right to use certain portions of the Arizona Nuclear Power Project Valley
Transmission System. The City has a 4.9% entitlement share of the Authority’s
interest in the station.
Between 1983 and 2008, the Authority issued $3.266 billion in debt of Power Project
Revenue Bonds for the Station to finance the bonds and the purchase of the
Authority’s share of the Station and related transmission rights. The bonds are not
obligations of any member of the Authority or public agency other than the Authority.
Under a power sales contract with the Authority, the City is obligated on a “take or
pay” basis for its proportionate share of power generated, as well as to make
payments for its proportionate share of the operating and maintenance expenses of
the Station, debt service on the bonds and any other debt, whether or not the project
or any part thereof or its output is suspended, reduced or terminated. The City took
its proportionate share of the power generated and its proportionate share of costs
during the fiscal year 2022 was $3,320,768. The City expects no significant
increases in costs related to its nuclear resources.
Power Purchase Commitments
The Authority has entered into power purchase agreements with project participants.
These agreements are substantially “take-and-pay” contracts where there may be other
obligations not associated with the delivery of energy. The City has entered into power
purchase agreements with the Authority related to the following projects:
Astoria 2 Solar Project
On July 23, 2014, the Authority entered into a power purchase agreement with
Recurrent Energy for solar energy from the Astoria 2 Solar Project. SCPPA is
entitled to 35 MW of photovoltaic generating capacity from commercial operation to
December 31, 2021 and 45 MW of generating capacity from January 1, 2022 until
the expected expiration date of December 31, 2036. The commercial operation date
was December 2016. Power and Water Resources Pooling Authority, Lodi, Corona,
Moreno Valley, and Rancho Cucamonga, are each buying the output of a separate
portion of the facility, which is located in Kern County, California. SCPPA has
purchase options in the 10th, 15th, and 20th Contract Years. The project is
forecasted to start at a capacity factor of 31% with a 0.5% annual degradation. ACES
Power Marketing is the third-party scheduling coordinator for the project. The City
contracted to purchase 57.1429% until December 31, 2021, and 66.6667%
thereafter, of the output. The City’s proportionate share of costs during the current
fiscal year was $2,250,667.
CITY OF VERNON
ELECTRIC FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(46)
NOTE 10 ELECTRIC FUND OPERATIONS AND COMMITMENTS (CONTINUED)
Southern California Public Power Authority (Continued)
Power Purchase Commitments (Continued)
Puente Hills Landfill Gas-to-Energy Project
On June 25, 2014, the Authority entered into a power purchase agreement with
County Sanitation District No. 2 of Los Angeles County for 46 MW of the electric
generation from a landfill gas to energy facility, located at Whittier, California. The
project began deliveries to the Authority on January 1, 2017 for a term of 10 years.
The City contracted to purchase 23.2558% of the output. The City’s proportionate
share of costs during the current fiscal year was $1,007,652.
Antelope DSR 1 Solar Project
On July 16, 2015, the Authority, entered into a power purchase agreement with
Antelope DSR 1, LLC for 50 MW solar photovoltaic generating capacity from the
Antelope DSR 1 Solar Facility. The facility is located near Lancaster, California, and
commercial operation occurred on December 16, 2016 for a term of 20 years. The
City contracted to purchase 50.00% of the output. The City’s proportionate share of
costs during the current fiscal year was $1,192,621.
(47)
REQUIRED SUPPLEMENTARY INFORMATION
CITY OF VERNON
ELECTRIC FUND
SCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION LIABILITY
CITY'S MISCELLANEOUS AND SAFETY COST SHARING PLAN
LAST TEN FISCAL YEARS *
(48)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017
Measurement Date 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017 6/30/2016
City’s Proportion of the
Net Pension Liability 14.17% 12.03% 10.93% 10.61% 10.60% 10.41%
City's Proportionate Share of the
Net Pension Liability 12,461,180$ 16,262,340$ 13,198,355$ 12,037,649$ 11,622,798$ 9,913,819$
City’s Covered Payroll 2,763,712 2,971,068 3,153,590 3,119,774 2,844,009 1,368,926
City’s Proportionate Share of the
Net Pension Liability as a
Percentage of City's Covered Payroll 450.89% 547.36% 418.52% 385.85% 408.68% 724.20%
Plan Fiduciary Net Position as a
Percentage of the Plan's Total
Pension Liability 85.45% 74.79% 76.15% 77.68% 77.85% 78.91%
Notes to Schedule:
Benefit Changes:
There were no changes in benefits.
Changes in Assumptions:
From fiscal year June 30, 2017 to June 30, 2018:
The discount rate was reduced from 7.65% to 7.15%.
From fiscal year June 30, 2018 to June 30, 2019:
There were no significant changes in assumptions.
From fiscal year June 30, 2019 to June 30, 2020:
There were no significant changes in assumptions.
From fiscal year June 30, 2020 to June 30, 2021:
The inflation rate was increased from 2.5% to 2.625%
The payroll growth rate was reduced from 3.00% to 2.875%.
From fiscal year June 30, 2021 to June 30, 2022:
The inflation rate was decreased from 2.625% to 2.5%
The payroll growth rate was reduced from 2.875% to 2.75%.
The investment rate of return was decreased from 7.15% to 7.00%.
* Fiscal year 2017 was the first year the City allocated a portion of the net pension liability to the Electric Fund, therefore only six years are shown.
CITY OF VERNON
ELECTRIC FUND
SCHEDULE OF PLAN CONTRIBUTIONS
CITY'S MISCELLANEOUS AND SAFETY COST SHARING PLAN
LAST TEN FISCAL YEARS *
(49)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017
Actuarially Determined
Contributions 2,012,496$ 1,518,109$ 1,347,573$ 1,158,143$ 1,005,691$ 947,914$
Contributions in relation to the
Actuarially Determined
Contributions (2,012,496) (1,518,109) (1,347,573) (1,158,143) (1,005,691) (947,914)
Contribution :
Deficiency (Excess)-$ -$ -$ -$ -$ -$
Covered Payroll 3,589,490$ 2,763,712$ 2,971,068$ 3,153,590$ 3,119,774$ 2,844,009$
Contributions as a Percentage
of Covered Payroll 56.07% 54.93% 45.36% 36.72% 32.24% 33.33%
Notes to Schedule:
Valuation Date 6/30/2019 6/30/2018 6/30/2017 6/30/2016 6/30/2015 6/30/2014
Methods and Assumptions Used to
Determine Contribution Rates:
Actuarial Cost Method Entry AgeEntry AgeEntry AgeEntry AgeEntry AgeEntry Age
Amortization Method (1)(1)(1)(1)(1)(1)
Asset Valuation Method Fair Value Fair Value Fair Value Fair Value Fair Value Fair Value
Inflation 2.625% 2.625% 2.625% 2.75% 2.75% 2.75%
Salary Increases (2)(2)(2)(2)(2)(2)
Investment Rate of Return 7.00% (3)7.25% (3)7.25% (3)7.375% (3)7.50% (3)7.50% (3)
Mortality (4)(4)(4)(4)(4)(4)
(1)Level percentage of payroll, closed
(2)Depending on age, service, and type of employment
(3)Net of pension plan investment expense, including inflation
(4)Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study
adopted by the CalPERS Board.
* Fiscal year 2017 was the first year the City allocated a portion of the net pension liability to the Electric Fund, therefore only six years are
shown.
CITY OF VERNON
ELECTRIC FUND
SCHEDULE OF PROPORTIONATE SHARE OF THE NET OPEB LIABILITY
LAST TEN FISCAL YEARS *
(50)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018
Measurement Date 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017
Plan’s Proportion of the
Net OPEB Liability 14.16% 12.02% 10.93% 10.61% 6.43%
Plan’s Proportionate Share of the
Net OPEB Liability 2,317,770$ 2,429,343$ 2,394,613$ 2,449,998$ 2,333,037$
Plan’s Covered-Employee Payroll 3,810,495 3,491,517 3,731,469 2,152,941 2,153,877
Plan’s Proportionate Share of the
Net OPEB Liability as a Percentage
of Covered-Employee Payroll 60.83% 69.58% 64.17% 113.80% 108.32%
Plan Fiduciary Net Position as a
Percentage of the Total OPEB Liability 40.22% 25.73% 16.30% 8.62% 2.83%
Notes to Schedule:
Changes in Assumptions:
* Fiscal year 2018 was the first year of implementation, therefore only five years are shown.
The discount rate was changed from 2.85% to 3.58% for the measurement period ended June 30, 2017. The discount rate
for the measurement periods ended June 30, 2018 and 2019 was 6.50%. The discount rate for the measurement period
ended June 30, 2020 was reduced to 6.25%.
The mortality, retirement, disability, and termination rates for the measurement periods ended June 30, 2017 and 2018
were based on the CalPERS 1997-2011 Experience Study and CalPERS 1997-2015 Experience Study, respectively.
The mortality improvement rates for the measurement periods ended June 30, 2017 and 2018 were based on the Scale
MP-2016 and Scale-2018, respectively.
In the June 30, 2018 measurement period, the pre-65 waived retiree re-election was updated to be 10% after
age 65.
CITY OF VERNON
ELECTRIC FUND
SCHEDULE OF OPEB CONTRIBUTIONS
LAST TEN FISCAL YEARS *
(51)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018
Actuarially Determined
Contribution 217,810$ 184,942$ 211,038$ 285,605$ 173,080$
Contributions in relation to the
Actuarially Determined
Contribution (415,223) (376,391) (427,758) (317,055) (132,751)
Contribution:
Deficiency (Excess)(197,413)$ (191,449)$ (216,720)$ (31,449)$ 40,329$
Covered Payroll 4,487,701$ 3,810,495$ 3,491,517$ 3,731,469$ 2,152,941$
Contributions as a Percentage
of Covered Payroll 4.85% 4.85% 6.04% 7.65% 8.04%
Notes to Schedule:
Valuation Date 6/30/2019 6/30/2018 6/30/2017 6/30/2016 6/30/2015
Methods and Assumptions Used to
Determine Contribution Rates:
Actuarial Cost Method Entry AgeEntry AgeEntry AgeEntry AgeEntry Age
Amortization Method (1)(1)(1)(1)(1)
Amortization Period 28 years 28 years 27 years 27 years 29 years
Asset Valuation Method Market Value Market Value Market Value Market Value Market Value
Inflation 2.25% 2.25% 2.50% 2.50% 2.75%
Healthcare Trend Rates (7)(6)(3)(3)(2)
Investment Rate of Return 6.25% 6.25% 6.50% 7.00% 7.00%
Mortality (5)(5)(5)(5)(4)
(1)Level percentage of payroll, closed.
(2)8.50% trending down to 5.00%.
(3)6.90% trending down to 4.00%.
(4)CalPERS December 2014 experience study
(5) CalPERS December 2017 experience study
(6)6.70% trending down to 3.80%.
(7)6.30% trending down to 3.80%.
* Fiscal year 2018 was the first year of implementation, therefore five years year are shown.
CITY OF VERNON
WATER FUND
(AN ENTERPRISE FUND OF THE
CITY OF VERNON)
FINANCIAL STATEMENTS AND
SUPPLEMENTARY INFORMATION
YEAR ENDED JUNE 30, 2022
CITY OF VERNON
WATER FUND
TABLE OF CONTENTS
YEAR ENDED JUNE 30, 2022
INTRODUCTORY SECTION
A MESSAGE FROM THE GENERAL MANAGER OF VERNON PUBLIC
UTILITIES i
FINANCIAL SECTION
INDEPENDENT AUDITORS’ REPORT 1
MANAGEMENTS’ DISCUSSION AND ANALYSIS (REQUIRED
SUPPLEMENTARY INFORMATION – UNAUDITED) 4
BASIC FINANCIAL STATEMENTS
STATEMENT OF NET POSITION 9
STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN NET
POSITION 11
STATEMENT OF CASH FLOWS 12
NOTES TO BASIC FINANCIAL STATEMENTS 13
REQUIRED SUPPLEMENTARY INFORMATION
SCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION
LIABILITY – CITY’S MISCELLANEOUS AND SAFETY COST SHARING
PLAN 37
SCHEDULE OF PLAN CONTRIBUTIONS – CITY’S MISCELLANEOUS AND
SAFETY COST SHARING PLAN 38
SCHEDULE OF PROPORTIONATE SHARE OF THE NET OPEB LIABILITY 39
SCHEDULE OF OPEB CONTRIBUTIONS 40
INTRODUCTORY SECTION
Vernon Public Utilities
4305 Santa Fe Avenue, Vernon, CA, 90058
323.583.8811 | CityofVernon.org
Message from the General Manager
As an essential resource to all customers, our job is to provide dependable,
high-quality electric, water, natural gas, and fiber optic services at cost -
effective rates with the highest standards for reliability. We ensure that
electricity will stay on when needed, customers have safe, clean drinking
water, there is a reliable supply of natural gas to meet demand, and our fiber
services offer competitive rates and the latest technology. Our mission focuses
on reliably providing the lowest electric rates in California by 2030.
As a municipally owned utility, every customer is a stakeholder in Vernon Public
Utilities (VPU). VPU enjoys the continued support of the City Council, which has
approved key strategic initiatives for sustained success. These initiatives
include Renewable Energy Projects, such as the Daggett Solar Project
(operational in September 2023) and the Sapphire Solar and Storage Facility Project (operational in
December 2025). With Council support, along with City Administration, VPU remains focused on providing
our customers with reliable services and competitive rates.
Despite the recent supply chain issues and higher costs for energy, materials, and supplies, which are
critical to our operations, VPU is committed to maintaining a strong financial and operational position for
the future. Our strategy focuses on the following initiatives for financial and operational flexibility :
1.Electric load growth with a diversified customer base which includes green commerce.
2.A diversified Energy Resource portfolio, which includes meeting California’s Renewable Portfolio
Standard Targets as outlined in SB100. Specifically, (i) 2027 - 52%, (ii) 2030 - 60%, and (iii) 2045 - 100%
Carbon Neutral. VPU is in the process of updating its Integrated Resource Plan, which focuses on
providing direction for reliability, affordability, and meeting renewable energy requirements.
3.Optimizing the operating profile for the Malburg Generating Station (MGS) for operational savings
and continued coordination with the CAISO to prevent statewide rolling blackouts and requests to
run MGS when energy is needed most across the electric grid.
4.Continued strategic capital investment in electric, water, natural gas, and fiber optic infrastructure to
support high-quality and reliable services. VPU continues to be one of the most reliable electric
systems compared to other utilities. VPU is a three-time recipient of the RP3 Diamond Level Award, the
highest reliability award from APPA, which reflects our continued investment in utility infrastructure and
commitment to safety and workforce development.
5.A focus on the utility’s financial strength, including improving key financial metrics used by the rating
agencies such as Moody’s and S&P Global Ratings, including the implementation of a Utility Financial
Reserves Policy, and keeping rates competitive to ensure businesses can grow in Vernon.
As we enter 2023, I am optimistic about the future. VPU is focused on providing reliable and competitive
electric, water, natural gas, and fiber optic services. In that pursuit, we will excel today and in the future.
Sincerely,
Todd Dusenberry
General Manager
FINANCIAL SECTION
(1)
INDEPENDENT AUDITORS’ REPORT
Honorable Mayor and the Members of the City Council
City of Vernon, California
Report on the Financial Statements
Opinion
We have audited the accompanying financial statements of the Water Fund of the City of Vernon,
(Water Fund), an enterprise fund of the City of Vernon, California (City), which comprise the statement
of net position as of June 30, 2022, and the related statements of revenues, expenses, and changes in
net position, and cash flows for the year then ended, and the related notes to the financial statements,
which collectively comprise the Water Fund’s basic financial statements as listed in the table of
contents.
In our opinion, the financial statements referred to above present fairly, in all material respects, the
financial position of the Water Fund as of June 30, 2022, and the changes in its financial position and
its cash flows for the year then ended in accordance with accounting principles generally accepted in
the United States of America.
Basis for Opinion
We conducted our audit in accordance with auditing standards generally accepted in the United States
of America (GAAS) and the standards applicable to financial audits contained in Government Auditing
Standards, issued by the Comptroller General of the United States. Our responsibilities under those
standards are further described in the Auditors’ Responsibilities for the Audit of the Financial
Statements section of our report. We are required to be independent of the City’s Water and to meet
our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our
audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a
basis for our audit opinion.
Emphasis of Matter
As discussed in Note 1 to the financial statements, the financial statements present only the City’s
Water Fund and do not purport to, and do not, present fairly the financial position of the City of Vernon,
California as of June 30, 2022, and the changes in its financial position and its cash flows for the year
then ended in accordance with accounting principles generally accepted in the United States of
America. Our opinion is not modified with respect to this matter.
CLA (CliftonLarsonAllen LLP) is an independent network member of CLA Global. See CLAglobal.com/disclaimer.
CliftonLarsonAllen LLP
CLAconnect.com
Honorable Mayor and the Members of the City Council
City of Vernon, California
(2)
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in
accordance with accounting principles generally accepted in the United States of America; this includes
the design, implementation, and maintenance of internal control relevant to the preparation and fair
presentation of financial statements that are free from material misstatement, whether due to fraud or
error.
Auditors’ Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole
are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that
includes our opinions. Reasonable assurance is a high level of assurance but is not absolute assurance
and therefore is not a guarantee that an audit conducted in accordance with GAAS and Government
Auditing Standards will always detect a material misstatement when it exists. The risk of not detecting a
material misstatement resulting from fraud is higher than for one resulting from error, as fraud may
involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
Misstatements are considered material if there is a substantial likelihood that, individually or in the
aggregate, they would influence the judgment made by a reasonable user based on the financial
statements.
In performing an audit in accordance with GAAS and Government Auditing Standards, we:
Exercise professional judgment and maintain professional skepticism throughout the audit.
Identify and assess the risks of material misstatement of the financial statements, whether due
to fraud or error, and design and perform audit procedures responsive to those risks. Such
procedures include examining, on a test basis, evidence regarding the amounts and disclosures
in the financial statements.
Obtain an understanding of internal control relevant to the audit in order to design audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Water Fund’s internal control. Accordingly, no such opinion is
expressed.
Evaluate the appropriateness of accounting policies used and the reasonableness of significant
accounting estimates made by management, as well as evaluate the overall presentation of the
financial statements.
We are required to communicate with those charged with governance regarding, among other matters,
the planned scope and timing of the audit, significant audit findings, and certain internal control related
matters that we identified during the audit.
Honorable Mayor and the Members of the City Council
City of Vernon, California
(3)
Required Supplementary Information
Accounting principles generally accepted in the United States of America require that the
management’s discussion and analysis, schedule of proportionate share of the net pension liability,
schedule of plan contributions, schedule of proportionate share of the net OPEB liability, and schedule
of OPEB contributions, identified as required supplementary information (RSI) in the accompanying
table of contents, be presented to supplement the basic financial statements. Such information,
although not a part of the basic financial statements, is required by the Governmental Accounting
Standards Board who considers it to be an essential part of financial reporting for placing the basic
financial statements in an appropriate operational, economic, or historical context. We have applied
certain limited procedures to the required supplementary information in accordance with auditing
standards generally accepted in the United States of America, which consisted of inquiries of
management about the methods of preparing the information and comparing the information for
consistency with management’s responses to our inquiries, the basic financial statements, and other
knowledge we obtained during our audit of the basic financial statements. We do not express an
opinion or provide any assurance on the information because the limited procedures do not provide us
with sufficient evidence to express an opinion or provide any assurance.
Other Information
Management is responsible for the other information included in the annual report. The other
information comprises the introductory section but does not include the basic financial statements and
our auditors’ report thereon. Our opinion on the basic financial statements does not cover the other
information, and we do not express an opinion or any form of assurance thereon.
In connection with our audit of the basic financial statements, our responsibility is to read the other
information and consider whether a material inconsistency exists between the other information and the
basic financial statements, or the other information otherwise appears to be materially misstated. If,
based on the work performed, we conclude that an uncorrected material misstatement of the other
information exists, we are required to describe it in our report.
Other Reporting Required by Government Auditing Standards
In accordance with Government Auditing Standards, we have also issued our report dated August 8,
2023, on our consideration of the Water Fund’s internal control over the financial reporting and on our
tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and
other matters. The purpose of that report is solely to describe the scope of our testing of internal control
over financial reporting and compliance and the results of that testing, and not to provide an opinion on
the effectiveness of the Water Fund’s internal control over financial reporting or on compliance. That
report is an integral part of an audit performed in accordance with Government Auditing Standards in
considering the Water Fund’s internal control over financial reporting and compliance.
CliftonLarsonAllen LLP
Irvine, California
August 8, 2023
CITY OF VERNON
WATER FUND
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(4)
The management of the Water Fund of the City of Vernon (“the City”) offers the following overview and
analysis of the basic financial statements of the Water Fund for the fiscal year ended June 30, 2022.
Management encourages readers to utilize information in the Management’s Discussion and Analysis
(MD&A) in conjunction with the accompanying basic financial statements.
OVERVIEW OF BASIC FINANCIAL STATEMENTS
The MD&A is intended to serve as an introduction to the Water Fund’s basic financial statements.
Included as part of the financial statements are three separate statements.
The statement of net position presents information on the Water Fund’s total assets and deferred
outflows of resources and total liabilities and deferred inflows of resources, with the difference between
the two reported as net position.
The statement of revenues, expenses and changes in net position presents information showing how
the Water Fund's net position changed during the most recent fiscal year. Financial results are
recorded using the accrual basis of accounting. Under this method, all changes in net position are
reported as soon as the underlying events occur, regardless of the timing of cash flows. Thus, revenues
and expenses reported in this statement for some items may affect cash flows in a future fiscal period
(examples include billed but uncollected revenues and employee earned but unused vacation leave).
The statement of cash flows reports cash receipts, cash payments, and net changes in cash and cash
equivalents from operations, noncapital financing, capital and related financing, and investing activities.
The notes to the financial statements provide additional information that is essential to fully understand
the data provided in the financial statements.
CITY OF VERNON
WATER FUND
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(5)
FINANCIAL HIGHLIGHTS
Fund Net Position
The table below summarizes the Water Fund’s net position as of the current fiscal year ended June
30, 2022 and prior fiscal year ended June 30, 2021. The details of the current year’s summary can
be found on pages 9 and 10 of this report.
City of Vernon
Water Fund
Fund Net Position
June 30, 2022 and 2021
The assets and deferred outflows of resources of the Water Fund exceeded its liabilities and
deferred inflows of resources at the close of the most recent fiscal year by $20,753,779 (net
position).
The category of the Water Fund’s net position with the largest balance totaling $13,884,392
represents the unrestricted net position that is expected to be used for future projects or other
purposes.
The remaining category of net position, totaling $6,869,387, represents resources that are invested
in capital assets, net of related debt.
CITY OF VERNON
WATER FUND
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(6)
Fund Net Position (Continued):
Current assets increased by $3.2 million from the prior year due to increases in cash by $2.8
million, accounts receivable by $164 thousand, and accrued unbilled revenue by $254
thousand.
Restricted assets decreased by $3.9 million in 2022 as we drew down on the Water System
Revenue Bonds 2020 Taxable Series A to fund capital projects.
Capital assets increased $3.1 million from the prior year due to additional water plant
construction totaling $3.1 million, net of depreciation of $410 thousand (See Note 5).
Current liabilities decreased by $663 thousand from the prior year primarily due to decreases
accrued wages and benefits by $68 thousand and in the amount due to other city funds
balance by $593 thousand.
Long-term liabilities decreased by $2.4 million from the prior year due to decreases in bonds
payable by $269 thousand, in the note payable by $140 thousand, and net other
postemployment benefit liability of $168 thousand, and net pension liability of $1.8 million.
The net investments in capital assets, net of related debt decreased by $434 thousand while
the unrestricted net position increased by $2.3 million causing an increase in the total net
position of $1.8 million.
CITY OF VERNON
WATER FUND
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(7)
Changes in Fund Net Position
The table below summarizes the Water Fund’s changes in net position over the current and prior
fiscal years. The details of the current year’s changes in net position can be found on page 11 of
this report.
City of Vernon
Water Fund
Changes in Fund Net Position
June 30, 2022 and 2021
The Water Fund’s FY 2021-22 operating income of $2.6 million offset by net non-operating revenues
(expenses) of $(767) thousand resulted in a net position of $1.8 million. The key reasons for this
change are due to a water rate adjustment effective January 2022, management and control of
operating expenses, and higher net non-operating revenues(expenses) by $200 thousand.
CITY OF VERNON
WATER FUND
MANAGEMENT'S DISCUSSION AND ANALYSIS
JUNE 30, 2022
(8)
CAPITAL ASSETS
The Water Fund’s investment in capital assets as of June 30, 2022 amounted to $16.3 million (net of
accumulated depreciation). This investment in capital assets includes land, construction in progress,
and utility system improvements.
Additional information on the Water Fund's capital assets can be found in Note 5 of this report.
OUTSTANDING DEBT
As of June 30, 2022, the following debt remains outstanding:
$14,600,000 City of Vernon Water System Revenue Bonds, 2020 Taxable Series A
$1,220,930 City of Vernon agreement with Water Replenishment District of Southern
California
The City of Vernon Water System Revenue Bonds, 2020 Series A were issued to provide funds to(i)
finance the acquisition and construction of certain capital improvements to the Water System of the
City, (ii) purchase a municipal bond debt service reserve insurance policy for deposit in the Reserve
Fund in satisfaction of the Reserve Requirement, and (iii) to pay costs of issuance of the 2020 Bonds.
As of June 30, 2022, the rating on the Water System Revenue Bonds is A-/Stable by S&P.
Additional information on the Water Fund's long-term debt can be found in Note 6 of this report.
ECONOMIC FACTORS AND NEW YEAR’S BUDGET AND RATES
These factors were considered in preparing the Water Fund’s FY 2022-23 operating and capital
budgets.
VPU is committed to providing dependable, high-quality electric, water, natural gas, and fiber
services at the lowest competitive rates and the highest standards for reliability.
VPU continues to respond to inflation and supply chain issues, including higher chemical and
construction costs, to maintain infrastructure investment to continue to provide exceptionally
reliable service.
Continue to implement the multi-year water rate adjustment plan approved by City Council as
well as manage and control operating expenses.
REQUESTS FOR INFORMATION
This report is designed to provide an overview of the Water Fund's FY 2021-22 results. Questions
concerning the fund’s financial or operating results can be addressed to Scott Williams, Director of
Finance, swilliams@cityofvernon.org, City of Vernon, 4305 Santa Fe Avenue, Vernon, California,
90058.
CITY OF VERNON
WATER FUND
STATEMENT OF NET POSITION
JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(9)
ASSETS
Current Assets:
Cash and Cash Equivalents 17,015,777$
Accounts Receivable, Net of Allowance of $53,364 1,141,938
Accrued Unbilled Revenue 1,373,195
Accrued Interest Receivable 4,448
Total Current Assets 19,535,358
Noncurrent Assets:
Restricted Cash and Cash Equivalents 7,358,059
Advances to Other City Funds 202,798
Capital Assets:
Nondepreciable 7,381,939
Depreciable, Net 8,886,072
Total Noncurrent Assets 23,828,868
Total Assets 43,364,226
DEFERRED OUTFLOWS OF RESOURCES
Deferred Outflows Related to Pensions 917,279
Deferred Outflows Related to OPEB Liability 113,765
Total Deferred Outflows of Resources 1,031,044
CITY OF VERNON
WATER FUND
STATEMENT OF NET POSITION (CONTINUED)
JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(10)
LIABILITIES
Current Liabilities:
Accounts Payable 1,415,262$
Accrued Wages and Benefits 44,295
Customer Deposits 61,184
Bond Interest Payable 242,490
Bonds Payable 250,000
Note Payable 139,535
Compensated Absences 28,069
Total Current Liabilities 2,180,835
Noncurrent Liabilities:
Bonds Payable 14,885,833
Note Payable 1,081,395
Compensated Absences 56,139
Net Other Postemployment Benefit Liability 529,343
Net Pension Liability 2,845,943
Total Noncurrent Liabilities 19,398,653
Total Liabilities 21,579,488
DEFERRED INFLOWS OF RESOURCES
Deferred Inflows Related to Pensions 1,790,896
Deferred Inflows Related to OPEB Liability 271,107
Total Deferred Inflows of Resources 2,062,003
NET POSITION
Net Investment in Capital Assets 6,869,387
Unrestricted 13,884,392
Total Net Position 20,753,779$
CITY OF VERNON
WATER FUND
STATEMENT OF REVENUES, EXPENSES, AND CHANGES IN NET POSITION
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(11)
OPERATING REVENUES
Charges for Services 10,845,652$
Total Operating Revenue 10,845,652
OPERATING EXPENSES
Cost of Sales 7,743,964
Depreciation 500,102
Total Operating Expenses 8,244,066
OPERATING INCOME 2,601,586
NONOPERATING REVENUES (EXPENSES)
Intergovernmental 194,487
Investment Income 11,991
Interest Expense (563,895)
Loss on Disposition of Assets (409,841)
Total Nonoperating Revenues (Expenses)(767,258)
CHANGE IN NET POSITION 1,834,328
Net Position - Beginning Of Year 18,919,451
NET POSITION - END OF YEAR 20,753,779$
CITY OF VERNON
WATER FUND
STATEMENT OF CASH FLOWS
YEAR ENDED JUNE 30, 2022
See accompanying Notes to Basic Financial Statements.
(12)
CASH FLOWS FROM OPERATING ACTIVITIES
Cash Received from Customers 10,427,677$
Cash Paid to Suppliers for Goods and Services (6,851,398)
Cash Paid to Employees for Services (1,818,089)
Net Cash Provided by Operating Activities 1,758,190
CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES
Payment of Bond Payable (240,000)
Bond Interest Paid (587,975)
Payment of Note Payable (139,535)
Net Acquisition of Capital Assets (4,033,299)
Net Cash Used by Capital and Related Financing Activities (5,000,809)
CASH FLOWS FROM NONCAPITAL FINANCING ACTIVITIES
Grant Revenue Received 194,487
Payment from (Provided to) Other City Funds 1,915,195
Net Cash Provided by Noncapital Financing Activities 2,109,682
CASH FLOWS FROM INVESTING ACTIVITIES
Investment Income 7,583
Net Cash Provided by Investing Activities 7,583
CHANGE IN CASH AND CASH EQUIVALENTS (1,125,354)
Cash and Cash Equivalents - Beginning of Year 25,499,190
CASH AND CASH EQUIVALENTS - END OF YEAR 24,373,836$
COMPOSITION OF CASH AND CASH EQUIVALENTS
Cash and Cash Equivalents 17,015,777$
Restricted Cash and Investments 7,358,059
Total 24,373,836$
RECONCILIATION OF OPERATING INCOME TO NET CASH
PROVIDED BY OPERATING ACTIVITIES
Operating Income 2,601,586$
Adjustments to Reconcile Operating Income
to Net Cash Provided by Operating Activities:
Depreciation 500,102
Change in Operating Assets and Liabilities:
Accounts Receivable (164,414)
Accrued Unbilled Revenue (254,361)
Deferred Outflows of Resources 102,727
Accounts Payable (1,292)
Accrued Wages and Benefits (67,916)
Due to Other Funds (593,486)
Customer Deposits 800
Compensated Absences (18,983)
Other Postemployment Benefit Liability (167,986)
Net Pension Liability (1,822,068)
Deferred Inflows of Resources 1,643,481
Net Cash Provided by Operating Activities 1,758,190$
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(13)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying financial statements present only the Water Enterprise Fund (the Water
Fund) of the City of Vernon, California (the City), and do not present fairly the financial
position and results of the operations of the City. The Water Fund accounts for the
independent operations and the maintenance of the City’s Water utility. The Water Fund is
administered as an independent fiscal and accounting entity with a self-balancing set of
accounts recording resources, related liabilities, obligations, reserves, and equities,
segregated for the purpose of carrying out specific activities or attaining certain objectives in
accordance with special regulations, restrictions or limitations.
For additional information regarding the City of Vernon, refer to the City’s annual financial
report.
The financial statements of the Water Fund have been prepared in conformity with the U.S.
generally accepted accounting principles (U.S. GAAP). The Governmental Accounting
Standards Board (GASB) is the accepted standard-setting body for establishing
governmental accounting and financial reporting principles. The Water Fund’s significant
accounting policies are described below.
A. Basis of Presentation
The Water Fund’s financial statements are reported using the economic resources
measurement focus and the accrual basis of accounting. Revenues are recorded when
earned and expenses are recorded at the time liabilities are incurred, regardless of when
the related cash flows take place.
The Water Fund distinguishes operating revenues and expenses from nonoperating
items. Operating revenues, such as charges for services, result from exchange
transactions associated with the sale of Water. Exchange transactions are those in
which each party receives and gives up essentially equal values. Nonoperating
revenues, such as subsidies and investment earnings, result from nonexchange
transactions or ancillary activities. Operating expenses include the cost of sales and
services, administrative expenses and depreciation on capital assets. All expenses not
meeting this definition are reported as nonoperating expenses.
B. Pooled Cash
Part of the Water Fund’s operating cash balance is pooled with various other City funds
for deposit purposes. The share of each fund in the pooled cash account is recorded in
each of the fund’s books of accounts, and interest income is apportioned to the
participating funds based on the relationship of their average monthly balances to the
total of the pooled cash.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(14)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
C. Cash Deposits and Investments
For purposes of the statement of cash flows, the Water Fund considers all highly liquid
investments (including restricted cash and investments) with an original maturity of three
months or less when purchased to be cash equivalents. Investment transactions are
recorded on the settlement date. Investments in nonparticipating interest-earning
investment contracts are reported at cost and all other investments are reported at fair
value. Fair value is defined as the amount that the Water Fund could reasonably expect
to receive for an investment in a current sale between a willing buyer and a seller and is
generally measured by quoted market prices.
D. Receivables/Payables
Short-term City interfund receivables and payables are classified as “due from other City
funds” and “due to other City funds”, respectively, on the statement of net position. Long-
term City interfund receivables and payables are classified as “advances to/from other
City funds,” respectively, on the statement of net position.
Trade receivables are shown net of an allowance for uncollectible accounts. Allowances
for uncollectible accounts were $53,364 as of June 30, 2022. The Water Fund’s
customers are billed monthly. The estimated value of services provided, but unbilled at
year-end has been included in the accompanying financial statements.
E. Capital Assets
Capital assets (including infrastructure) are recorded at historical cost or at estimated
historical cost if the actual historical cost is not available. Contributed capital assets are
recorded at their estimated acquisition value at the date contributed. Capital assets
include land, construction in progress, and plant assets including building,
improvements, and machinery and equipment. The capitalization threshold for all capital
assets is $5,000. Capital assets used in operations are depreciated using the straight-
line method over their estimated useful lives.
The estimated useful lives are as follows:
Utility Plant 3 to 50 Years
Maintenance and repairs are charged to operations when incurred. Betterments and
major improvements, which significantly increase values, change capacities or extend
useful lives, are capitalized. Upon sale or retirement of capital assets, the cost and
related accumulated depreciation are removed from the respective accounts and any
resulting gain or loss is included in the statement of revenues, expenses, and changes in
net position.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(15)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
F. Compensated Absences
Accumulated vacation is accrued when incurred. Upon termination of employment, the
Water Fund will pay the employee all accumulated vacation leave at 100% of the
employee’s base hourly rate.
G.Deferred Outflows and Inflows of Resources
The Water Fund recognizes deferred outflows and inflows of resources. A deferred
outflow of resource is defined as a consumption of net position by the Water Fund that is
applicable to a future reporting period. A deferred inflow of resources is defined as an
acquisition of net position by the Water Fund that is applicable to a future reporting
period. On June 30, 2022, the Water Fund has deferred outflows of resources
representing deferred amounts on pension-related transactions and postemployment
benefit-related transactions and deferred inflows of resources representing pension-
related transactions and postemployment benefit-related transactions.
H. Long-Term Obligations
Bond discounts and premiums are amortized over the life of the bonds using the
straight-line method.
I. Net Position
The Water Fund financial statements utilize a net position presentation. Net position is
categorized as invested in capital assets (net of related debt), restricted, and
unrestricted.
Net Investment in Capital Assets – This category groups all capital assets into
one component of net position. Accumulated depreciation and the outstanding
balances of liabilities that are attributable to the acquisition, construction or
improvement of these assets reduce the balance in this category.
Restricted Net Position – This category presents external restrictions imposed
by creditors, grantors, contributors or laws or regulations of other governments
and restrictions imposed by law through constitutional provisions or enabling
legislation. The Water Fund does not have any restricted net position.
Unrestricted Net Invested in Capital Assets or Position – This category
represents the net position of the Water Fund not restricted for any project or
other purposes.
The Water Fund’s policy regarding whether to first apply restricted or unrestricted
resources when an expense is incurred for purposes for which both restricted and
unrestricted net position are available is to use restricted resources first.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(16)
NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
J. Use of Estimates
The preparation of the basic financial statements in conformity with U.S. GAAP requires
management to make estimates and assumptions that affect certain reported amounts
and disclosures. Accordingly, actual results could differ from those estimates.
K. Pensions
For purposes of measuring the net pension liability and deferred outflows/inflows of
resources related to pensions and pension expense, information about the fiduciary net
position of the City’s California Public Employees’ Retirement System (CalPERS) plan
and additions to/deductions from the Pension Plans’ fiduciary net position have been
determined on the same basis as they are reported by CalPERS. For this purpose,
benefit payments (including refunds of employee contributions) are recognized when
due and payable in accordance with the benefit terms. Investments are reported at fair
value.
L. Other Postemployment Benefits Other than Pensions (OPEB)
For purposes of measuring the net OPEB liability, deferred outflows of resources and
deferred inflows of resources related to OPEB, and OPEB expense information about
the fiduciary net position of the City’s OPEB Plan and additions to/deductions from the
Plan’s fiduciary net position have been determined on the same basis as they are
reported by the Plan. For this purpose, the Plan recognizes benefit payments when due
and payable in accordance with the benefit terms. Investments are reported at fair value.
NOTE 2 CASH AND CASH EQUIVALENTS
Cash and cash equivalents as of June 30, 2022, are classified in the accompanying
statement of net position as follows:
Cash and Cash Equivalents 17,015,777$
Restricted Cash and Cash Equivalents 7,358,059
Total Cash and Cash Equivalents 24,373,836$
Cash and cash equivalents as of June 30, 2022 consist of the following:
Equity in the City's Pooled Cash 10,972,364$
Deposits with Financial Institutions 6,043,413
Money Market Mutual Funds 7,358,059
Total Cash and Cash Equivalents 24,373,836$
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(17)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Equity in the Cash Pool of the City of Vernon
The Water Fund has equity in the cash pool managed by the City. The Water Fund is a
voluntary participant in that pool and the pool is governed by and under the regulatory
oversight of the Investment Policy adopted by the City Council of the City. The Water Fund
has not adopted an investment policy separate from that of the City. The amount of the
Water Fund’s cash in this pool is reported in the accompanying financial statements based
upon the Water Fund’s pro rata share of the amount calculated by the City. The balance
available for withdrawal is based on the accounting records maintained by the City.
The City’s Investment Policy
The City’s Investment Policy sets forth the investment guidelines for all funds of the City.
The Investment Policy conforms to the California Government Code Section 53600 et. seq.
The authority to manage the City’s investment program is derived from the City Council.
Pursuant to Section 53607 of the California Government Code, the City Council annually,
appoints the City Treasurer to manage the City’s investment program and approves the
City’s investment policy. The Treasurer is authorized to delegate this authority as deemed
appropriate. No person may engage in investment transactions except as provided under
the terms of the Investment Policy and the procedures established by the Treasurer.
This Investment Policy requires that the investments be made with the prudent person
standard, that is, when investing, reinvesting, purchasing, acquiring, exchanging, selling or
managing public funds, the trustee (Treasurer and staff) will act with care, skill, prudence,
and diligence under the circumstances then prevailing, including but not limited to, the
general economic conditions and the anticipated needs of the City.
The Investment Policy also requires that when following the investing actions cited above,
the primary objective of the trustee be to safeguard the principal, secondarily meet the
liquidity needs of depositors, and then achieve a return on the funds under the trustee’s
control. Further, the intent of the Investment Policy is to minimize the risk of loss on the
City’s held investments from:
A. Credit Risk
B. Custodial Credit Risk
C. Concentration of Credit Risk
D. Interest Rate Risk
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(18)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Investments Authorized by the California Government Code and the City’s Investment
Policy
The table below identifies the investment types that are authorized for the City by the
California Government Code and the City’s Investment Policy. The table also identifies
certain provisions of the California Government Code that address interest rate risk, credit
risk, and concentration of credit risk. This table does not address investment of debt
proceeds held by the bond trustee that are governed by the provisions of debt agreements
of the City, rather than the general provisions of the California Government Code or the
City’s Investment Policy.
Maximum Maximum
Authorized Maximum Percentage Investment Minimum
Investment Type Maturity of Portfolio* in One Issuer Rating
U.S. Treasury Bonds 5 Years None None None
State and Local Agency Bonds 5 Years None None None
Securities of the U.S. Government, or
its Agencies 5 Years None None None
Certain Asset-Backed Securities 5 Years 20%None AA
Negotiable Certificates of Deposit 5 Years 30%None None
Bankers' Acceptances 180 Days 40%30%None
Commercial Paper 270 Days 25%10%P-1
Repurchase Agreements 1 year None None None
Reverse Repurchase Agreements 92 Days 20%None None
Medium-Term Notes 5 Years 30%None A
Mutual Funds Investing in Eligible Securities N/A 20%10%AAA
Money Market Mutual Funds N/A 20%10%AAA
Mortgage Pass-Through Securities 5 Years 20%None AA
State Administered Pool Investment N/A None $75 Million None
* Excluding amounts held by bond trustee that are not subject to California Government Code restrictions.
Investments Authorized by Debt Agreements
Investments of debt proceeds held by bond trustees are governed by provisions of the debt
agreements, rather than the general provisions of the California Government Code or the
City’s Investment Policy. The table below identifies the investment types that are authorized
for investments held by the bond trustee. The table also identifies certain provisions of these
debt agreements that address interest rate risk, credit risk, and concentration of credit risk.
Maximum Maximum
Authorized Maximum Percentage Investment Minimum
Investment Type Maturity of Portfolio in One Issuer Rating
Securities of the U.S. Government, or
its Agencies None None None None
Certain Asset-Backed Securities None None None AA
Certificates of Deposit None None None None
Bankers' Acceptances 1 Year None None None
Commercial Paper None None None P-1
Money Market Mutual Funds N/A None None AAA
State Administered Pool Investment N/A None $75 Million None
Investment Contracts None None None None
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(19)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Disclosure Relating to Interest Rate Risk
Interest rate risk is the risk that changes in market interest rates will adversely affect the fair
value of an investment. Generally, the longer the maturity of an investment, the greater the
sensitivity of its fair value to changes in market interest rates. One of the ways that the City
manages its exposure to interest rate risk is by purchasing a combination of shorter-term
and longer-term investments and by timing cash flows from maturities so that a portion of
the portfolio is maturing or coming close to maturity evenly over time as necessary to
provide the cash flow and liquidity needed for operations. The City has no specific limitations
with respect to this metric. Information about the sensitivity of the fair values of the Water
Fund’s investments (including investments held by bond trustee) to market interest rate
fluctuations is provided in the following table that shows the distribution of the Water Fund’s
investments by maturity:
Investment Maturities
Fair Value (in Months)
as of Less than 13 to 25 to
Investment Type 6/30/2022 12 Months 24 Months 60 Months
Held by Trustee:
Money Market Mutual Funds 7,358,059$ 7,358,059$ -$ -$
Disclosures Relating to Credit Risk
Generally, credit risk is the risk that an issuer of an investment will not fulfill its obligation to
the holder of the investment. This is measured by the assignment of a rating by a nationally
recognized statistical rating organization. Presented below is the minimum rating required by
the California Government Code, the City’s Investment Policy, or debt agreements, and the
actual rating as of the year-end for each investment type.
Minimum Actual Fair Value
Required Credit Rating as of
Investment TypeRatingMoody's / S&P June 30, 2022
Held by Trustee:
Money Market Mutual Funds Aaa / AAA Aaa / AAA 7,358,059$
Concentration of Credit Risk
The City’s Investment Policy places no limit on the amount the City may invest in any one
issuer excluding a 10% limitation on commercial paper, mutual funds, and money market
mutual funds and a 30% limitation on bankers’ acceptances. The City’s Investment Policy
also places no limit on the amount of debt proceeds held by the bond trustee that the trustee
may invest in one issuer that is governed by the provisions of debt agreements of the City,
rather than the general provisions of the California Government Code or the City’s
Investment Policy. As of June 30, 2022, there were no investments held by the Water Fund
that exceeded 5% in any one issuer, excluding money market mutual funds.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(20)
NOTE 2 CASH AND CASH EQUIVALENTS (CONTINUED)
Custodial Credit Risk
Custodial credit risk for deposits is the risk that, in the event of the failure of a depository
financial institution, a government will not be able to recover its deposits or will not be able
to recover collateral securities that are in the possession of an outside party. The custodial
credit risk for investments is the risk that, in the event of the failure of the counterparty to a
transaction, a government will not be able to recover the value of its investment or collateral
securities that are in the possession of another party. The California Government Code and
the City’s Investment Policy do not contain legal or policy requirements that would limit the
exposure to custodial credit risk for deposits or investments. Under the California
Government Code, a financial institution is required to secure deposits, in excess of the
FDIC insurance amount of $250,000, made by state or local governmental units by pledging
government securities held in the form of an undivided collateral pool. The market value of
the pledged securities in the collateral pool must equal at least 110% of the total amount
deposited by the public agencies. California law also allows financial institutions to secure
City deposits by pledging first trust deed mortgage notes having a value of 150% of the
secured public deposits. Such collateral is held by the pledging financial institution’s trust
department or agent in the City’s name.
At June 30, 2022, all of the Water Fund’s deposits were insured or collateralized as required
by Section 53652 of the California Government Code.
Fair Value Measurement
The Water Fund categorizes its fair value measurements within the fair value hierarchy
established by generally accepted accounting principles. The hierarchy is based on the
valuation inputs used to measure the fair value of the asset.
Level 1 inputs are quoted prices for identical assets or liabilities in active markets
that the government can access at the measurement date.
Level 2 inputs are other than quoted prices included in Level 1 that are observable
for an asset or liability, either directly or indirectly.
Level 3 inputs are unobservable inputs for an asset or liability.
The Water Fund’s investments in money market mutual funds is not subject to
categorization in the fair value hierarchy.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(21)
NOTE 3 ACCOUNTS RECEIVABLES
The Water Fund’s accounts receivable at June 30, 2022, are as follows:
Accounts Receivable 1,195,302$
Less: Allowance for Uncollectible Accounts (53,364)
Total Receivables, Net 1,141,938$
NOTE 4 INTRA-ENTITY TRANSACTIONS
Transactions between the Water Fund and the other City funds commonly occur in the
normal course of business for services received or furnished (accounting, management,
engineering, legal services, and capital projects).
Advances to Other City Funds
The following table summarizes the Water Fund’s advances to the other City funds at
June 30, 2022:
Advances to Other City Funds - July 1, 2021 2,117,993$
Advance Repaid by City Funds During the Year (1,915,195)
Advances to Other City Funds - June 30, 2022 202,798$
The advances between the other City funds and the Water Fund does not accrue interest
due to the nature of the City’s operational relationship and capital projects funded by the
Water Fund that benefits the both. On November 6, 2012, the City adopted Resolution
No. 2012-215 extending the repayment term of the advance to the other City funds from
15 months to a period of over 10 years.
The City’s General Fund allocates certain administrative and overhead costs to the Water
Fund which is included as part of the cost of sales. The allocated costs for the year ended
June 30, 2022, were $610,000.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(22)
NOTE 5 CAPITAL ASSETS
Capital asset activities of the Water Fund for the fiscal year ended June 30, 2022, were as
follows:
Balance Balance
June 30, 2021 Additions Deletions Transfers June 30, 2022
Capital Assets, Not Being Depreciated:
Land 467,640$ -$ -$ -$ 467,640$
Construction in Progress 4,635,417 2,366,637 - (87,755) 6,914,299
Total Capital Assets, Not Being
Depreciated 5,103,057 2,366,637 - (87,755) 7,381,939
Capital Assets, Being Depreciated:
Water Utility Plant 23,765,353 1,666,662 (1,789,499) 87,755 23,730,271
Total Capital Assets, Being Depreciated 23,765,353 1,666,662 (1,789,499) 87,755 23,730,271
Less Accumulated Depreciation for:
Water Utility Plant (15,723,755) (500,102) 1,379,658 - (14,844,199)
Total Accumulated Depreciation (15,723,755) (500,102) 1,379,658 - (14,844,199)
Total Capital Assets, Being Depreciated, Net
Water Utility Plant 8,041,598 1,166,560 (409,841) 87,755 8,886,072
Total 8,041,598 1,166,560 (409,841) 87,755 8,886,072
Total Capital Assets, Net 13,144,655$ 3,533,197$ (409,841)$ -$ 16,268,011$
The Water Fund’s total depreciation expense for the year was $500,102.
NOTE 6 LONG-TERM OBLIGATIONS
As of June 30, 2022, outstanding debt obligations consisted of the following:
$14,840,000 Water System Revenue Bonds (2020 Series A)
At June 30, 2022, $14,600,000 remained outstanding. The bonds are special obligation
bonds which are secured by an irrevocable pledge of water revenues payable to
bondholders. The debt service remaining on the bonds is $25,040,038, payable through
fiscal 2051. For the current year, debt service and net water revenues were $827,975 and
$3,194,732, respectively. Under the Indenture of Trust dated May 6, 2020, interest and
principal on the bonds are payable from Net Revenues (or Revenues less Operation and
Maintenance Expenses) and/or amounts in the Water Enterprise (as those terms are
defined in the Indenture of Trust). The City of Vernon Water System Revenue Bonds, 2020
Series A were issued to provide funds to (i) finance the acquisition and construction of
certain capital improvements to the Water System of the City, (ii) purchase a municipal bond
debt service reserve insurance policy for deposit in the Reserve Fund in satisfaction of the
Reserve Requirement, and (iii) to pay costs of issuance of the 2020 Bonds.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(23)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
A summary of the bonds payable under the Water Fund is as follows:
Fixed Annual Original
Interest Principal Issue Outstanding
Bonds Maturity Rates Installments Amount June 30, 2022
City of Vernon 08/01/50 5.00% To begin 08/01/21: 14,840,000$ 14,600,000$
Water System Revenue Bonds,$240,000 -
2020 Taxable Series A $3,785,000
Premium 535,833
Total Revenue Bonds 15,135,833$
Note Payable – Direct Borrowing
In May 2019, the City entered into an agreement with Water Replenishment District of
Southern California (WRD) for assistance with the construction of a new groundwater well or
rehabilitation of an existing groundwater well. The promissory note is unsecured and has no
interest basis for an amount not to exceed $1,500,000. As of June 30, 2022, WRD has
disbursed all of the funds under the agreement to the City. The note is payable in quarterly
principal payments commencing September 1, 2020, in an amount which, together with all
quarterly payments, will be sufficient to fully amortize the principal balance of the note by the
maturity date of April 1, 2031.
Upon an event of default, WRD may declare any or all of the outstanding and unpaid
principal balance immediately due and payable, without presentment, demand, protest,
notice of protest, notice of acceleration or of intention to accelerate or any other notice,
declaration or act of any kind, all of which are hereby expressly waived by the City.
Debt Service Requirements
As of June 30, 2022, annual debt service requirements of the Water Fund to maturity are as
follows:
Water System Revenue Bonds
2020 Taxable Series A
Fiscal Year Ending June 30,Principal Interest
2023 250,000$ 575,725$
2024 265,000 562,850
2025 275,000 549,350
2026 - 542,475
2027 - 542,475
2028-2032 1,985,000 2,563,500
2033-2037 2,180,000 2,052,625
2038-2042 2,680,000 1,535,450
2043-2047 3,180,000 1,051,925
2048-2051 3,785,000 463,663
Total Requirements 14,600,000$ 10,440,038$
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(24)
NOTE 6 LONG-TERM OBLIGATIONS (CONTINUED)
Debt Service Requirements (Continued)
Note Payable - Direct Borrowing
Fiscal Year Ending June 30,Principal Interest
2023 139,535$ -$
2024 139,535 -
2025 139,535 -
2026 139,535 -
2027 139,535 -
2028-2031 523,256 -
Total Requirements 1,220,930$ -$
Changes in Long-Term Liabilities
The following is a summary of long-term liabilities transactions for the fiscal year ended
June 30, 2022:
Amounts
Balance Balance Due Within
June 30, 2021 Additions Reductions June 30, 2022 One Year
Other Debt - Bonds Payable 14,840,000$ -$ (240,000)$ 14,600,000$ 250,000$
Bond Premium 554,913 - (19,080) 535,833 -
Note Payable - Direct Borrowing 1,360,465 - (139,535) 1,220,930 139,535
Compensated Absences 103,191 79,892 (98,875) 84,208 28,069
Total 16,858,569$ 79,892$ (497,490)$ 16,440,971$ 417,604$
Credit Ratings
As of June 30, 2022, the ratings on all Water System Revenue Bonds is A-/Stable by S&P
and not rated by Moody’s.
NOTE 7 RISK MANAGEMENT
The Water Fund is in the City’s self-insurance program as part of its policy to self-insure
certain levels of risk within separate lines of coverage to maximize cost savings.
The City is exposed to various risks of loss related to torts; theft of, damage to, and
destruction of assets, errors and omissions; injuries to employees, and natural disasters.
The City utilizes insurance policy(s) to transfer these risks. Each policy has either self-
insured retention or deductible, which are parts of the City’s Risk Financing Program. These
expenses are paid on a cash basis as they are incurred. There have been no significant
settlements or reductions in insurance coverage during the past three fiscal years.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(25)
NOTE 7 RISK MANAGEMENT (CONTINUED)
Starting in Fiscal 2010, the City chose to establish Risk Financing in the General Fund,
whereby assets are set aside for claim-litigation settlements associated with the
abovementioned risks up to their self-insured retentions or policy deductibles. Athens
Administrators Inc. is the Third-Party Administrator for the City’s workers’ compensation
program, and they provide basic services for general liability claims and litigation.
The insurance limits for the fiscal year 2022 are as follows:
Deductible/SIR
Insurance Type Program Limits (Self-Insured Retention)
Excess Liability Insurance $20,000,000 $2,000,000 SIR per occurrence
D and O Employment Practice $2,000,000 $150,000 SIR non-safety; $150,000 SIR safety
Excess Workers Compensation $50,000,000 $1,500,000 SIR per occurrence for presumptive loss
Employer's Liability $1,000,000 $1,000,000 SIR per occurrence for all employees
Commercial Property Insurance $100,000,000 $25,000 except:
$25,000,000 Flood Sublimit $250,000 power stations
$1.5/kVA transfers, subject to a $250,000 minimum
$500,000 named transformers
Employee Dishonest - Crime $1,000,000 $25,000
Pollution - Site Owned $5,000,000 $25,000 for non-utility locations, divested locations
and scheduled storage tanks
$50,000 for utility locations
$100,000 for natural gas pipeline
Cyber Liability $3,000,000 $100,000
Contractors Equipment/Auto $10,000,000 Maximum Loss Per Occurrence $5,000
Physical Damage $1,000,000 Equipment Limit-loss or damage to
any one piece
Residential Property Insurance $8,023,126 Blanket Building Limit $2,500
$89,013 Blanket Business Personal Property Limit
Terrorism and Sabotage $100,000,000 Policy Aggregate N/A
$5,000,000 Active Shooter and Malicious Attack
Per Occurrence/Aggregate
$5,000,000 Terrorism and Sabotage Liability
Per Occurrence/Aggregate
The City has numerous claims and pending litigations, which generally involve accidents
and/or liability or damage to City property. The balance of claims/litigations against the City
is in the opinion of management, ordinary routine matters, incidental to the normal business
conducted by the City. In the opinion of management, such proceedings are substantially
covered by insurance, and the ultimate dispositions of such proceedings are not expected to
have a material adverse effect on the Water Fund’s financial position, results of operations
or cash flows. Further information regarding the City’s self-insurance program may be found
in the City’s Annual Financial Report.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(26)
NOTE 8 PENSION PLAN
A. General Information About the Pension Plans
Plan Descriptions
All full-time safety and miscellaneous personnel and temporary or part-time employees
who have worked a minimum of 1,000 hours in a fiscal year are eligible to participate in
the City’s cost-sharing and agent multiple-employer defined benefit pension Safety and
Miscellaneous Plans, respectively, administered by the California Public Employees’
Retirement System (CalPERS) that acts as a common investment and administrative
agent for participating public entities within the state of California. The City allocates the
costs of these Plans across all City departments. The Water Fund’s proportionate share
of the net pension liability of these Plans is reported as a cost-sharing plan in the
financial statements. Benefits vest after five years of service. Employees who retire at
the minimum retirement age with five years of credited service are entitled to retirement
benefits. Monthly retirement benefits are based on a percentage of an employee’s
average compensation for his or her highest consecutive 12 or 36 months of
compensation for each year of credited service.
Benefits Provided
Miscellaneous members hired prior to January 1, 2013, with five years of credited
service may retire at age 55 based on a benefit factor derived from the 2.7% at 55
Miscellaneous formula or may retire between ages 50 and 54 with reduced retirement
benefits. New Miscellaneous members (PEPRA) with five years of credited service may
retire at age 62 based on a benefit factor derived from the 2% at 62 Miscellaneous
formula or may retire between age 52 and 61 with reduced retirement benefits. The
benefit factor increases to a maximum of 2.5% at age 67. Safety members with five
years of credited service may retire at age 50 based on a benefit factor derived from the
3% at 50 Safety formula for sworn Police and Fire Department employees. New Safety
members (PEPRA) with five years of credited service may retire at age 57 based on a
benefit factor derived from the 2.7% at 57 Safety (PEPRA) formula or may retire
between age 50 and 56 with reduced retirement benefits for new Safety (PEPRA)
members of both Police and Fire Departments. CalPERS also provides death and
disability benefits. These benefit provisions and all other requirements are established
by state statute provided through a contract between the City and CalPERS.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(27)
NOTE 8 PENSION PLAN (CONTINUED)
A. General Information About the Pension Plans (Continued)
Benefits Provided (Continued)
The Plans’ provisions and benefits in effect as of the measurement date of June 30,
2021, are summarized as follows:
Miscellaneous
Prior to On or After
Hire Date January 1, 2013 January 1, 2013
Benefit Formula 2.7%@55 2%@62
Benefit Vesting Schedule 5 Years of Service 5 Years of Service
Benefit Payments Monthly for Life Monthly for Life
Retirement Age 50 52
Monthly Benefits, as a % of Eligible Compensation 2.0% to 2.7% 1.0% to 2.5%
Required Employee Contribution Rates 8.000% 6.250%
Required Employer Contribution Rates:
Normal Cost Rate 11.380% 11.380%
Payment of Unfunded Liability 3,924,540$ -$
Safety
Prior to On or After
Hire Date January 1, 2013 January 1, 2013
Benefit Formula 3.0%@50 2.7%@57
Benefit Vesting Schedule 5 Years of Service 5 Years of Service
Benefit Payments Monthly for Life Monthly for Life
Retirement Age 50 50
Monthly Benefits, as a % of Eligible Compensation 3.000% 2.0% to 2.7%
Required Employee Contribution Rates 9.000% 13.750%
Required Employer Contribution Rates:
Normal Cost Rate 22.780% 22.780%
Payment of Unfunded Liability 7,063,113$ 15,563$
Contributions
Section 20814(c) of the California Public Employees’ Retirement Law requires that the
employer contribution rates for all public employers be determined on an annual basis by
the actuary and shall be effective on July 1 following notice of a change in the rate.
Funding contributions for both Plans are determined annually on an actuarial basis as of
June 30 by CalPERS. The actuarially determined rate is the estimated amount
necessary to finance the costs of benefits earned by employees during the year, with an
additional amount to finance any unfunded accrued liability. The City is required to
contribute to the difference between the actuarially determined rate and the contribution
rate of employees. For the year ended June 30, 2022, the Water Fund’s share of
employer contributions made to the Plans was $459,607.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(28)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions
Actuarial Assumptions
The net pension liability of each of the Plans is measured as of June 30, 2021, using an
annual actuarial valuation as of June 30, 2020, rolled forward to June 30, 2021, using
standard update procedures. A summary of principal assumptions and methods used to
determine the net pension liability is shown below.
Miscellaneous Safety
Valuation Date June 30, 2020 June 30, 2020
Measurement Date June 30, 2021 June 30, 2021
Actuarial Cost Method Entry Age Normal Entry Age Normal
Actuarial Assumptions:
Discount Rate 7.15% 7.15%
Inflation 2.500% 2.500%
Payroll Growth 2.750% 2.750%
Projected Salary Increase (1)(1)
Mortality Rate Table (2)(2)
Post-Retirement Benefit Increase (3)(3)
(1)Varies by entry age and service.
(2)The mortality table used was developed based on CalPERS-specific data. The
probabilities of mortality are based on the 2017 CalPERS Experience Study for the
period from 1997 to 2015. Pre-retirement and Post-retirement mortality rates includes
15 years of projected mortality improvement using 90% of Scale MP-2016 published by
the Society of Actuaries. For more details on this table, please refer to the CalPERS
Experience Study and Review of Actuarial Assumptions report from December 2017
that can be found on the CalPERS website.
(3)The lessor of contract COLA or 2.50% until Purchasing Power Protection Allowance Floor
on purchasing power applies, 2.50% thereafter.
Long-Term Expected Rate of Return
The long-term expected rate of return on pension plan investments was determined
using a building-block method in which expected future real rates of return (expected
returns, net of pension plan investment expense and inflation) are developed for each
major asset class.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(29)
NOTE 8 PENSION PLAN (CONTINUED)
B.Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Long-Term Expected Rate of Return (Continued)
In determining the long term expected rate of return, CalPERS took into account both
short term and long-term market return expectations as well as the expected pension
fund cash flows. Using historical returns of all the funds’ asset classes, expected
compound (geometric) returns were calculated over the short term (first 10 years) and
the long-term (11+ years) using a building block approach. Using the expected nominal
returns for both short term and long term, the present value of benefits was calculated
for each fund. The expected rate of return was set by calculating the rounded single
equivalent expected return that arrived at the same present value of benefits for cash
flows as the one calculated using both short term and long-term returns. The expected
rate of return was then set equal to the single equivalent rate calculated above and
adjusted to account for assumed administrative expenses.
The expected real rates of return by asset class are as follows:
Assumed Real Return Real Return
Asset Years Years
Asset Class (a)Allocation 1 - 10 (b)11+ (c)
Global Equity 50.00%4.80%5.98%
Fixed Income 28.00 1.00%2.62%
Inflation Assets 0.00 0.77%1.81%
Private Equity 8.00 6.30%7.23%
Real Assets 13.00 3.75%4.93%
Liquidity 1.00 0.00%-0.92%
Total 100.00%
(a)
(b)An expected inflation of 2.0% used for this period.
(c)An expected inflation of 2.92% used for this period.
In the CalPERS CAFR, Fixed Income is included in Global Debt Securities; Liquidity is
included in Short-term Investments; Inflation Assets are included in both Global Equity
Securities and Global Debt Securities.
Discount Rate
The discount rate used to measure the total pension liability was 7.15%. The projection
of cash flows used to determine the discount rate assumed that contributions from plan
members will be made at the current member contribution rates and that contributions
from employers will be made at statutorily required rates, actuarially determined. Based
on those assumptions, the Plan’s fiduciary net position was projected to be available to
make all projected future benefit payments of current plan members. Therefore, the
long-term expected rate of return on plan investments was applied to all periods of
projected benefit payments to determine the total pension liability.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(30)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Subsequent Events
On July 12, 2021, CalPERS reported a preliminary 21.3% net return on investments for
fiscal year 2020-21. Based on the thresholds specified in CalPERS Funding Risk
Mitigation policy, the excess return of 14.3% prescribes a reduction in investment
volatility that corresponds to a reduction in the discount rate used for funding purposes
of 0.20%, from 7.00% to 6.80%. Since CalPERS was in the final stages of the four-year
Asset Liability Management (ALM) cycle, the board elected to defer any changes to the
asset allocation until the ALM process concluded, and the board could make its final
decision on the asset allocation in November 2021.
On November 17, 2021, the board adopted a new strategic asset allocation. The new
asset allocation along with new capital market assumptions, economic assumptions and
administrative expense assumption support a discount rate of 6.90% (net of investment
expense but without a reduction for administrative expense) for financial reporting
purposes. This includes a reduction in the price inflation assumption from 2.50% to
2.30% as recommended in the November 2021 CalPERS Experience Study and Review
of Actuarial Assumptions. This study also recommended modifications to retirement
rates, termination rates, mortality rates and rates of salary increases that were adopted
by the board. These new assumptions will be reflected in the GASB 68 account
valuation repots for the June 30, 2022 measurement date.
Proportionate Share of Net Pension Liability – Allocation of the City’s Pension Plans to
the Water Fund
The Water Fund’s net pension liability for the Plans is measured as the proportionate
share of the combined net pension liability of the City’s miscellaneous and safety agent
multiple-employer plans. The Water Fund’s proportionate share of the combined net
pension liability was based on the Water Fund’s current year share of contributions to
the pension plans relative to the City’s total current year contributions to the pension
plans.
The Water Fund’s proportionate share of the combined net pension liability for the
pension plans as of the measurement date ended June 30, 2020 and 2021 were as
follows:
Increase (Decrease)
Total Plan Net Pension
Pension Fiduciary Liability Proportionate
Liability Net Position (Asset)Share
Balance at June 30, 2020 (MD)17,762,255$ 13,094,244$ 4,668,011$ 3.45%
Balance at June 30, 2021 (MD)20,712,814 17,866,870 2,845,943 3.23%
Net Changes during 2020-21 2,950,559$ 4,772,626$ (1,822,067)$ -0.22%
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(31)
NOTE 8 PENSION PLAN (CONTINUED)
B.Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Pension Expense and Deferred Outflows and Inflows of Resources
For the measurement period ended June 30, 2021, the Water Fund recognized its
proportionate share of the combined pension expense of the Plans, totaling $67,423. At
June 30, 2022, the Water Fund reported its proportionate share of the Plans’ deferred
outflows of resources and deferred inflows of resources related to pensions from the
following sources:
Deferred Deferred
Outflows Inflows
of Resources of Resources
Pension Contributions Subsequent
to Measurement Date 459,607$ -$
Differences Between Actual and
Expected Experience 394,025 -
Change in Assumptions - -
Net Differences Between Projected and
Actual Earnings on Plan Investments - (1,610,826)
Differences Between Employer Contributions
And Proportionate Share of Contributions - (163,253)
Change in Employer's Proportion 63,647 (16,817)
Total 917,279$ (1,790,896)$
$459,607 reported as deferred outflows of resources related to contributions subsequent
to the measurement date will be recognized as a reduction of the net pension liability in
the year ending June 30, 2023. Differences between projected and actual investment
earnings are amortized on a five-year straight-line basis and all other amounts are
amortized over the expected average remaining service lives of all members that are
provided with benefits. Other amounts reported as deferred outflows of resources and
deferred inflows of resources related to pensions will be recognized as pension expense
as follows:
Fiscal Year Ended June 30,Total
2023 (240,409)$
2024 (274,651)
2025 (370,754)
2026 (447,410)
2027 -
Thereafter -
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(32)
NOTE 8 PENSION PLAN (CONTINUED)
B. Pension Liabilities, Pension Expenses, and Deferred Outflows/Inflows of
Resources Related to Pensions (Continued)
Sensitivity of the Net Pension Liability to Changes in the Discount Rate
The following presents the Water Fund’s proportionate share of the Plans’ combined net
pension liability, calculated using a discount rate of 7.15%, as well as what the Water
Fund’s proportionate share of the Plans’ combined net pension liability would be if it
were calculated using a discount rate that is a 1-percentage point lower or a
1-percentage point higher than the current rate:
Total
1% Decrease 6.15%
Net Pension Liability 5,011,809$
Current Discount Rate 7.15%
Net Pension Liability 2,845,943$
1% Increase 8.15%
Net Pension Liability 1,069,110$
Pension Plan Fiduciary Net Position
Detailed information about each pension plan’s fiduciary net position is available in the
separately issued CalPERS financial reports.
Payable to the Pension Plan
At June 30, 2022, the Water Fund had no outstanding amount of contributions to the
pension plans required for the year ended June 30, 2022.
NOTE 9 OTHER POSTEMPLOYMENT BENEFITS (OPEB)
The other postemployment benefits (OPEB) described in the following paragraphs relate to
the City’s OPEB plan. The Water Fund’s share of the net pension liability of the City’s OPEB
Plan is reported as a cost-sharing plan in these financial statements since the Water Fund’s
operations are handled by City employees who are eligible to participate in the City’s OPEB
Plan.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(33)
NOTE 9 OTHER POSTEMPLOYMENT BENEFITS (OPEB) (CONTINUED)
Benefits Provided
Retiree medical and dental benefits are established through the City’s Fringe Benefits and
Salary Resolution as well as individual memoranda of understanding between the City and
the City’s various employee bargaining groups. Generally, the City will provide
postemployment benefit plan for the employee only to those who retire at age sixty (60) or
later with twenty (20) years of continuous uninterrupted service, up to the age of sixty-five
(65). Alternatively, employees who retire before the age of sixty (60) with twenty (20) years
of continuous uninterrupted service, will be permitted to pay their medical and dental
premium cost and upon reaching the age of sixty (60), the City will pay the premium for the
medical and dental plans until they reach the age of sixty-five (65).
Resolution 2012-217 granted specific retiree medical benefits to employees who retired
during the 2012 2013 fiscal year in order to provide an incentive for early retirement
whereby the City authorized the payment of medical and dental insurance premiums for
eligible retiring employees and their eligible dependents with at least ten (10) years of
service plus 5% for each additional full year of service above the ten (10) years of service.
Resolution 2013-06 declared that the retiree medical benefits which had not been a vested
right for employees will continue to be a nonvested right for employees who continue to be
employed by the City on or after July 1, 2013, but will be a vested right for those who retire
during the 2012-2013 fiscal year. The City’s plan is considered a substantive OPEB plan
and the City recognizes costs in accordance with GASB Statement No 75. The City may
terminate its unvested OPEB in the future.
Funding Policy and Contributions
The City has established an irrevocable OPEB trust with assets dedicated to paying future
retiree medical benefits. The City intends to contribute 100% or more of the actuarially
determined contribution for the explicit subsidy liability only. The portion of the liability due to
the implicit subsidy is not prefunded but is paid as benefits come due. For the fiscal year
ended June 30, 2022, the Water Fund’s proportionate share of contributions made was
$94,830 ($49,746 contributed to the OPEB trust, $29,288 paid for retiree premiums, and the
estimated implied subsidy of $15,796).
Net OPEB Liability
The City’s net OPEB liability is measured as of June 30, 2021, and the total OPEB liability
used to calculate the net OPEB liability was determined by an actuarial valuation as of
June 30, 2021. A summary of the principal assumptions and methods used to determine the
total OPEB liability is shown on the next page.
Actuarial Assumptions
The valuation has been prepared on a closed group basis. Assumptions such as age-related
healthcare claims, healthcare trends, retiree participation rates, and spouse coverage, were
selected based on demonstrated plan experience and the best estimate of expected future
experience.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(34)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
Actuarial Assumptions (Continued)
Explicit subsidy benefit payments by employee group were allocated based on expected
benefit payments. The following actuarial assumptions, applied to all periods included in the
measurement unless otherwise specified:
Funding Method: Entry age normal level percent of pay cost method
Inflation: 2.25%
Salary Increases: 2.75% annual increases
Long-Term Return on Assets: 6.25% net of investment expenses
Discount Rate: 6.25%
Healthcare Cost Trend Rates: 6.3% for FY2022, gradually decreasing over several
decades to ultimate rate of 3.8% in FY76 and later
years
Mortality: 2017 CalPERS Experience Study. Tables include
15 years of static mortality improvement using 90%
of scale MP-2016
Long-Term Expected Rate of Return
The long-term expected rate of return was determined using a building-block method in
which best-estimate ranges of expected future real rates of return (expected returns, net of
OPEB plan investment expense and inflation) are developed for each major asset class.
These ranges are combined to produce the long-term expected rate of return by weighing
the expected future real rates of return by the target asset allocation percentage and by
adding expected inflation. Best estimates of arithmetic real rates of return for each major
asset class included in the OPEB plan’s target asset allocation as of June 30, 2021 are
summarized in the following table:
Long-Term
Target Expected Real
Asset Class Allocation Rate of Return
CERBT Strategy 1:
Equity 59.00% 4.42%
Fixed Income 25.00 1.00%
TIPS 5.00 0.15%
Commodities 3.00 3.98%
REITs 8.00 1.73%
Total 100.00%
Discount Rate
The discount rate used to measure the total OPEB liability was 6.25%. The projection of
cash flows used to determine the discount rate assumed that City’s contributions will be
made at rates equal to the actuarially determined contribution rates. Based on those
assumptions, the fiduciary net position was projected to be available to make all projected
OPEB payments for current active and inactive employees and beneficiaries. Therefore, the
long-term expected rate of return on plan investments was applied to all periods of projected
benefit payments to determine the total OPEB liability.
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(35)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
Allocation of the Net OPEB Liability
The Water Fund’s proportionate share of the net OPEB liability as of the measurement
dates ended June 30, 2020 and 2021 was as follows:
Increase (Decrease)
Total Plan Net OPEB
OPEB Fiduciary Liability Proportionate
Liability Net Position (Asset)Share
Balance at June 30, 2020 (MD)938,946$ 241,617$ 697,329$ 3.45%
Balance at June 30, 2021 (MD)885,514 356,171 529,343 3.23%
Net Changes during FY 2020-21 (53,432)$ 114,554$ (167,986)$ -0.22%
Sensitivity of the Net OPEB Liability to Changes in the Discount Rate
The following presents the Water Fund’s proportionate share of the net OPEB liability if it
were calculated using a discount rate that is 1% point lower or 1% point higher than the
current rate:
Discount Rate
1% Decrease Current Rate 1% Increase
(5.25%)(6.25%)7.25%)
Net OPEB Liability 628,426$ 529,343$ 446,130$
Sensitivity of the Net OPEB Liability to Changes in the Healthcare Cost Trend Rates
The following presents the Water Fund’s proportionate share of the net OPEB liability if it
were calculated using a healthcare cost trend rates that are 1% point lower (5.3%
decreasing to an ultimate rate of 2.8%) or 1% point higher (7.3% decreasing to an ultimate
rate of 4.8%) than the current rate:
Healthcare Trend Rate
1% Decrease Current Rate 1% Increase
Net OPEB Liability 487,506$ 529,343$ 570,961$
OPEB Expense and Deferred Inflows and Outflows of Resources Related to OPEB
For the year ended June 30, 2022, the Water Fund recognized its proportionate share of the
OPEB expense(revenue) of $(27,257). At June 30, 2022, the Water Fund reported deferred
outflows of resources and deferred inflows of resources related to OPEB from the following
sources:
CITY OF VERNON
WATER FUND
NOTES TO BASIC FINANCIAL STATEMENTS
JUNE 30, 2022
(36)
NOTE 9 POSTEMPLOYMENT BENEFITS OTHER THAN PENSIONS (OPEB) (CONTINUED)
OPEB Expense and Deferred Inflows and Outflows of Resources Related to OPEB
(Continued)
Deferred Deferred
Outflows Inflows
of Resources of Resources
Contributions Between Measurement Date and
Reporting Date 94,830$ -$
Difference Between Expected and Actual Liability 4,487 (114,095)
Changes of Assumptions 14,448 (121,225)
Net Differences Between Projected and Actual
Earnings on Investments - (35,787)
Total 113,765$ (271,107)$
The $94,830 reported as deferred outflows of resources related to contributions subsequent
to the measurement date will be recognized as a reduction of the net OPEB liability in the
year ended June 30, 2023. Differences between projected and actual investment earnings
are amortized on a five-year straight-line basis and all other amounts are amortized over the
expected average remaining service lives of all members that are provided with benefits.
Other amounts reported as deferred outflows of resources and deferred inflows of resources
related to OPEB will be recognized as OPEB expense as follows:
Deferred
Outflows
(Inflows)
Fiscal Year Ending June 30,of Resources
2022 (75,491)$
2023 (75,491)
2024 (75,530)
2025 (72,853)
2026 50,007
Thereafter (2,814)
Payable to the OPEB Plan
At June 30, 2022, the Water Fund had no outstanding amount of contributions to the OPEB
plan required for the year ended June 30, 2022.
REQUIRED SUPPLEMENTARY INFORMATION
CITY OF VERNON
WATER FUND
SCHEDULE OF PROPORTIONATE SHARE OF THE NET PENSION LIABILITY
CITY'S MISCELLANEOUS AND SAFETY COST SHARING PLAN
LAST TEN FISCAL YEARS *
(37)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017
Measurement Date 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017 6/30/2016
Plan’s Proportion of the
Net Pension Liability 3.23% 3.45% 3.28% 3.11% 3.74% 3.80%
Plan’s Proportionate Share of the
Net Pension Liability 2,845,943$ 4,668,011$ 3,964,339$ 3,533,209$ 4,100,788$ 3,619,851$
Plan’s Covered Payroll 792,625 891,592 925,620 1,100,727 1,038,438 499,838
Plan’s Proportionate Share of the
Net Pension Liability as a
Percentage of Covered Payroll 359.05% 523.56% 428.29% 320.99% 394.90% 724.20%
Plan Fiduciary Net Position as a
Percentage of the Total
Pension Liability 85.45% 74.79% 76.15% 77.68% 77.85% 78.91%
Notes to Schedule:
Benefit Changes:
There were no changes in benefits.
Changes in Assumptions:
From fiscal year June 30, 2017 to June 30, 2018:
The discount rate was reduced from 7.65% to 7.15%.
From fiscal year June 30, 2018 to June 30, 2019:
There were no significant changes in assumptions.
From fiscal year June 30, 2019 to June 30, 2020:
There were no significant changes in assumptions.
From fiscal year June 30, 2020 to June 30, 2021:
The inflation rate was increased from 2.5% to 2.625%
The payroll growth rate was reduced from 3.00% to 2.875%.
From fiscal year June 30, 2021 to June 30, 2022:
The inflation rate was decreased from 2.625% to 2.5%
The payroll growth rate was reduced from 2.875% to 2.75%.
The investment rate of return was decreased from 7.15% to 7.00%.
* Fiscal year 2017 was the first year the City allocated a portion of the net pension liability to the Water Fund; therefore only six years are shown.
CITY OF VERNON
WATER FUND
SCHEDULE OF PLAN CONTRIBUTIONS
CITY'S MISCELLANEOUS AND SAFETY COST SHARING PLAN
LAST TEN FISCAL YEARS *
(38)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017
Actuarially Determined
Contributions 459,607$ 435,752$ 404,765$ 339,930$ 354,831$ 346,113$
Contributions in relation to the
Actuarially Determined
Contributions (459,607) (435,752) (404,765) (339,930) (354,831) (346,113)
Contribution :
Deficiency (Excess) -$ -$ -$ -$ -$ -$
Covered Payroll 819,206$ 792,625$ 891,592$ 925,620$ 1,100,727$ 1,038,438$
Contributions as a Percentage
of Covered Payroll 56.10% 54.98% 45.40% 36.72% 32.24% 33.33%
Notes to Schedule:
Valuation Date 6/30/2019 6/30/2018 6/30/2017 6/30/2016 6/30/2015 6/30/2014
Methods and Assumptions Used to
Determine Contribution Rates:
Actuarial Cost Method Entry Age Entry Age Entry Age Entry Age Entry Age Entry Age
Amortization Method (1) (1) (1) (1) (1) (1)
Asset Valuation Method Fair Value Fair Value Fair Value Fair Value Fair Value Fair Value
Inflation 2.625% 2.625% 2.625% 2.75% 2.75% 2.75%
Salary Increases (2) (2) (2) (2) (2) (2)
Investment Rate of Return 7.00% (3) 7.25% (3) 7.25% (3) 7.375% (3) 7.50% (3) 7.50% (3)
Mortality (4) (4) (4) (4) (4) (4)
(1) Level percentage of payroll, closed.
(2) Depending on age, service, and type of employment.
(3) Net of pension plan investment expense, including inflation.
(4) Mortality assumptions are based on mortality rates resulting from the most recent CalPERS Experience Study
adopted by the CalPERS Board.
* Fiscal year 2017 was the first year the City allocated a portion of the net pension liability to the Water Fund; therefore only six years are shown.
CITY OF VERNON
WATER FUND
SCHEDULE OF PROPORTIONATE SHARE OF THE NET OPEB LIABILITY
LAST TEN FISCAL YEARS *
(39)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018
Measurement Date 6/30/2021 6/30/2020 6/30/2019 6/30/2018 6/30/2017
Plan’s Proportion of the
Net OPEB Liability 3.23% 3.45% 3.28% 3.11% 4.08%
Plan’s Proportionate Share of the
Net OPEB Liability 529,343$ 697,329$ 719,261$ 719,107$ 1,482,614$
Plan’s Covered-Employee Payroll 1,093,781 1,048,734 1,095,236 1,368,166 1,368,760
Plan’s Proportionate Share of the
Net OPEB Liability as a Percentage
of Covered-Employee Payroll 48.40% 66.49% 65.67% 52.56% 108.32%
Plan Fiduciary Net Position as a
Percentage of the Total OPEB Liability 40.22% 25.70% 16.30% 8.62% 2.83%
Notes to Schedule:
Changes in Assumptions:
* Fiscal year 2018 was the first year of implementation; therefore only five years are shown.
In the June 30, 2018 measurement period, the pre-65 waived retiree re-election was updated to be 10% after age 65.
The discount rate was changed from 2.85% to 3.58% for the measurement period ended June 30, 2017. The discount
rate for the measurement periods ended June 30, 2018 and 2019 was 6.50%. The discount rate for the measurement
period ended June 30, 2020 was reduced to 6.25%.
The mortality, retirement, disability, and termination rates for the measurement periods ended June 30, 2017 and 2018
were based on the CalPERS 1997-2011 Experience Study and CalPERS 1997-2015 Experience Study, respectively.
The mortality improvement rates for the measurement periods ended June 30, 2017 and 2018 were based on the Scale
MP-2016 and Scale-2018, respectively.
CITY OF VERNON
WATER FUND
SCHEDULE OF OPEB CONTRIBUTIONS
LAST TEN FISCAL YEARS *
(40)
Fiscal Year Ended 6/30/2022 6/30/2021 6/30/2020 6/30/2019 6/30/2018
Actuarially Determined
Contribution 49,744$ 53,086$ 63,389$ 83,829$ 109,990$
Contributions in relation to the
Actuarially Determined
Contribution (94,830) (108,041) (128,484) (93,060) (84,361)
Contribution:
Deficiency (Excess) (45,086)$ (54,954)$ (65,095)$ (9,231)$ 25,629$
Covered Payroll 1,024,922$ 1,093,781$ 1,048,734$ 1,095,236$ 1,368,166$
Contributions as a Percentage
of Covered-Employee Payroll 9.25% 9.88% 12.25% 8.50% 6.17%
Notes to Schedule:
Valuation Date 6/30/2019 6/30/2018 6/30/2018 6/30/2016 6/30/2016
Methods and Assumptions Used to
Determine Contribution Rates:
Actuarial Cost Method Entry AgeEntry AgeEntry AgeEntry AgeEntry Age
Amortization Method (1)(1)(1)(1)(1)
Amortization Period 28 years 28 years 27 Years 27 Years 29 Years
Asset Valuation Method Market Value Market Value Market Value Market Value Market Value
Inflation 2.25% 2.25% 2.50% 2.50% 2.75%
Healthcare Trend Rates (7)(6)(3)(3)(2)
Investment Rate of Return 6.25% 6.25% 6.50% 7.00% 7.00%
Mortality (5)(5)(5)(5)(4)
(1)Level percentage of payroll, closed.
(2)8.50% trending down to 5.00%.
(3)6.90% trending down to 4.00%.
(4)CalPERS December 2014 experience study.
(5)CalPERS December 2017 experience study.
(6)6.70% trending down to 3.80%.
(7)6.30% trending down to 3.80%.
*Fiscal year 2018 was the first year of implementation; therefore five years year are shown.
City Council Agenda Report
Meeting Date:October 17, 2023
From:Todd Dusenberry, General Manager of Public Utilities
Department:Public Utilities
Submitted by:Adriana Ramos, Administrative Analyst
Subject
Vernon Public Utilities 2023 Integrated Resource Plan (IRP)
Recommendation
A. Find that approval of the proposed action is exempt from California Environmental Quality Act
(CEQA) review, because it is a continuing administrative activity that will not result in direct or
indirect physical changes in the environment, and therefore does not constitute a “project” as
defined by CEQA Guidelines Section 15378;
B. Approve and adopt the Vernon Public Utilities 2023 IRP; and
C. Authorize the General Manager of Public Utilities to take all necessary actions to implement
the IRP, consistent with California State law mandates, including but not limited to periodic
updates and IRP revisions.
Background
Vernon Public Utilities’ (VPU) 2023 IRP is a comprehensive 20-year strategy that outlines the
Utility’s plan for how it will continue to meet its customers’ need for reliable and cost-effective
electric service while meeting various regulatory initiatives, generating and procuring clean
energy, and the continuous investment in the distribution system infrastructure while addressing
system constraints. Senate Bill (SB) 350 requires Publicly Owned Utilities (POUs), like VPU, to
develop an IRP at least once every five years. The last IRP was filed in 2018.
The IRP outlines the process for developing a resource acquisition strategy that balances supply
and demand. This roadmap aims to help make short-term and long-term decisions on how the
utility will comply with several legislative requirements. Specifically, SB 350’s requirement to
reduce greenhouse gas emissions by 40% to 1990 levels by 2030 and 100% of retail load with
clean energy by 2045, as well as SB 1020, which mandates that 90% of the load be served by
clean energy by 2035 and 95% a load with clean energy by 2045.
Over the past five years, the Utility’s Integrated Resource team has worked diligently to transform
the power portfolio and can proudly share that VPU has met the goals identified in the 2018 IRP;
increased its renewable generation by 43.3% and affirmed that more than 50% of its resources
are carbon-free.
It’s important to know that VPU recently signed two Power Purchase Agreements (PPAs) for two
large solar projects: Daggett Solar for 60 megawatts (MW) of capacity with an expected
commercial operation of December 2023, and Sapphire Solar for 39 MW of capacity with an
anticipated commercial operation date of December 2026. As part of these PPAs, VPU will also
acquire a total of over 50 MW of four–hour energy storage: 30 MW from Daggett and 19.6 MW
from Sapphire. These two solar agreements greatly surpass what was recommended in the 2018
IRP.
VPU’s goal for the 2023 IRP is to continue to procure reliable, affordable, renewable, and zero-
carbon energy while addressing the growth of transportation and building electrification, demand
for energy efficiency and demand side management initiatives, and the growing advancements
with distributed energy technologies.
To assist with this effort, on March 21, 2023, the City Council approved a services agreement
with Ascend Analytics (Ascend) to assist VPU staff with developing a comprehensive IRP
Strategy. Ascend has assisted many of the neighboring POUs with designing Portfolio Options
using their proprietary PowerSIMM modeling software that includes resource mixes, availability
in the market, costs, and analyzes them to develop preferred portfolio options.
IRP Process
During the planning process, VPU engaged community stakeholders to seek guidance and
direction on key decisions for preferred portfolios of generation, demand, and distributed
resources, including cost. VPU spent several months on stakeholder outreach by conducting in-
person meetings, circulating a comprehensive survey, informing them about the IRP process,
and garnering input for developing Portfolio Options. Part of the outreach was to inform
stakeholders of the challenges facing VPU and to obtain valuable insight into the customers’
needs and priorities.
VPU stakeholders included city residents, current and prospective property and business
owners, property developers, business employees, the Vernon Business and Industry
Commission, the Green Vernon Commission, the Vernon Chamber of Commerce, the City
Council, and commissioners, to name a few.
Through the stakeholder meetings and feedback from the survey, Vernon customers made their
priorities clear, which was to ensure that the utility continued to provide reliable electric service
and maintained low rates. Responses from the survey also provided helpful insight; more than
80% of the respondents were either satisfied or very satisfied with the services provided by VPU,
and more than 70% of respondents felt there was a direct correlation with rates increasing if VPU
exceeded the state’s Renewable Portfolio Standards (RPS) target.
A total of three stakeholder meetings were held on March 15th, May 11th, and June 21, 2023.
Throughout the process, presentations were made that provided an overview of the survey
results, explained the IRP process, summarized legislative requirements, described the scenario
modeling process, and provided details regarding the final three scenarios for consideration,
along with the associated costs.
VPU communicated information about both the community meetings, as well as a survey through
several outreach channels which included advertisements in the paper, use of social media
platforms, printed mail seeking participation in the survey and meetings, email updates,
newsletters, as well as direct phone calls to customers.
Portfolio Options
IRP modeling is a multi-step process where staff worked with Ascend to gather data on VPU
supply resources and load, including historical data, projections for resource updates, and
expected changes in customer load. Ascend’s modeling provides several scenarios that vary in
system costs, reliability, emissions, and resource operations. The Portfolio Options explored a
different mixture of resource options, and renewable generation such as geothermal, solar
photovoltaic (PV), wind, and clean energy like hydrogen, Carbon Capture Sequestration,
hydroelectric, and nuclear, as well as battery storage for capacity.
Portfolio 1 includes procuring solar PV from northern and southern CA, the most cost-effective
wind and four-hour battery storage options, and maintaining operations of the utility’s natural gas
power plant, Malburg Generating Station (MGS), until 2035. Portfolio 2 is similar to Portfolio 1
but includes assumptions to procure nearly 70 MW of geothermal. Portfolio 3 does not include
geothermal but considers fuel switching the MGS to produce an output of approximately 45 MW
of green hydrogen and includes wind and battery storage.
Portfolio 1 was selected as the preferred portfolio primarily because geothermal and hydrogen
are estimated to be much more expensive than the four-hour battery storage and the sheer
volume of solar resources available in today’s market. The total supply costs for Portfolio 2 and
Portfolio 3 are significantly higher than the total supply cost for Portfolio 1. These costs are a
function of the expected resource costs 10 to 15 years from now, which include a significant
amount of uncertainty and risk. Pursuing Portfolio 1 would achieve the renewable and zero-
carbon generation goals, maintain the utility’s ability to provide reliable service and affordable
rates, and meet all statutory requirements. VPU’s ongoing goal is to strive for competitive and
stable rates and provide high reliability throughout the entire planning period of 2023 through
2045.
If adopted by the City Council (VPU’s governing board), the 2023 IRP will be submitted to the
California Energy Commission as required by SB 350. Compliance filing must include the IRP,
supporting information, and the four standardized tables.
Fiscal Impact
There is no fiscal impact associated with this report.
Attachments
1. Vernon Public Utilities 2023 Integrated Resource Plan
2023
Integrated
Resource
Plan
Vernon Public Utilities 202 3 IRP ii
CONTRIBUTORS
Vernon Public Utilities
Tim Bass
Aziz Danialian
Todd Dusenberry
Sylvie Gonzalez
Margie Otto
Ramzi Raufdeen
Efrain Sandoval
Shawn Sharifzadeh
Jonathan Sun
Lisa Umeda
Ascend Analytics
Anthony Boukarim
Rich Maggiani
Siddarth Mathew
Brandon Mauch
PREFACE
Vernon Public Utilities’ Integrated Resource Plan (IRP) serves as a comprehensive planning
strategy and long-term road map for procuring a Renewable Portfolio Standards (RPS)
compliant and zero-carbon resource portfolio that meets California statutory and regulatory
requirements while ensuring reliability and affordability for its customers.
Vernon Public Utilities 2023 IRP iii
Table of Contents
1. EXECUTIVE SUMMARY ..................................................................................... 1-1
Complying with Clean Energy and Customer-Centric Goals .................................................... 1-2
IRP Conclusions ...................................................................................................................... 1-3
The Preferred Portfolio...........................................................................................................................1-4
Capacity Expansion Resource Mix........................................................................................................1-5
Rationale for the Preferred Portfolio Selection ......................................................................................1-6
Acquisition Timeline ..............................................................................................................................1-7
Cost Considerations ................................................................................................................. 1-8
Driving Factors for this IRP ..................................................................................................... 1-9
Transmission and Distribution Upgrades ............................................................................... 1-10
2. BACKGROUND AND PLANNING GOALS ...................................................... 2-1
The Inception of the Integrated Resource Plan ......................................................................... 2-1
About This IRP ........................................................................................................................ 2-2
The Goal of the IRP ...............................................................................................................................2-3
VPU’s Approach for Creating the IRP ..................................................................................................2-5
Outcomes from 2018 IRP Recommendations ........................................................................... 2-7
About Vernon Public Utilities .................................................................................................. 2-8
Customer Base ........................................................................................................................................2-9
Award Winning Grid Reliability and Service ..................................................................................... 2-10
Membership in SCPPA ........................................................................................................................ 2-11
Energy Resource Mix ........................................................................................................................... 2-12
Stakeholder Outreach Efforts ................................................................................................. 2-12
Stakeholder Meetings ........................................................................................................................... 2-13
VPU Stakeholder Survey and Results .................................................................................................. 2-13
3. PLANNING DRIVERS .......................................................................................... 3-1
California Policy Requirements ................................................................................................ 3-1
Greenhouse Gas Emission Reduction Statutes .....................................................................................3-2
Renewable Portfolio Standard and Zero-Carbon Resources.................................................................3-4
Subsidies for Customer Rooftop Solar ...................................................................................................3-8
Cap-and-Trade Program and Market ....................................................................................................3-8
Energy Efficiency and Demand-Side Management ..............................................................................3-9
Transportation Electrification .............................................................................................................. 3-10
Energy Storage Resources .................................................................................................................... 3-11
Statewide Planning Considerations ........................................................................................ 3-11
California Air Resources Board Scoping Plan ..................................................................................... 3-11
CEC Integrated Energy Policy Report Demand Forecasts ................................................................. 3-13
CAISO Transmission Planning Process .............................................................................................. 3-14
Resource Adequacy Methodology ....................................................................................................... 3-17
Building Electrification Impacts ........................................................................................................... 3-21
Transportation Electrification Analysis ............................................................................................... 3-22
Regionalization Considerations and Risks .............................................................................. 3-24
The Western Interconnection and WECC .......................................................................................... 3-24
CAISO as a Regional Transmission Operator .................................................................................... 3-26
Western Energy Imbalance Market ..................................................................................................... 3-27
Extended Day-Ahead Market .............................................................................................................. 3-27
Table of Contents
Vernon Public Utilities 2023 IRP iv
Western Resource Adequacy Program ................................................................................................ 3-28
Grid Regionalization: Opportunities and Challenges ......................................................................... 3-29
Cost of Service and Rate Impacts ........................................................................................... 3-33
4. ENERGY AND DEMAND FORECASTS ............................................................ 4-1
Long-Term Energy Forecast Methodology ............................................................................... 4-1
Random Forest Regression ....................................................................................................................4-2
Historic Forecasting Predictors ..............................................................................................................4-2
Historical Weather and 48-Hour Trailing Weather Predictors .............................................................4-5
Annual Energy and Demand Forecasts .................................................................................... 4-6
Annual Peak Demand Forecast .............................................................................................................4-7
Annual Energy Forecast ........................................................................................................................4-8
Rooftop Solar PV Installations ................................................................................................. 4-9
Energy Efficiency Impacts ...................................................................................................... 4-10
Price Forecasts ....................................................................................................................... 4-11
Transportation Electrification Impacts ................................................................................... 4-13
Zero-Emission Vehicle Adoption and Energy Impacts ....................................................................... 4-13
Electric Vehicle Impact ........................................................................................................................ 4-14
5. RESOURCE AND PROGRAM REVIEW ............................................................ 5-1
Energy Efficiency Targets ......................................................................................................... 5-1
Energy Efficiency Programs ..................................................................................................... 5-2
Demand Response Programs .................................................................................................................5-3
Demand-Side Management Programs ..................................................................................................5-3
Energy Efficiency Program Impacts ......................................................................................... 5-4
Energy Efficiency Incentive Program ....................................................................................................5-4
Energy Efficiency Potential Forecasts ....................................................................................... 5-5
Energy Efficiency Potential Forecasting Study .....................................................................................5-5
Transportation Electrification ................................................................................................... 5-8
Transportation Electrification Programs ...............................................................................................5-9
Customer Education and Outreach .......................................................................................................5-9
Electric Vehicle Charging Rates ........................................................................................................... 5-10
Municipal Fleet .................................................................................................................................... 5-10
Electric Vehicle Charging Infrastructure .............................................................................................. 5-11
Underserved and Disadvantaged Community Initiatives ........................................................ 5-12
EV Chargers in DACs .......................................................................................................................... 5-12
Environmental Sustainability ............................................................................................................... 5-12
6. TRANSMISSION AND DISTRIBUTION ............................................................ 6-1
Bulk Transmission System ....................................................................................................... 6-1
Bulk Transmission System .....................................................................................................................6-1
Transmission Service Agreements .........................................................................................................6-1
Laguna Bell Corridor Line Upgrades ....................................................................................................6-2
Distribution System .................................................................................................................. 6-3
Distributed Generation Evaluation and Recommendations .................................................................6-4
Distribution System Capital Improvement Project ...............................................................................6-5
System Reliability..................................................................................................................... 6-8
Three Reliability Indicators ....................................................................................................................6-8
Cause of Outages .................................................................................................................................. 6-11
7. RESOURCE PORTFOLIO .................................................................................... 7-1
Resource Portfolio Overview .................................................................................................... 7-1
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Vernon Public Utilities 2023 IRP v
Current Resource Portfolio ....................................................................................................... 7-3
Natural Gas Resources ...........................................................................................................................7-3
Zero-Emission Resources .......................................................................................................................7-4
Renewable Energy Resources ................................................................................................................7-5
Wholesale Market Power Purchases ......................................................................................... 7-7
8. RENEWABLE ENERGY AND RPS COMPLIANCE ......................................... 8-1
Renewable Generation ............................................................................................................. 8-1
RPS Compliance ...................................................................................................................... 8-2
RPS and Clean Energy Portfolio 1 ........................................................................................................8-4
RPS and Clean Energy Portfolio 2 ........................................................................................................8-5
RPS and Clean Energy Portfolio 3 ........................................................................................................8-6
Portfolio Compliance ............................................................................................................... 8-7
9. MARKET RESOURCE PORTFOLIOS ................................................................ 9-1
The Foundation of This IRP .................................................................................................... 9-1
Modeling and Analysis Framework ......................................................................................... 9-2
Input Assumptions and Portfolio Modeling .............................................................................. 9-3
Candidate Resources ..............................................................................................................................9-4
Potential Portfolio Options Procurement Plan ......................................................................................9-5
Resource Cost Estimates ........................................................................................................................9-7
Risk Analysis ..........................................................................................................................................9-8
Analyzing VPU’s Current Resource Portfolio .......................................................................... 9-9
Three Portfolio Scenarios ....................................................................................................... 9-11
Portfolio 1: Solar, Wind, Storage ......................................................................................................... 9-11
Portfolio 2: Geothermal, Solar, Wind, Storage ................................................................................... 9-12
Portfolio 3: Green Hydrogen CT, Solar, Wind, Storage ..................................................................... 9-12
Capacity Expansion Results ................................................................................................... 9-13
Preferred Portfolio Selection ................................................................................................................ 9-13
Alternative Portfolio 2 .......................................................................................................................... 9-16
Alternative Portfolio 3 .......................................................................................................................... 9-18
Modeled Portfolios and RA Requirements ......................................................................................... 9-20
Capacity Expansion Resource Mix...................................................................................................... 9-20
Portfolio Cost Comparison .................................................................................................................. 9-21
The Preferred Plan and Disadvantaged Communities ........................................................................ 9-22
10. ACTION PLANS ................................................................................................ 10-1
Initial Steps ............................................................................................................................ 10-2
Bulk Power System Action Plan ............................................................................................. 10-3
Utility-Scale Resource Procurement .................................................................................................... 10-4
Malburg Generating Station ................................................................................................................ 10-4
Distributed Energy Resources Action Plan ............................................................................. 10-5
Energy Efficiency Action Plan ............................................................................................... 10-5
Transportation Electrification Action Plan ............................................................................. 10-6
Customer Engagement Action Plan ....................................................................................... 10-7
Distribution System Action Plan ............................................................................................ 10-7
Table of Contents
Vernon Public Utilities 2023 IRP vi
11. APPENDICES .................................................................................................... 11-1
A. IRP GUIDELINES CROSS-REFERENCE.......................................................... A-1
B. GLOSSARY AND DEFINITIONS ...................................................................... B-1
C. POWERSIMM PLANNER .................................................................................. C-1
PowerSIMM Overview ........................................................................................................... C-1
Simulations in PowerSIMM ................................................................................................................. C-1
Dispatch in PowerSIMM ...................................................................................................................... C-2
Resource Planning Modeling .................................................................................................. C-3
Production Cost Modeling .................................................................................................................... C-3
Capacity Expansion Optimization........................................................................................................ C-4
Resource Adequacy Analysis ................................................................................................................ C-5
Simulation Details ................................................................................................................... C-7
Weather Simulation .............................................................................................................................. C-7
Load Simulation .................................................................................................................................... C-8
Wind and Solar Simulation ................................................................................................................ C-10
Small Hydro Simulation ..................................................................................................................... C-12
Forward Price Simulation ................................................................................................................... C-13
Spot Price Simulation .......................................................................................................................... C-14
Basis Price Simulation ......................................................................................................................... C-14
D. ANNUAL ENERGY FORECAST DATA .......................................................... D-1
E. STAKEHOLDER OUTREACH ........................................................................... E-1
Stakeholder Meetings .............................................................................................................. E-1
Stakeholder Survey and Results ............................................................................................... E-3
Survey Results ....................................................................................................................................... E-4
Key Insights ......................................................................................................................................... E-12
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Vernon Public Utilities 2023 IRP vii
FIGURES
Figure 1. Four Foundational Pillars of the IRP ................................................................................................. 1-1
Figure 2. Preferred Portfolio Capacity Resource Accounting Table (CRAT) .................................................... 1-4
Figure 3. Preferred Portfolio Energy Balance Table (EBT)................................................................................ 1-5
Figure 4. 2030 Energy Mix ................................................................................................................................ 1-6
Figure 5. 2045 Energy Mix ................................................................................................................................ 1-6
Figure 6. New Nameplate Annual Capacity Expansion for the Preferred Portfolio .......................................... 1-7
Figure 7. Total Net Present Value Cost of Load for Each Portfolio .................................................................. 1-8
Figure 8. IRP Balances Demand with Supply ................................................................................................... 2-3
Figure 9. IRP Roadmap of Resource Compliance ............................................................................................. 2-4
Figure 10. Four Components of the IRP Process ................................................................................................ 2-5
Figure 11. VPU Customer Count ...................................................................................................................... 2-10
Figure 12. VPU Energy Consumed ................................................................................................................... 2-10
Figure 13. 2024 Energy Resource Mix .............................................................................................................. 2-12
Figure 14. Greenhouse Gas Emission Reduction Legislation ............................................................................. 3-2
Figure 15. RPS and Zero-Carbon Target Legislation .......................................................................................... 3-4
Figure 16. RPS Percent Procurement Requirements by Compliance Periods ..................................................... 3-7
Figure 17. Customer Rooftop Solar Installation Legislation ............................................................................... 3-8
Figure 18. Cap-and-Trade Program Legislation .................................................................................................. 3-8
Figure 19. Energy Efficiency and Demand-Side Management Legislation ......................................................... 3-9
Figure 20. Electric Vehicle Charging Legislation .............................................................................................. 3-10
Figure 21. CAISO Transmission Planning Zones and Capacities ..................................................................... 3-16
Figure 22. CAISO Local Capacity Area Map ................................................................................................... 3-18
Figure 23. The Variable Renewable Generation Duck Curve ........................................................................... 3-19
Figure 24. Zero-Emission Vehicles Sales Compliance with ACC II .................................................................. 3-23
Figure 25. North American NERC Interconnections and Governing Organizations ........................................ 3-24
Figure 26. Map of Nationwide RTOs ................................................................................................................ 3-25
Figure 27. CAISO WEIM Participants and SPP Markets+ Development Participants .................................... 3-32
Figure 28. Average Daily Profile by Month ........................................................................................................ 4-3
Figure 29. Average Daily Profile by Day ............................................................................................................. 4-4
Figure 30. Average Daily Profile by Holiday ...................................................................................................... 4-4
Figure 31. Average August Daily Profile ............................................................................................................. 4-5
Figure 32. Example Rank and Average Weather Profiles ................................................................................... 4-5
Figure 33. Behind-the-Meter Solar PV Energy Forecast .................................................................................... 4-10
Figure 34. CAISO SP-15 Power Price Forecast ................................................................................................. 4-11
Figure 35. SoCal City Gate Natural Gas Price Forecast ................................................................................... 4-12
Figure 36. Carbon Emission Price Forecast ....................................................................................................... 4-12
Figure 37. Medium- and Heavy-Duty Electric Vehicle Population Forecast ..................................................... 4-13
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Vernon Public Utilities 2023 IRP viii
Figure 38. Transportation Electrification Demand Forecast ............................................................................. 4-14
Figure 39. Net Incremental Market Potential by Sector (MWh) and Percent of Sales ........................................ 5-6
Figure 40. Incremental Net Market Energy Efficiency Potential by Sector ......................................................... 5-7
Figure 41. Cumulative Net Market Energy Efficiency Potential by Sector .......................................................... 5-8
Figure 42. SAIFI Outage Frequency Comparison ............................................................................................... 6-8
Figure 43. SAIDI Outage Duration Comparison ................................................................................................ 6-9
Figure 44. CAIDI Average Outage Restoration Time Comparison .................................................................... 6-9
Figure 45. Causes of Outages ............................................................................................................................ 6-11
Figure 46. Current and Near-Term Generation Mix ........................................................................................... 7-2
Figure 47. Malburg Generating Station ............................................................................................................... 7-3
Figure 48. H Gonzales CT1 and CT2 .................................................................................................................. 7-3
Figure 49. Palo Verde Nuclear Station ................................................................................................................ 7-4
Figure 50. Hoover Dam Hydroelectric Power Plant ............................................................................................ 7-4
Figure 51. Puente Hills Landfill Gas Plant .......................................................................................................... 7-5
Figure 52. Astoria II Solar Photovoltaic Facility ................................................................................................. 7-5
Figure 53. Antelope DSR 1 Solar PV Facility ..................................................................................................... 7-6
Figure 54. Desert Harvest 2 REC Solar PV Project ............................................................................................. 7-6
Figure 55. Daggett Solar PV and BESS Project ................................................................................................... 7-7
Figure 56. Market Purchases and Clean Energy Position until 2035 ................................................................... 8-3
Figure 57. RPS Position for Portfolio 1 ............................................................................................................... 8-4
Figure 58. RPS and Clean Energy Position for Portfolio 1 .................................................................................. 8-4
Figure 59. RPS Position for Portfolio 2 ............................................................................................................... 8-5
Figure 60. RPS and Clean Energy Position for Portfolio 2 .................................................................................. 8-5
Figure 61. RPS Position for Portfolio 3 ............................................................................................................... 8-6
Figure 62. RPS and Clean Energy Position for Portfolio 3 .................................................................................. 8-6
Figure 63. Optimal Supply Portfolio ................................................................................................................... 9-2
Figure 64. Resource Capacity Modeling Elements .............................................................................................. 9-4
Figure 65. Resource Costs: Wind, Solar, Geothermal ......................................................................................... 9-7
Figure 66. Resource Costs: Battery Energy Storage System ................................................................................ 9-7
Figure 67. Resource Costs: Hydrogen with Carbon Capture and Sequestration ................................................. 9-8
Figure 68. Greenhouse Gas Emissions Accounting Table (GEAT) for All Portfolios ...................................... 9-10
Figure 69. Summary of Modeled Portfolio Scenarios ........................................................................................ 9-11
Figure 70. Capacity Resource Accounting Table (CRAT): Portfolio 1 ............................................................. 9-13
Figure 71. Energy Balance Table (EBT): Portfolio 1 ......................................................................................... 9-14
Figure 72. Renewable Procurement Table (RPT): Portfolio 1 ........................................................................... 9-14
Figure 73. Clean Energy Contribution: Portfolio 1 ............................................................................................ 9-15
Figure 74. Capacity Resource Accounting Table (CRAT): Portfolio 2 ............................................................. 9-16
Figure 75. Energy Balance Table (EBT): Portfolio 2 ......................................................................................... 9-17
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Vernon Public Utilities 2023 IRP ix
Figure 76. Renewable Procurement Table (RPT): Portfolio 2 ........................................................................... 9-17
Figure 77. Capacity Resource Accounting T able (CRAT): Portfolio 3 ............................................................. 9-18
Figure 78. Energy Balance Table (EBT): Portfolio 3 ......................................................................................... 9-19
Figure 79. Renewable Procurement Table (RPT): Portfolio 3 ........................................................................... 9-19
Figure 80. 2030 Resource Capacity Mix ............................................................................................................ 9-20
Figure 81. 2045 Resource Capacity Mix ............................................................................................................ 9-20
Figure 82. Total Net Present Value Cost of Load for Each Portfolio ................................................................ 9-21
Figure 83. New Nameplate Annual Capacity Expansion for Portfolio 1 .......................................................... 10-3
Figure 84. Three-Day Dispatch Outputs Plotted against Load ........................................................................... C-4
Figure 85. ARS Schematic of Candidate Resource Expansion ........................................................................... C-5
Figure 86. PowerSIMM Simulation Engine ....................................................................................................... C-6
Figure 87. Multiple Simulations of Daily Maximum Dry Bulb Temperatures ................................................... C-8
Figure 88. Multiple Simulations of Load Over a Single Week .......................................................................... C-9
Figure 89. Load versus Temperature Relationships ............................................................................................ C-9
Figure 90. Multiple Simulations of Solar Generation Over a Single Week ...................................................... C-10
Figure 91. Multiple Simulations of Wind Generation Over a Single Week ..................................................... C-11
Figure 92. Multiple Simulations of Hydro Generation Over a Single Week .................................................... C-12
Figure 93. Multiple Simulations of Forward Prices .......................................................................................... C-13
Figure 94. Simulations for Spot Prices Over a Single Week ............................................................................. C-14
Figure 95. Stakeholder Survey Flyer with QR Code .......................................................................................... E-4
Figure 96. Question 1: Stakeholder Demographic Responses ............................................................................ E-5
Figure 97. Question 2: Electric Services Satisfaction Responses ........................................................................ E-5
Figure 98. Question 3: Electric Service Ranking Responses ............................................................................... E-6
Figure 99. Question 4: Rates or Reliability Priority Responses .......................................................................... E-6
Figure 100. Question 5: RPS Compliance Responses........................................................................................... E-7
Figure 101. Question 6: RPS Increase Rate Impact Responses ............................................................................ E-7
Figure 102. Question 7: Green Efforts Ranking Responses .................................................................................. E-8
Figure 103. Question 8: DER Penetration Impacts Responses ............................................................................. E-8
Figure 104. Question 9: MGS Energy Supply Responses ..................................................................................... E-9
Figure 105. Question 10: MGS Investment Ranking Responses .......................................................................... E-9
Figure 106. Question 11: MGS Investment Rate Impact Responses .................................................................. E-10
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Vernon Public Utilities 2023 IRP x
TABLES
Table 1. VPU Historic Customer Count ........................................................................................................... 2-9
Table 2. Renewable Portfolio Standard Percent Goals and Target Years ........................................................ 3-6
Table 3. RPS Compliance Period Procurement Quantity Formulas ................................................................ 3-7
Table 4. Flexible Resource Adequacy Categories........................................................................................... 3-19
Table 5. Flexible Resource Adequacy Capacity Requirements: 2023 ............................................................. 3-20
Table 6. Resource Adequacy Capacity: 2023 ................................................................................................. 3-21
Table 7. Historic Annual Peak Demand and Load .......................................................................................... 4-3
Table 8. Annual Peak Demand Forecast (MW) ............................................................................................... 4-7
Table 9. Annual Energy Forecast (MWh) ........................................................................................................ 4-8
Table 10. Rooftop Solar PV Historical and Forecast Installation Capacity and Energy Forecast ...................... 4-9
Table 11. Plug-In Electric Vehicle Adoption Forecast and Load Impacts ........................................................ 4-15
Table 12. Peak Demand, Energy, and GHG Emission Impacts of ZEV Penetration ...................................... 4-16
Table 13. Annual Electricity Savings Targets with Adjustments (GWh) ........................................................... 5-1
Table 14. Cumulative Historical Energy Efficiency Savings: Fiscal Years 2014–2022 ....................................... 5-4
Table 15. Historical Lighting Incentive Program Savings: Fiscal Years 2018 –2022 .......................................... 5-4
Table 16. Net Incremental Market Demand Potential By Sector ....................................................................... 5-5
Table 17. Net Incremental Market Energy Potential By Sector ......................................................................... 5-6
Table 18. Net Incremental Market Potential – Base And Codes and Standards ................................................ 5-7
Table 19. Laguna Bell-Mesa #1 230 kV Line Rating Increase Summary ........................................................... 6-3
Table 20. Five-Year Capital Improvement Plan Budget .................................................................................... 6-7
Table 21. Current VPU Owned and Contracted Generation Resources ............................................................ 7-1
Table 22. REC Generation by Resource in 2022 ................................................................................................ 8-2
Table 23. Average Cost of RPS -Compliant, Clean Energy, and Storage Resource Portfolio Options ............... 9-6
Table 24. Capacity Expansion Action Plan until 2035 ..................................................................................... 10-3
Table 25. Capacity Expansion Action Plan from 2035 until 2045 .................................................................... 10-4
Table 26. Energy Efficiency Potential Forecast ................................................................................................ 10-5
Table 27. Distribution System Action Plan Items ............................................................................................ 10-8
Table 28. IRP Guidelines Cross-Reference ....................................................................................................... A-3
Table 29. Annual Energy Forecast with Modifiers (MWh).............................................................................. D-2
Vernon Public Utilities 2023 IRP 1-1
1. Executive Summary
Founded as an exclusively industrial city, the City of Vernon (City) is a vital economic engine,
supplying necessary goods across the state, country and globally. The City is comprised of 5.2
square miles located southeast of downtown Los Angeles in Southern California, supporting
over 1,900 businesses that employ a workforce from neighboring cities of approximately
55,000 people.
As such, Vernon Public Utilities (VPU) is an essential resource for the City’s ever-growing and
evolving business community. VPU’s principal responsibility and core mission is to serve its
predominantly commercial and industrial customer base with high-quality, reliable
competitive and stable utility rates while providing extremely responsive customer service. To
achieve these goals, VPU must procure sufficient resources to meet current and future
customer needs while complying with state requirements for capacity and renewable and clean
energy generation.
VPU’s 2023 Integrated Resource Plan (IRP) comprises four founding pillars (Figure 1): a
reliable and resilient electric grid, sustainable generation, a prudent and equitable transition to
clean energy, and competitive and stable rates for its customers.
Figure 1. Four Foundational Pillars of the IRP
The 2023 IRP is a comprehensive document that outlines the City’s plan to meet its customers’
needs and comply with statutory requirements. The IRP utilizes VPU’S current daily
operations as a planning starting point. It also forecasts the City’s future capacity and energy
needs and identifies and evaluates renewable and clean energy resources to meet those needs.
In addition, the IRP provides an overview of numerous state laws and regulatory requirements
that the City must meet.
1
Keep the lights on
and recover quickly
in emergencies
Reliability and Resiliency
Ensure all Vernon
resident s benefit
from the transit ion to
a cleaner grid
Equitable Transition
Reduce GHG and air
pollution from
elect ricity supply
Sustainability
Electricit y must be
universal and
affordable to support
the city’s economy
Affordability
1. Executive Summary
Complying with Clean Energy and Customer-Centric Goals
Vernon Public Utilities 2023 IRP 1-2
The IRP chronicles an extensive research, forecasting, and planning process that VPU
performs daily to make critical decisions and execute action plans needed to satisfy statewide
requirements and customer needs.
COMPLYING WITH CLEAN ENERGY AND CUSTOMER-CENTRIC
GOALS
VPU developed this IRP by employing an integrated planning approach that considers various
key goals and strategies. As a result, the implementation of this IRP:
▪ Supplies reliable and affordable energy to meet the expected increasing energy needs of
VPU’s customers through a diversified resource portfolio to meet demand with supply.
▪ Procures adequate renewable generation to meet the state’s 60 percent Renewable Portfolio
Standard (RPS) by 2030 (as mandated by Senate Bill (SB) 350 and updated by SB 100).
▪ Achieves a 100 percent zero-carbon generation portfolio by 2045 (also mandated by
SB 100), with interim goals of 90 percent zero-carbon generation by 2035 and 95 percent
zero-carbon generation by 2040 (as mandated by SB 1020).
▪ Reduces greenhouse gas (GHG) emissions by 40 percent from 1990 levels by 2030 (as
mandated by SB 350) and by 85 percent from 1990 levels by 2045 (as mandated by
AB 1279).
▪ Complies with California Independent System Operator’s (CAISO) Resource Adequacy
(RA) Program requirements to ensure safe and reliable electric service.
▪ Facilitates the adoption of distributed energy resources (DERs), primarily by subsidizing
customer-sited rooftop solar photovoltaic (PV) and storage systems.
▪ Ensures baseload local generation to maintain system reliability.
▪ Identifies a strategic plan for increasing energy savings through energy efficiency measures
and demand-side management (DSM) programs.
▪ Reviews the feasibility of utilizing battery energy storage systems (BESS).
▪ Advances the transition for transportation electrification by developing on-site and public
electric vehicle (EV) charging infrastructure.
▪ Supports the transition to building electrification.
▪ Fosters economic, social, and electric rate benefits for low-income customers and
disadvantaged communities (DACs).
The IRP considered two planning cycles:
▪ Short-term: from the present through 2030 when the RPS requirements must be met.
▪ Long-term: when GHG and zero-carbon requirements must be met.
1. Executive Summary
IRP Conclusions
Vernon Public Utilities 2023 IRP 1-3
Overall, the entire long-term planning period runs from 2023 through 2045.
Over the short term, the IRP demonstrates how VPU’s resource portfolio will be comprised of
at least 60 percent RPS-compliant renewable generation. Over the long term, the IRP
illustrates how VPU’s resource portfolio will be 90 percent zero-carbon by 2035, 95 percent
zero-carbon by 2040, and 100 percent zero-carbon by 2045.
While the primary focus of an IRP is resource acquisition and resource retirement
considerations, the IRP considers three other components: DER penetration, customer
engagement, and distribution system improvements. This IRP encourages the growth of
DERs, fosters customer engagement, and looks to improve the resiliency of the VPU
distribution system, all in keeping with VPU’s core mission. These four interrelated
components contain several subcomponents that VPU manages daily to ensure safe,
affordable, and reliable operations.
Together, these aforementioned components form the basis of an integrated planning
approach. A robust distribution system is a necessity for developing the two-way flow of
energy required with increasing penetration of DERs and behind-the-meter (BTM) local
battery storage. These factors will directly affect the bulk power system portfolio mix.
Transitioning to building and transportation electrification, including adding EV charging
stations across the city will result in higher electricity demand. Additional energy efficiency
measures stand to decrease the electric demand. The planning performed in the IRP takes into
account customer outreach, engagement, and feedback.
IRP CONCLUSIONS
The IRP considered several resources for inclusion in a preferred portfolio. These resources
included both renewable generation in the form of geothermal, solar PV, and wind, along with
clean energy generation, such as hydrogen, carbon capture and sequestration (CCS), BESS,
and nuclear. The IRP resulted in three portfolio scenarios: Portfolio 1, Portfolio 2, and
Portfolio 3. Each scenario was extensively and comprehensively modeled and analyzed.
The three portfolios revolve around the future status of the Malburg Generating Station
(MGS), which began commercial operation in 2005. VPU must reduce emissions generated at
MGS by 2030. The most favorable option for accomplishing this emissions reduction is to stop
operating one of MGS’s combustion turbines (CTs) to run in concert with its steam turbine
(ST) and operate the unit less frequently outside the summer months when the grid demands
the most electricity. Thus, starting in 2030, the model assumes that MGS will operate in a 1x1
configuration (one CT and one ST) with limited strategic dispatch in the off-peak months. In
2035, the model assumes that, after 30 years of operation, MGS is planned to stop operating to
1. Executive Summary
IRP Conclusions
Vernon Public Utilities 2023 IRP 1-4
help VPU meet the state’s renewable and clean energy requirements. When MGS stops
operating, VPU is expected to meet over 90 percent of its load with carbon free resources.
The 2023 IRP is expected to be updated in five years, however, the 2023 IRP can be updated
as necessary to respond to any number of evolving situations (such as emerging renewable
generation technologies; changing community needs; or sudden changes in regulatory,
financial, or operational policies). The action plans in the 2023 IRP are flexible and adaptable
to these factors and unforeseen changes, including any strategic and operational decisions
regarding MGS.
The Preferred Portfolio
Through production cost modeling simulation results identified Portfolio 1 as the preferred
portfolio because it is the least-cost, best-fit option. This portfolio combines wind, solar, and
energy storage resources to replace MGS. Solar and wind provide renewable diversity to the
portfolio, while a 4-hour battery energy storage system provides capacity. The results align
with cost projections for future resources: wind, solar, and a 4-hour BESS represent the least
cost option.
Figure 2 shows the
Capacity Resource
Accounting Table
(CRAT) for the
preferred portfolio. It
depicts the annual
peak capacity
requirements (in MW)
and contributions from
existing and future
resources to meet
them. The CRAT
depicts MGS
transitioning to a 1x1
configuration in 2030
and with no generation
from MGS in 2035.
Figure 2. Preferred Portfolio Capacity Resource Accounting Table (CRAT)
H. Gonzales 1 and 2 will continue to provide minimal natural gas generation during peak
hours.
1. Executive Summary
IRP Conclusions
Vernon Public Utilities 2023 IRP 1-5
Resources included in the CRAT include storage, thermal, hydro, nuclear, solar, wind, and
biomass. Resources that were not selected include hydrogen, geothermal, and CCS.
Figure 3 shows the
Energy Balance Table
(EBT) for the preferred
portfolio. It depicts the
annual energy needs
(in MWh) and the
amount procured from
each portfolio
resource. The capacity
expansion model
identified the need for
new energy storage to
come online in 2030 to
cover the capacity drop
from MGS’s transition
to a 1x1 operation and
Figure 3. Preferred Portfolio Energy Balance Table (EBT)
again in 2035 when MGS is expected to reach its life expectancy. H. Gonzales 1 and 2 will
remain online to provide minimal natural gas generation during peak hours.
Capacity Expansion Resource Mix
The IRP must create a path to meet the state’s RPS requirement in 2030 and the zero-carbon
generation requirements of 90 percent by 2035 and 95 percent by 2040.
Figure 4 depicts the VPU energy mix in 2030. This portfolio meets the 60 percent RPS
compliance requirements for 2030. Of that 60 percent, 53.54 percent comes from VPU
resources and the remaining 6.46 percent comes from REC purchases. Figure 5 depicts the
VPU energy mix in 2045. This complies with all RPS and zero-carbon requirements.
1. Executive Summary
IRP Conclusions
Vernon Public Utilities 2023 IRP 1-6
The percentage of solar PV and wind increases by approximately 60 percent between 2030 and
2045, while the amount of thermal generation diminishes to an infinitesimal level as
H. Gonzales 1 and 2 continue to provide minimal natural gas generation during peak hours.
Figure 4. 2030 Energy Mix Figure 5. 2045 Energy Mix
Rationale for the Preferred Portfolio Selection
In all three modeled portfolio scenarios, VPU would meet its RA Program requirement
through the entire long-term planning period. Meeting the RA requirements means that VPU
will continue to provide highly reliable service to its customers.
The actual capacity values of all resources, however, are determined by CAISO, in its annual
study. Therefore, the RA values shown in the CRAT for the preferred portfolio are based on
capacity accreditation projections that could be lower or higher than the actual values
experienced over time.
Portfolio 1 was chosen as the preferred option because the candidate resource options included
in the other two portfolios—geothermal and hydrogen—are estimated to be much more
expensive than 4-hour storage and solar resources. As such, total supply costs for Portfolio 2
and Portfolio 3 are higher than the total supply cost for Portfolio 1. These costs are a function
of the expected resource costs ten to fifteen years from now, which include a significant
amount of uncertainty and risk.
1. Executive Summary
IRP Conclusions
Vernon Public Utilities 2023 IRP 1-7
Acquisition Timeline
VPU looks to provide the industry’s best reliability, offer highly competitive and affordable
rates, and improve the lives along with supporting the livelihood of its customers, especially in
disadvantaged communities, during its twenty-plus year clean energy transition. VPU
currently has a long standing history of adding renewable resources to its portfolio.
The capacity expansion software begins replacing 72 MW of MGS generation with renewable
resources by 2030 and replacing the remaining 67 MW by 2035 when MGS is projected to stop
operating. During those years, the power purchase agreements (PPAs) for Puente Hills
Landfill Gas (10 MW), Astoria II Solar PV (30 MW), and Antelope DSR 1 Solar PV (25 MW)
are scheduled to expire.
VPU’s capacity
expansion consists of
adding, in the
aggregate, a
combination of
360 MW of solar PV,
80 MW of wind, and
380 MW of energy
storage over the entire
planning period.
Figure 6 shows the
amount of energy
storage, solar PV, and
wind that is planned to
be added.
Figure 6. New Nameplate Annual Capacity Expansion for the Preferred Portfolio
The first step in VPU’s action plan is to ensure that two new PPAs come online as contracted:
Daggett Solar PV plus BESS by the end of 2023 and Sapphire Solar PV plus BESS in 2026.
These new resources play a crucial role in VPU’s carbon reduction strategy and put VPU on
course to meet SB 1020’s future clean energy mandates.
1. Executive Summary
Cost Considerations
Vernon Public Utilities 2023 IRP 1-8
COST CONSIDERATIONS
The preferred portfolio identifies the lowest cost resource portfolio. The IRP is based upon
nominal cost estimates, financial costs, and capital forecasts, which represent current year costs
not adjusted for inflation. It is important to note many factors contribute to the overall electric
rates; generation costs are only one factor. Although these costs have a direct impact on
electric rates, the costs provide a high-level estimate and do not represent an actual cost of
service analysis and rate design study.
Figure 7 estimates the twenty-year net present value (NPV) cost (by MWh) of the three
modeled portfolio scenarios compared to the current total portfolio cost.
Figure 7. Total Net Present Value Cost of Load for Each Portfolio
These total NPV costs indicate that replacing MGS with wind, solar PV, and energy storage
through the preferred portfolio only results in a modest increase in estimated supply costs. The
cost of the geothermal and green hydrogen in the other two portfolios, however, is estimated to
result in much higher costs.
1. Executive Summary
Driving Factors for this IRP
Vernon Public Utilities 2023 IRP 1-9
DRIVING FACTORS FOR THIS IRP
The IRP process considered numerous statutory and regulatory driving factors to determine how
to meet generation needs, both in the short-term (until 2030) and in the long-term (until 2045).
These factors include the following:
▪ The statewide goal of reducing GHG emissions by 85 percent from 1990 levels by 2045.
Several statutes complement this overarching goal.
▪ SB 350 and SB 100 established an RPS goal that requires 60 percent of VPU’s customer
electricity load (excluding municipal load) be supplied by renewable energy. This includes
energy from solar, wind, biogas, geothermal, and small hydroelectric generation.
▪ SB 100 required all generation be derived from clean energy sources by 2045. SB 1020
added interim goals of 90 percent clean energy by 2035 and 95 percent by 2040. These
resources include nuclear generation (including small modular reactors) and large
hydroelectric.
▪ Savings from energy efficiency measures and DSM programs must be doubled from 2020
levels on a statewide basis by 2030 as mandated by SB 350.
▪ Vehicle transportation must continue to be electrified to comply with the Advanced Clean
Car II (ACC II) rule that forecasts the addition of over five million zero-emission vehicles
(ZEVs) by 2030. The rule states that all new cars and light trucks allowed on road or new
purchases should be ZEVs by 2035. To support ACC II, regulations require the permitting
process for private EV charging stations be efficient and streamlined.
▪ Building systems must be electrified in new buildings and major renovations. While the
regulations are still in flux, building electrification must be promoted and considered in
future energy needs.
▪ Customer adoption of DERs must continue to be promoted.
In addition, VPU conducted a 12-question survey to better understand the priorities of its
customers and stakeholders with regard to available services and the resource portfolio that
will generate the power they consume. In concert with the survey, VPU held three in-person
meetings with stakeholders to review the IRP process, discuss the survey results, and to present
the content and conclusions of the three prospective portfolios modeled for the IRP. VPU
presented its stakeholders with legislative and regulatory context, analytical insights, and
perspective into the IRP planning process.
These factors were critical considerations in the planning, input, modeling, analysis, and
development of the 2023 IRP. Furthermore, VPU utilized these factors in selecting a preferred
generation portfolio to meet forecasted energy needs and develop an action plan to implement
the IRP findings.
1. Executive Summary
Transmission and Distribution Upgrades
Vernon Public Utilities 2023 IRP 1-10
TRANSMISSION AND DISTRIBUTION UPGRADES
The City of Vernon has limited real estate to site additional generation resources. Thus, a
robust transmission system is necessary to import the renewable and zero-carbon resources
necessary to reliably satisfy demand while meeting state energy and environmental goals.
Toward that end, VPU is benefiting from upgrades to the Laguna Bell-Mesa and the
Lighthipe-Mesa 230 kV transmission lines, as well as upgrades to the Laguna Bell substation
(owned by Southern California Edison) and the repowering of the Huntington Beach
transmission line. These upgrades mitigate three levels of power loss contingencies (P3, P6,
and P7) and increase each transmission line’s capacity.
Locally, VPU has just completed a $25 million Capital Improvement Plan (CIP), upgrading
the aging distribution system to increase its load carrying capacity and increase system
reliability.
Actions that are part of the upcoming Five-Year CIP include the following:
▪ Continue to replace and upgrade distribution infrastructure to increase capacity, maintain
system reliability, and system resilience.
▪ Implement additional distribution system automation by installing intelligent line switches
and automatic reclosers to improve VPU’s smart grid and diminish the impact of electric
system outages on customers.
▪ Upgrade line conductors, transformers, and complete voltage conversions at electric
substations to foster higher reliability and increase capacity.
▪ Replace obsolete and aging circuits, cables, and relays with state-of-the-art technology.
▪ Proactively replace utility poles in a strategic manner.
▪ Perform system undergrounding in conjunction with development and City projects for
improved system reliability.
These efforts provide VPU the opportunity to engage with various commercial and industrial
customers interested in increasing their existing capacity to serve expanding demand, and
electrifying their fleet by installing EV charging infrastructure. In addition, the City and VPU
are actively transitioning toward a clean commerce future that includes adding mixed-use
customer developments and increase residential housing options.
VPU plans to implement these upgrades and improvements throughout the course of this IRP
planning cycle and plans to complete them, and all other resource planning actions, by the
next IRP cycle in five years.
Vernon Public Utilities 2023 IRP 2-1
2. Background and Planning Goals
Vernon Public Utilities, an integrated part of the City of Vernon, consists of a dedicated team
committed to providing essential services that contribute to this vibrant community’s overall
well-being and functionality.
The City of Vernon is a primarily industrial city of 5.2 square miles located just to the
southeast of Downtown Los Angeles in Southern California. The City’s business-friendly
environment, low-cost utilities, and proximity to ports, trucking, and rail transport make
Vernon an ideal location for industrial uses. VPU serves about 1,900 mainly commercial and
industrial electric customers with electric sales of approximately 1,151 GWh annually and
peak loads of approximately 189 MW in the summer and 174 MW in the winter.
VPU rates for the larger commercial and industrial classes, such as TOU-V and TOU-Vt, are
extremely competitive, including comparisons with the Los Angeles Department of Water and
Power and Southern California Edison. The utility has a mission to offer the lowest rates in
California by 2030.
VPU’s electric system includes generation and distribution facilities that are completely located
within VPU’s electric service territory in the LA Basin. VPU does not own or operate any
transmission facilities. VPU has two generation facilities within VPU service territory. MGS is
a 139 MW combined-cycle natural gas-fired plant and two H. Gonzales units is a combined
11.5 MW natural gas plant. VPU has 119 miles of distribution lines and 27 miles of 66 kV
sub-transmission lines.
THE INCEPTION OF THE INTEGRATED RESOURCE PLAN
On October 7, 2015, the California Senate passed Senate Bill (SB) 350, the Clean Energy and
Pollution Reduction Act. This legislation required a dramatic reduction in greenhouse gas
(GHG) emissions, fundamentally altering how electricity consumed within the state was
generated.
Among its numerous provisions, the bill required the California Public Utilities Commission
(CPUC) to adopt a process for Investor-Owned Utilities (IOUs), Community Choice
2. Background and Planning Goals
About This IRP
Vernon Public Utilities 2023 IRP 2-2
Aggregators (CCAs), and Electric Service Providers (ESPs) to file an Integrated Resource Plan
(IRP) to:
▪ Meet the GHG emissions reduction targets established by the California Air Resources
Board (CARB) for the electricity sector.
▪ Procure at least 50 percent eligible renewable energy resources by December 31, 2030,
consistent with the RPS. (The RPS requirement was raised to 60 percent in 2018.)
▪ Minimize impacts on ratepayers’ bills.
▪ Ensure system and local reliability.
▪ Strengthen the diversity, sustainability, and resilience of the bulk transmission and
distribution systems and local communities.
▪ Enhance distribution systems and demand-side energy management.
▪ Require Publicly-Owned Utilities (POUs) to adopt IRPs according to similar standards,
subject to review by the California Energy Commission (CEC).1
The bill also required a diversified procurement portfolio consisting of both short-term and
long-term electricity, electricity-related programs, and demand response products.
The CEC’s publication, Publicly Owned Utility Integrated Resource Plan Submission and Review
Guidelines, Revised Third Edition, which was last updated in August 2022, details twelve main
areas of compliance, and included filing and review procedures.
ABOUT THIS IRP
The VPU 2023 Integrated Resource Plan presents a comprehensive 20-year strategy that
outlines how the City of Vernon plans to continue to meet the electric service needs of
customers with reliable and environmentally responsible energy development and procurement
at competitive and stable rates. It outlines how VPU plans to not only meet these energy and
capacity needs, but also comply with various regulatory and statutory initiatives to generate
clean energy, consider physical and operational constraints, and meet other state and local
priorities.
The IRP outlines a process for charting a resource acquisition strategy that balances supply and
demand. It favors procuring reliable, affordable, renewable, and zero-carbon energy balanced
against forecasted growth, and coupled with transportation and building electrification
demands, energy efficiency and demand-side management initiatives, and DERs.
1 https://trackbill.com/bill/california-senate-bill-350-clean-energy-and-pollution-reduction-act-of-2015/1126101/
2. Background and Planning Goals
About This IRP
Vernon Public Utilities 2023 IRP 2-3
Figure 8 depicts this balance of demand with supply.
Figure 8. IRP Balances Demand with Supply
The foundation of the 2023 IRP is based on maintaining and improving the utility’s ongoing
commitment to excellence: its generation and distribution systems continue to rank among the
most reliable nationwide.
The Goal of the IRP
VPU developed this IRP by implementing an integrated approach that considered several key goals
and strategies. It details a forward-looking view of available resource options and a plan that:
▪ Supplies reliable and affordable energy to customers through a diversified resource portfolio
to meet demand with supply.
▪ Achieves the 2030 target of 60 percent RPS by procuring adequate renewable generation, as
mandated by SB 350 and updated by SB 100.
▪ Achieves a 100 percent zero-carbon generation portfolio by 2045, also mandated by SB 100,
with interim goals of 90 percent zero-carbon generation by 2035 and 95 percent zero-carbon
generation by 2040 as mandated by SB 1020.
▪ Reduces GHG emissions by 40 percent from 1990 levels by 2030 as mandated by SB 350.
▪ Ensures adequate baseload local generation after 2028 to maintain system reliability.
▪ Identifies a strategic plan for increasing energy efficiency savings.
▪ Facilitates the adoption of DERs.
▪ Addresses the integration of battery energy storage systems (BESS).
▪ Supports the transition to transportation and building electrification.
▪ Fosters economic, social, and electric rate benefits for low-income residents and
neighboring disadvantaged communities.
▪ Ensures compliance with all statutory and regulatory requirements.
2. Background and Planning Goals
About This IRP
Vernon Public Utilities 2023 IRP 2-4
Planning Horizon
The IRP serves as a roadmap for both short-term and long-term decisions. It encompasses a
short-term planning period through 2030 when the 60 percent RPS goal must be achieved, and
a long-term planning period through 2045 when the 100 percent zero-carbon portfolio mandate
must be achieved. Figure 9 depicts a roadmap for complying with state requirements for
procuring renewable and zero-carbon clean energy.
Figure 9. IRP Roadmap of Resource Compliance
The culmination of the IRP is an action plan to be implemented over the next five years with
an eye toward attaining long-term goals.
Four Components of the IRP Planning Process
While the primary focus of an IRP is resource acquisition, the IRP focuses on three other
components of its operations: DER penetration, customer engagement, and distribution
system improvements. This focus encourages the growth of DERs, fosters customer
engagement, and improves the resiliency of the VPU distribution system, all in keeping with
VPU’s core mission.
2. Background and Planning Goals
About This IRP
Vernon Public Utilities 2023 IRP 2-5
Figure 10 depicts the elements of the four main components of the IRP.
Figure 10. Four Components of the IRP Process
These four interrelated components form the basis of an integrated planning approach. A
robust distribution system is a necessity for developing the two-way flow of energy required
with increasing penetration of DERs and behind-the-meter (BTM) local battery storage. The
increased penetration of DERs directly affects the bulk power system portfolio mix.
Transitioning to building and transportation electrification, including the development of EV
charging stations across the city, results in higher demand. Implementation of energy efficiency
measures decreases demand. VPU’s short- and long-term planning approach considers
customer outreach and their resultant input.
While the next IRP is not due for another five years, the 2023 IRP can be updated as necessary
in the interim to respond to any number of evolving situations (such as emerging renewable
generation technologies; changing community needs; or sudden changes in regulatory,
financial, or operational policies). The action plans in the VPU 2023 IRP are flexible and
adaptable to these and other unforeseen changes, including any strategic and operational
decisions regarding the status of MGS.
VPU’s Approach for Creating the IRP
Ensuring adequate resources to meet current and future demand is at the heart of the IRP. The
IRP informs a process for implementing a short- and long-term resource acquisition strategy.
The process for creating the IRP was based on evaluations of several key areas:
2. Background and Planning Goals
About This IRP
Vernon Public Utilities 2023 IRP 2-6
Internal Considerations. Existing resources; distribution system; resource portfolio; physical
and operational constraints; and current energy efficiency, demand response, and demand-side
management measures.
External Considerations. Applicable statutory and regulatory requirements, stakeholder
input, and potential current and emerging resource technologies including energy storage and
DERs, and transmission system constraints.
Generation Resources. Solar, wind, hydroelectric, geothermal, biogas and biomass, battery
storage, nuclear, and natural gas.
Various Inputs. Reliability standards, risk management policies, rates, and financial incentives
and goals.
Forecasts. Demand, energy, transportation electrification, building electrification, cost of
service, and how they contribute to resource adequacy.
Increasing amounts of variable renewable energy impacts the ability to provide adequate
dispatchable baseload and load-following generation. VPU contracted with Ascend Analytics
to design potential future scenarios that encompass various resource mixes. Ascend then
modeled and analyzed the different scenarios to arrive at a preferred portfolio of resources to
procure. The preferred portfolio examined the amount, timing, and type of sustainable
resources that can provide the energy needs of VPU’s customers at the lowest reasonable cost
while meeting sustainability and reliability requirements.
Ascend designed and modeled three potential future resource portfolios that can meet these
requirements. To varying degrees, the IRP employed an integrated approach for assessing
resource investment tradeoffs and stranded risk possibilities to ensure reliability, environmental
stewardship, statutory and regulatory compliance, and rate considerations.
During the planning process, VPU engaged its stakeholders as a means of seeking guidance
and direction on key decisions for preferred portfolios of generation, demand, and distributed
resources.
The strategic outcome is a power supply transition roadmap that enables VPU to evaluate and
update various power supply objectives. The resultant preferred portfolio incorporates a
prudent mix of generation, distribution, and transmission resources together with energy
efficiency measures balanced against reliability, sustainability, and financial goals to meet the
energy needs of its customers now and over the next two decades. Over time, VPU’s power
supply requirements and related costs will continue to evolve.
The IRP ensures timely resource investments that maintain a reliable power system. VPU
intends to implement the IRP together with its Capital Improvement Plan and other forward-
looking management plans, including a cost of service analysis and rate design study, to ensure
supply reliably meets demand at competitive and stable rates.
2. Background and Planning Goals
Outcomes from 2018 IRP Recommendations
Vernon Public Utilities 2023 IRP 2-7
The IRP complies with California Public Utilities Code (PUC) Section 9621 and the Publicly
Owned Utility Integrated Resource Plan Submission and Review Guidelines, Revised Third Edition
issued by the CEC in August 2022. These guidelines dictate the content of an IRP and require
VPU to file an IRP at least every five years.
OUTCOMES FROM 2018 IRP RECOMMENDATIONS
Among several options, the 2018 IRP recommended diversifying VPU’s resource mix by
procuring a cumulative total of 93 megawatts (MW) of solar capacity by 2027, 27 MW of wind
capacity in 2025, 20 MW of geothermal capacity in 2029, and an additional 1 MW per year of
energy storage starting in 2023 with an increase of 15 MW more in 2029. Recommended solar
procurement was for 65 MW in 2021, 20 MW in 2023, and 8 MW in 2026. One other
recommendation was for VPU to develop a plan to accommodate the additional 1.7 MW of
load due to a forecasted increase in EV penetration and charging requirements.
In the last five years, VPU has signed power purchase agreements (PPAs) for two solar
facilities: Daggett Solar for 60 MW of nameplate capacity with a commercial operation date
(COD) of December 20, 2023, and Sapphire Solar for 39 MW of nameplate capacity with a
COD of December 31, 2026. As part of these PPAs, VPU will acquire a total of almost
50 MW of 4-hour Lithium-Ion battery energy storage: 30 MW from Daggett and 19.67 MW
from Sapphire, far surpassing the recommended 5 MW by 2027. Procuring the recommended
wind and geothermal resources has yet to be realized due to their current cost prohibitive
pricing.
In late 2021, VPU repurchased the MGS from Bicent Power LLC, which allows VPU to use
the plant more efficiently depending on operating and market conditions.
In the interim, VPU added more than 40 EV charging stations for city employees and the
municipal fleet. As of May 2023, daily peak usage has been 80 kilowatts (kW). VPU expanded
its EV charging infrastructure with the following projects:
▪ One publicly available Level 3 (L3) charging depot that opened in July 2023, equipped with
ten ChargePoint direct current fast chargers (DCFCs) and eight Tesla V3 Superchargers.
▪ 43 Level 2 (L2) EV chargers installed at Vernon City Hall, available to employees, the city
fleet, and the public.
▪ One more publicly available L3 charging depots is currently under development, which will
also be equipped with DCFCs and Tesla V3 Superchargers. The site is scheduled to be
completed in calendar year 2024.
As of May 2023, the peak charging usage was 80 kW with a maximum daily usage of 674 kW.
2. Background and Planning Goals
About Vernon Public Utilities
Vernon Public Utilities 2023 IRP 2-8
VPU’s publicly available EV fast charging depots also help address the lack of DCFCs in
disadvantaged communities (DACs), as defined under CalEnviroScreen criteria. The
California Office of Environmental Health Hazard Assessment created the CalEnviroScreen
criteria to help CalEPA identify disadvantaged communities based on geographic,
socioeconomic, public health and environmental hazard criteria, as required by SB 535. All of
the current and proposed depots are close to several major interstate and intrastate highways.
As a result, Vernon’s public EV charging depots provide the necessary infrastructure to support
battery electric vehicles in the Gateway Cities region and help encourage the adoption of zero
ZEVs in underserved communities.
ABOUT VERNON PUBLIC UTILITIES
Throughout the years, Vernon Public Utilities has remained steadfast in its mission: to provide
its customers with reliable, safe, and affordable energy in a manner consistent with California’s
progressive, cleaner energy goals.
VPU continues to build a resilient, full-
service utility that meets the energy
challenges and capitalizes on emerging
technologies and strategic opportunities.
In addition to electric services, VPU
provides water, gas, and fiber optic
services. VPU operates in a financial and
environmentally responsible manner while
remaining dedicated to reliability, safety,
sustainability, and affordability through a
customer-focused vision. As a publicly
owned utility, VPU’s stakeholders are its
customers, residents, current and
prospective property and business owners, property developers, business employees and
customers, the Business and Industry Commission, the Vernon Green Commission, the
Vernon Chamber of Commerce, the City Council, and commissioners.
VPU is a steward of the Vernon community. With Vernon City Council acting as its governing
board, local control affords the utility the opportunity to offer critical advantages to VPU’s
customers: transparency of governance; competitive and stable rates; the opportunity to tailor
utility policies, create beneficial programs, and have a voice in the utility decision-making
process, all to serve community priorities. The City Council and City Administration take a
leadership role in supporting the efforts expended by VPU staff. VPU is committed to
2. Background and Planning Goals
About Vernon Public Utilities
Vernon Public Utilities 2023 IRP 2-9
partnering with the local community in shaping and constructing a sustainable energy future
for the City of Vernon.
Customer Base
A key feature that makes VPU unique is a customer base that is predominantly comprised of
commercial and industrial businesses. Over the past decade, the breakdown of customers and
the total number of customers has remained relatively the same. Since 2012, VPU’s customer
count has increased a modest 1.64 percent (see Table 1) while energy consumed by those
customers has grown at a similar rate of 1.57 percent.
Customer 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Residential 28 28 28 28 74 74 74 74 74 74 74
Commercial 1,168 1,182 1,191 1,205 1,210 1,210 1,218 1,223 1,231 1,238 1,262
Industrial 600 591 573 558 555 539 531 524 514 503 503
Municipal 100 98 97 96 95 93 93 94 93 90 88
Total 1,896 1,899 1,889 1,887 1,934 1,916 1,916 1,915 1,912 1,905 1,927
Table 1. VPU Historic Customer Count
For most electric utilities, a majority of their customer base is comprised of residential
customers. However, at VPU, an overwhelming majority of the customers fall under the
commercial and industrial segment.
VPU serves approximately 1,900 commercial and industrial accounts, with a service territory
home to manufacturing and production employing close to 55,000 skilled workers. The
primary industries found within the City of Vernon include food service distribution and
manufacturing, glass and plastic equipment manufacturing, and metalworking. About half of
Vernon’s residents live in city-owned housing and are employed by private businesses within
the city. In 2015, VPU’s residential accounts more than doubled after the city opened its first
privately-owned apartment complex.
While commercial and industrial customers make up almost 92 percent of VPU’s electricity
accounts, they also consume over 99 percent of its demand and energy sales. In addition, VPU’s
customer base includes many industrial and commercial businesses have been in Vernon for
many decades. Some of VPU’s largest customers average over 31 years of operations in the city.
2. Background and Planning Goals
About Vernon Public Utilities
Vernon Public Utilities 2023 IRP 2-10
Figure 11 shows VPU’s customer breakdown, while Figure 12 shows the energy consumed by
each customer category. All amounts are from 2022.
Figure 11. VPU Customer Count Figure 12. VPU Energy Consumed
VPU customers consumed 1,150.6 GWh of energy in 2022, with a winter peak load of
174 MW and summer peak load of 189 MW. The proximity of VPU’s summer and winter
peak loads results in an annual load factor over 70 percent, with a large industrial customer
base as a major contributing factor.
Award Winning Grid Reliability and Service
The American Public Power Association (APPA) designates Reliable Public Power Provider
recognition (RP3) to utilities that demonstrate exceptional proficiency in four key areas: safety,
reliability, workforce development, and system improvement. Consistent with its mission,
VPU strives for excellence in these areas.
APPA has awarded VPU its highest, Diamond Level, RP3 designation for three consecutive
terms, encompassing nine years from 2016–2019, 2019–2022, and 2022–2025. VPU earned
these honors by providing exceptionally reliable and safe electric service. VPU is one of only
26 of the more than 2,000 public power utilities across the United States to achieve Diamond
Level RP3 designation for the period of 2022–2025.
APPA also awarded VPU the Safety Award for Excellence in 2022 as there were no reportable
safety incidents. In addition, the City of Vernon earned a Tree City USA Designation in 2019,
2020, and 2021—one of only 3,500 communities in the nation to be named.
2. Background and Planning Goals
About Vernon Public Utilities
Vernon Public Utilities 2023 IRP 2-11
Membership in SCPPA
VPU is a member of the Southern California Public Power Authority (SCPPA). SCPPA is a
Joint Powers Authority, created in 1980, to provide joint planning, financing, construction,
and operation of transmission and generation projects. Comprised of eleven municipal utilities
and one irrigation district, SCPPA’s members serve more than 5 million Californians across a
service area of 7,000 square miles. SCPPA members supply 16 percent of California’s power.
SCPPA’s twelve members are:
Anaheim Public Utilities Department Burbank Water and Power
Azusa Light & Water City of Banning
Cerritos Electric Utility City of Colton
Vernon Public Utilities Glendale Water and Power
Imperial Irrigation District Los Angeles Department of Water & Power
Pasadena Water and Power Riverside Public Utilities
SCPPA members continue to seek new energy solutions to meet the clean energy goals set by
the state of California. Today, each member delivers energy through a combination of fuel
sources and renewable generation, offset by energy efficiency measures, to meet the diverse
needs of their customers and to comply with state mandates. The biggest benefit of SCPPA is
economies of scale, joint procurement at lower overall cost and understanding lessons learned
from other POU’s.
VPU derives several benefits from its SCPPA membership.
Decarbonization. SCPPA champions decarbonization efforts for its member communities
through collective projects, programs, and services to meet sustainability goals while
maintaining reliability, low costs, and local control.
Emerging Issues. SCPPA helps members thrive and excel in the long term by exploring
technological and operational solutions to emerging industry challenges and opportunities.
Collaboration. SCPPA fosters collaboration and professionalism with its working groups to
maximize its value to members and the communities they serve.
Assets. SCPPA is a trustworthy steward of public funds through responsible administration of
financial and physical assets and obligations.
Advocacy. SCPPA emphasizes the unique needs of member communities by facilitating
proactive advocacy.
2. Background and Planning Goals
Stakeholder Outreach Efforts
Vernon Public Utilities 2023 IRP 2-12
Energy Resource Mix
VPU’s generation portfolio continues to evolve with state mandates for renewable energy and
zero carbon generation. Vernon participates in the CAISO wholesale energy markets under a
metered subsystem agreement (MSSA). Five years ago, approximately 59 percent of VPU’s
energy resource mix was supplied by natural gas generation from MGS and market purchases.
The remaining energy came from 7.7 percent nuclear, 1.6 percent large hydroelectric, and
approximately 32 percent renewables.
VPU’s energy mix for 2024 is depicted in Figure 13.
Generation from natural gas
has been reduced to
32.2 percent (from 59 percent)
of VPU’s portfolio while
renewable generation has
increased to 43.4 percent
(from 31 percent). This
renewable generation
comprises 29.0 percent solar,
3.1 percent biomass, and
11.3 percent renewable
energy credits (RECs). In
addition to renewable
Figure 13. 2024 Energy Resource Mix
generation resources, the 7.7 percent nuclear and 1.6 percent hydro are both zero-carbon
resources.
One of VPU’s central goals of the 2023 IRP is to increase its renewable generation penetration
to 60 percent by 2030 as directed by California statute.
For a detailed discussion about generation requirements as directed by statute, refer to
“California Policy Requirements” on page 3-1 and “Statewide Planning Considerations” on
page 3-11. For specific generation resources, refer to “Resource Portfolio Overview” on
page 8-1.
STAKEHOLDER OUTREACH EFFORTS
VPU expends a considerable amount of time and energy on stakeholder outreach by engaging
its customers through in-person stakeholder meetings and comprehensive surveys to foster
transparency, inform stakeholders about the IRP process, and garner input for developing the
IRP. The outreach aimed to inform stakeholder of the major issues facing VPU and to
2. Background and Planning Goals
Stakeholder Outreach Efforts
Vernon Public Utilities 2023 IRP 2-13
gather valuable insights about how these issues can be addressed. Outcomes from these
meetings and results from the survey helped shape the different portfolio scenarios considered
and acted as a guide to inform the decision making process.
VPU’s stakeholders include city residents, current and prospective property and business
owners, property developers, business employees and customers, the Business and Industry
Commission, the Vernon Green Commission, the Vernon Chamber of Commerce, the City
Council, and commissioners—essentially the entire Vernon community.
Principal Results. Through stakeholder meetings and the survey results, Vernon customers
made clear that their top two priorities are reliable electric service and low rates, with an
emphasis on reliability.
Stakeholder Meetings
To engage VPU stakeholders directly, VPU held three in-person stakeholder meetings. VPU
and Ascend Analytic representatives gave a presentation at each meeting and facilitated a
discussion with attendees. All three meetings took place at the Council Chambers in Vernon
City Hall. The Green Vernon Commission, Business and Industry Commission, and
community members attended all three meetings.
The first stakeholder meeting was held on March 15, 2023. The meeting’s presentation
introduced the IRP process, statutory requirements, deadlines, and the IRP’s goals. An
overview of VPU’s current resource portfolio, along with a stakeholder survey requesting
valuable attendee feedback was also included.
The second stakeholder meeting was held on May 11, 2023. The meeting’s presentation
detailed the results of the stakeholder survey, key insights, discussion regarding VPU’s
current/future renewable contracts, overview of the different portfolio scenarios and available
resource options for capacity expansion.
The third and final stakeholder meeting was held on June 21, 2023. The meeting’s presentation
reviewed the IRP process and Ascend’s capabilities, the modeling process, details regarding the
three modeled scenarios and associated costs.
Attendees were allowed the opportunity to comment and share their thoughts on the IRP
process. VPU incorporated the stakeholder feedback into the IRP analysis and utilized
stakeholder feedback to select the preferred resource portfolio.
VPU Stakeholder Survey and Results
VPU conducted a 12-question survey to better understand customer thoughts regarding
priorities about reliable power, affordable rates, renewable generation, EV charging, DERs,
2. Background and Planning Goals
Stakeholder Outreach Efforts
Vernon Public Utilities 2023 IRP 2-14
and MGS. VPU promoted the survey during stakeholder meetings community events, and
asked attendees for input. This feedback enabled the utility to make decisions about the IRP
and to gauge customer interest on essential factors that shape VPU’s energy future.
VPU created a webpage detailing the IRP process, included a frequently asked questions
(FAQs) page, and a link to the survey. The survey was available for approximately 2 months,
via link and QR code, which was displayed prominently on a survey flyer. (See Figure 95 on
page C-4 for a copy of the flyer.)
VPU publicized the survey through several outreach channels, including public meetings,
advertisements, social media platforms, printed mail, email, and phone calls. In addition, VPU
also leveraged its business partnerships and distribution of flyers at numerous community
events held throughout the city. (Refer to Appendix Stakeholder Survey and Results on page
C-3 for a more thorough list.) In total, VPU received a total of 126 survey responses.
Key Insights
Survey results indicate that the primary concern for VPU customers is maintaining system
reliability followed closely by offering affordable rates. VPU garnered several vital insights
from the survey responses.
▪ Over 80 percent of respondents were either satisfied or very satisfied with the service
provided by VPU.
▪ Over 80 percent of respondents ranked reliable electric service as one of the top two
priorities, with affordable rates being a close second.
▪ Over 70 percent of respondents do not believe VPU should exceed the state mandated RPS
target.
▪ Most respondents were very interested in more significant electrification incentives and
support for installing distributed generation and energy storage.
▪ Over 60 percent of community members were not aware of the capabilities of MGS.
▪ Over 37 percent of respondents expressed great interest in a further transition toward
electrification.
Refer to Appendix E. Stakeholder Outreach for in-depth information about the stakeholder
meetings as well as the questions and responses from the stakeholder survey.
Vernon Public Utilities 2023 IRP 3-1
3. Planning Drivers
Many external factors influence VPU’s operation and profoundly affect its long‑term resource
planning. As this operating environment continues to evolve, there can be a great deal of
uncertainty in resource acquisitions strategies and introduces a fair amount of risk. In
particular, external factors include:
▪ Emission-related legislation and regulations
▪ Renewable resource requirements
▪ Regional and global economic conditions
▪ Power market evolutions affecting supply and pricing
▪ VPU’s local planning priorities
▪ Advancement in technologies
Four main areas directly affect VPU’s operation: California policy requirements, statewide
planning considerations, regionalization evolution and risk, and cost of service and rate
impacts. Each is discussed at length in this chapter.
CALIFORNIA POLICY REQUIREMENTS
For almost two decades, the California legislature has introduced and passed several Assembly
Bills (ABs) and Senate Bills (SBs) to combat the impacts of climate change and mandate
substantial reductions in GHG emissions based on 1990 emission levels.
The series of bills set the foundation for all other subsequent legislations substantially altering
the operation of electric utilities across the state, and acted as planning drivers for the
development of VPU’s IRP. Most notably, the RPS mandate set levels for increasing the
amount of renewable and zero-carbon generation in VPU’s resource portfolio mix.
Other legislation complemented these mandates. These statutes include:
▪ Establishing incentives for customer-owned generation (mostly from rooftop solar
photovoltaic systems).
▪ Setting standards for cap-and-trade programs designed to lower GHG emissions.
3. Planning Drivers
California Policy Requirements
Vernon Public Utilities 2023 IRP 3-2
▪ Designing and maximizing the effects of energy efficiency measures and demand side
management programs funded through the Public Benefits surcharge.
▪ Building the necessary infrastructure for installing electric vehicle charging stations and
streamlining the permitting process.
▪ Simplifying the process for participating in energy storage markets.
Greenhouse Gas Emission Reduction Statutes
Several legislative statutes mandated
aggressive reductions in GHG
emissions with requirements set for
2020, 2030, 2045, and 2050.
Assembly Bill 32: California Global
Warming Solutions Act of 2006.
AB 32 required that aggregated GHG
emissions be reduced to the levels
measured in 1990 by 2020. CARB is
required to continue and coordinate
the overall climate change policies.
CARB is also required to monitor and
enforce compliance through a process
for utilities to report and self-verify its
emission reductions. CARB adopted
a regulation for the “Mandatory
Figure 14. Greenhouse Gas Emission Reduction Legislation
Reporting of Greenhouse Gas Emissions” and a “Cost of Implementation Fee Regulation”.
AB 32 also contained a provision for a cap-and-trade program (see page 3-8).
Senate Bill 350: Clean Energy and Pollution Reduction Act of 2015. Following passage of
SB 350 in 2015, the bill included a provision to set precise levels of GHG emission reductions:
40 percent of 1990 levels by 2030 and 80 percent of 1990 levels by 2050. Due to the substantial
impact of the bill’s provisions, SB 350 took effect in 2020, almost five years after it was signed
into law.
SB 350 also contained provisions for establishing RPS targets (page 3-4), increasing energy
efficiency (page 3-9), promoting transportation electrification (page 3-22), and taking steps to
implement a regionalization strategy in the Western Interconnection (page 3-24).
Senate Bill 32: California Global Warming Solutions Act of 2006 – 2030 Emissions Limit.
In 2016, SB 32 expanded the GHG emission reduction provisions implemented in AB 32 by
codifying the levels set in SB 350: reducing GHG emissions to 40 percent below 1990 levels by
2
Senat e Bill 350
(2015)
• GHG emissions 40% of 1990 levels by 2030
• GHG emissions 80% of 1990 levels by 2050
• Took effect in 2020
G H G B i l l s
Senat e Bill 32
(2016)
• Codified GHG emissions reduced to 40% below
1990 levels by 2030
• GHG emissions 80% of 1990 levels by 2050
• Cont ingent upon passing AB 197
Assem bly Bill 197
(2016)
• CARB priorit ized GHG emission reduct ions from
large sources
Assem bly Bill 1279
(2022)• GHG emissions 85% of 1990 levels by 2045
Senat e Bill 12
(2023)
• GHG emissions 55% of 1990 levels by 2030
• St ill being considered
Assem bly Bill 32
(2006)
• GHG emissions reduced to 1990 levels by 2020
• CARB adopted reporting and verification
regulat ions
3. Planning Drivers
California Policy Requirements
Vernon Public Utilities 2023 IRP 3-3
2030 and by 80 percent by 2050. CARB is responsible for ensuring that California meets this
goal.
Since the passage of SB 32, VPU has been reducing its reliance on the gas-fired generation that
produces GHG emissions in several ways: by transitioning to more renewable resources,
increasing energy efficiency, promoting local rooftop solar installations, and transitioning to
transportation and building electrification.
Assembly Bill 197: California Global Warming Solutions Act of 2006 – Direct Emissions.
AB 197 required CARB to adopt regulations to achieve the maximum amount of GHG
emission reductions in a cost-effective manner and to prioritize direct emission reductions from
large, stationary, and mobile sources.
To comply with AB 197, VPU has reduced overall GHG emissions through several
transportation electrification (see “Transportation Electrification Impacts” on page 4-13) and
energy efficiency initiatives.
Assembly Bill 1279: The California Climate Crisis Act of 2022. AB 1279 established a
statewide goal for achieving carbon neutrality within the next two decades. The bill furthered
GHG emission reduction goals by requiring an 85 percent reduction of 1990 levels no later
than 2045 and to continue that reduction into the future.
AB 1279 also contained a provision for an update to the RPS requirement (see page 3-5).
Senate Bill 12 of 2023. Introduced in late 2022 and still being debated, the bill sought to
decrease GHG emissions by changing the current goal of “40 percent reduction from 1990 by
2030” and replacing it with an aggressive target rate reduction of 55 percent.
3. Planning Drivers
California Policy Requirements
Vernon Public Utilities 2023 IRP 3-4
Renewable Portfolio Standard and Zero-Carbon Resources
California RPS Statutes
Five legislative statutes set various
targets for replacing carbon-fueled
generation with renewable and
zero-carbon resources by establishing
RPS targets starting in 2013 and
culminating in 2045, with a crucial target
in 2030.
Senate Bill X1–2: California
Renewable Energy Resources Act of
2011. This bill fundamentally modified
California’s RPS by setting three new
goals that apply to all retail electric
providers in the state, including POUs,
IOUs, ESPs, and
Figure 15. RPS and Zero-Carbon Target Legislation
CCAs. The bill defines compliant resources, establishes goals and minimum increases over
time for a specific percentage of retail sales, and specifies the location and delivery point for
renewable resources.
The RPS targets are:
▪ 20 percent of retail sales by year-end 2013.
▪ 25 percent of retail sales by year-end 2016.
▪ 33 percent of retail sales by year-end 2020 and thereafter.
VPU’s governing board, the City Council, must implement these requirements with the CEC,
with CARB having the specific enforcement authority.
Senate Bill 350: Clean Energy and Pollution Reduction Act of 2015. SB 350 called for a new
set of objectives to improve air quality and public health, reduce GHG emissions to address the
impacts of climate change, and expand other clean energy policies.
The bill was signed into law in 2015 and took effect in 2020. The bill established the
California’s renewable energy procurement goal of 33 percent by 2020 and 50 percent by 2030;
with the 50 percent target that must be maintained into the future. The bill includes an interim
goal of 40 percent RPS by 2024 and 45 percent RPS by 2027. Starting in 2021, at least
65 percent of RPS procurement must be derived from long-term contracts of 10 years or more.
The bill defined the renewable energy and zero-carbon sources that support the RPS goals.
Renewable energy includes generation from solar, wind, geothermal, small hydroelectric,
3
Senat e Bill X1–2
(2011)
Set three RPS targets:
• 20% of retail sales by year-end 2013
• 25% of retail sales by year-end 2016
• 33% of retail sales by year-end 2020 and onward
RPS Bills
Senat e Bill 350
(2015)
Set three more RPS t arget s t aking effect in 2020:
• 40% of retail sales by year-end 2024
• 45% of ret ail sales by year-end 2027
• 50% by 2030 with 65% from PPAs ≥ 10 years
Senat e Bill 100
(2018)
• 60% RPS by year-end 2030 and onward
• 100% renewable and zero-carbon by 2045
Assembly Bi ll 1279
(2022)• St atewide goal for carbon neut ralit y by 2045
Senat e Bill 1020
(2022)
• Int erim goals of 90% renewable and zero-carbon
by 2025 and 95% by 2040
• St ate agencies powered by 100% renewable and
carbon-free by 2035
3. Planning Drivers
California Policy Requirements
Vernon Public Utilities 2023 IRP 3-5
municipal solid waste, biofuels (biodiesel, biomass, and biomethane), fuel cells using
renewable fuel, and hydrokinetic energy (ocean thermal energy conversion [OTEC], ocean
wave, and tidal current). Zero-carbon generation that does not emit climate-altering
greenhouse gases include large hydroelectric and nuclear technologies.
Senate Bill 100: The 100 Percent Clean Energy Act of 2018. Passed in 2018, SB 100
accelerated the state’s RPS set in SB 350 to ensure that, by 2030, at least 60 percent of
California’s electricity is renewable. This percentage of renewable generation must be
maintained at or above 60 percent from 2030 onward. In addition, SB 100 requires that
renewable energy generation and zero-carbon resources power 100 percent of retail electricity
sold in California by the year 2045.
While not specified in SB 100, combustion resources fueled by biofuels or hydrogen derived
from renewable energy resources are defined as zero-carbon resources. In addition, while all
retail electricity sales in California must come from renewable and zero-carbon resources by
2045, the transmission and distribution line power losses (due to heat) can still be served by
fossil fuel-powered generation.
Finally, SB 100 required the CEC, the CPUC, and CARB to employ programs under existing
laws to achieve 100 percent clean electricity and issue a joint policy report on SB 100 by 2021
and every four years thereafter.
Assembly Bill 1279: The California Climate Crisis Act of 2022. AB 1279 established a
statewide goal for achieving carbon neutrality no later than 2045 and thereafter.
Senate Bill 1020: The Clean Energy, Jobs, and Affordability Act of 2022. In September
2022, SB 1020 added interim goals and the clean energy mandates established in SB 100.
SB 1020 requires that eligible renewable energy and zero-carbon resources supply 90 percent of
all retail electricity sales to California end-use customers by December 31, 2035, and supply
95 percent of all retail electricity sales by December 31, 2040. In addition, all electricity
delivered to California state agencies must be supplied by renewable and zero-carbon energy
resources by the end of 2035.
3. Planning Drivers
California Policy Requirements
Vernon Public Utilities 2023 IRP 3-6
California RPS Goals
Under current legislation, all California retail electric providers that serve electric load,
including IOUs, CCAs, ESPs, and POUs, must participate in the RPS program and comply
with numerous deadlines to meet RPS goals.
Table 2 summarizes the compliance periods (CPs) and RPS targets, along with the
corresponding legislations. Thus far, the CPUC has designated six CPs for reporting.
CP %
Compliance
Year Bill
Bill
Year Notes
1 20% 2013 SB X1-2 2006 SB 1078 initially set a 20% RPS target for 2017
2 25% 2016 SB X1-2 2006
3 33% 2020 SB 350 2015 Maintained in subsequent years
4 40% 2024 SB 350 2015 —
5 45% 2027 SB 350 2015 —
6 60% 2030 SB 100 2018 SB 350 initially set a 50% target for 2030
– 90% 2035 SB 1020 2022 From eligible renewable & zero-carbon resources
– 95% 2040 SB 1020 2022 From eligible renewable & zero-carbon resources
– 100% 2045 SB 100 2018 From eligible renewable & zero-carbon resources
Table 2. Renewable Portfolio Standard Percent Goals and Target Years
Starting in CP 3, the portfolio mix of all retail electric providers that serve electric load in
California must be made up of 75 percent or more, from two portfolio contents categories
(PCCs), PCC-0 and PCC-1 resources, 15 percent or less of PCC-2, and 10 percent or less of
PCC-3 resources2. In addition, starting with CP 4 (2021–2024), the RPS procurement requires
65 percent or more of owned or PPA contracts that extend 10 years or more. Both
requirements must be maintained starting in CP 4 and beyond. The annual RPS compliance
report is due to the CPUC on July 1.
2 PCC-0 designates a renewable resource located within the state of California or, a renewable resource that is directly delivered to
California without energy substitution from another resource that was signed or went online before June 1, 2010. PCC -1 designates
these resources that went online after June 1, 2010. PCC -3 designates a tradable or unbundled REC from a resource, delivered
without the energy component.
3. Planning Drivers
California Policy Requirements
Vernon Public Utilities 2023 IRP 3-7
Figure 16 depicts the RPS
percent procurement
requirements by CP, breaking
the CPs into interim goals by
year.
The CPUC has developed a
formula for determining the
procurement quantity
requirements for CP 4, CP 5,
and CP 6. The three formulas
follow a pattern based on the
following: the average
procurement quantity of the
electricity product over each
related CP must be greater
Figure 16. RPS Percent Procurement Requirements by Compliance Periods3
than or equal to the retail sales (RS) as calculated in each formula. Table 3 shows these formulas.
CP4 Procurement Quantity ≥ CP5 Procurement Quantity ≥ CP6 Procurement Quantity ≥
35.750% * 2021 RS 47.000% * 2025 RS 54.600% * 2028 RS
+ 38.500% * 2022 RS + 49.2.000% * 2026 RS + 57.200% * 2029 RS
+ 41.125% * 2023 RS + 52.000% * 2027 RS + 60.000% * 2030 RS
+ 44.000% * 2024 RS
Table 3. RPS Compliance Period Procurement Quantity Formulas
The California Code of Regulations, Title 20, Section 3201, defines both electricity product
and retail sales as follows:
▪ “Electricity product” means either (1) electricity and the associated RECs generated by an
eligible renewable energy resource or (2) an unbundled REC.
▪ “Retail sales” means electricity sales by a POU to end-use customers and their tenants,
measured in MWh. This does not include energy consumption by a POU, electricity used
by a POU for its water pumping, or electricity produced for onsite consumption
(self-generation).4
In 2018, VPU’s resource portfolio was comprised of 31 percent renewable generation and
10 percent zero-carbon generation. Since then, VPU’s share of the Astoria II Solar facility has
risen to 30 MW. In addition, VPU has attained a PPA for 60 MW from the Daggett Solar
3 https://www.cpuc.ca.gov/industries -and-topics/electrical-energy/electric -power-procurement/rps/rps-compliance-rules-and-
process/60-percent-rps-procurement-rules
4 https://casetext.com/regulation/california -code-of-regulations/title-20-public-utilities-and-energy/division-2-state-energy-resources-
conservation-and-development-commission/chapter-13-enforcement-procedures-for-the-renewables-portfolio-standard-for-local-
publicly-owned-electric-utilities/section-3201-definitions
3. Planning Drivers
California Policy Requirements
Vernon Public Utilities 2023 IRP 3-8
facility, plus 30 MW of BESS and 39 MW from the Sapphire Solar facility, plus 19.67 MW of
BESS. The COD for Daggett Solar is December 20, 2023; the COD for Sapphire Solar is
December 31, 2026. The addition of these PPAs increases the renewable generation portion of
VPU’s entire resource portfolio.
Subsidies for Customer Rooftop Solar
Senate Bill 1: Subsidies for Customer
Solar. SB 1 was enacted in 2006 to
increase the number of rooftop solar PV
systems, thus offsetting carbon resources
Figure 17. Customer Rooftop Solar Installation Legislation
and reducing GHG emissions. Potential systems include microturbines, fuel cells, solar, and
solar plus battery storage installations. The bill raises the net energy metering (NEM) cap from
0.5 percent to 2.5 percent of VPU’s aggregate customer peak demand.
Among related provisions, the legislation requires utilities to offer financial incentives for a
limited time to encourage customer rooftop solar PV installations. A portion of those
incentives must encourage optimal solar production during peak demand periods and energy
efficiency improvements. Since its inception, VPU has met the requirements of the bill’s
provisions by offering incentives for solar installations during a 10-year period from 2008-2017.
In addition, the utility continues to offer NEM and plans to develop a successor tariff in the
near future.
Cap-and-Trade Program and Market
Assembly Bill 32: California Global
Warming Solutions Act of 2006. AB 32
established a cap-and-trade market for
carbon emissions requiring CARB to
create two types of newly tradable
commodities known as a California
Compliance Instrument (CCI)
Figure 18. Cap-and-Trade Program Legislation
Allowance and CCI Offset. Allowances are essentially permits created and issued by CARB
that allows the holder to legally emit one metric ton (MT) of GHG measured in carbon
dioxide equivalents (CO2-e).
A CCI Offset is created when an approved project results in a GHG reduction or removal.
These projects must be accurate, quantifiable, permanent, verifiable, and enforceable
reductions or removals of GHG in the environment. An independent third-party verifier must
periodically inspect these projects to ensure compliance with protocols created or adopted by
3. Planning Drivers
California Policy Requirements
Vernon Public Utilities 2023 IRP 3-9
CARB. To comply with AB 32, a CCI Allowance and a CCI Offset must equally offset each
other to allow for the legal emission of one MT of GHG, measured in CO2-e.
Assembly Bill 398: Cap-and-Trade Extension. AB 398 extended and improved the
cap-and-trade program established in AB 32. The extension enables California to meet the
2030 GHG emission reduction goals in a cost-effective manner, and also generates billions of
dollars in auction proceeds to invest in statewide communities.
Energy Efficiency and Demand-Side Management
Assembly Bill 2021: 10-Year Energy
Efficiency Targets. AB 2021 required
POUs to establish specific annual energy
efficiency goals as a percentage of total
annual retail electric consumption and
establish 10-year targets every three
years, starting 2007. Before investing in
new carbon-based resources, utilities
must exhaust savings from all available
energy efficiency and demand reduction
Figure 19. Energy Efficiency and Demand-Side Management
Legislation
resources that are cost-effective, reliable, and feasible. The cost of implementing this program
was funded through a 2.85 percent surcharge on customer bills. The statute also required the
CEC to quantify all achievable energy efficiency savings to establish realistic attainment levels.
Assembly Bill 2227: 10-Year Energy Efficiency Targets (Amendment). AB 2227, passed in
2012, replaced the three-year requirement to establish 10-year energy efficiency goals to every
four years. In addition, AB 2227 also consolidated all of the POU reporting requirements into
a minimum number of sections in the Public Utilities Code (PUC).
Senate Bill 350: The Clean Energy and Pollution Reduction Act of 2015. Among the various
provisions set forth by SB 350, a key requirement directed state agencies to double the energy
savings in electricity and natural gas end uses through energy efficiency and conservation by
2030.
6
E E & D S M B i l l s
Assembly Bill 2021
(2006)
• Ut ilit ies must inst itute all possible EE and DSM
• Est ablished 10-year t arget s every t hree years
• CEC quantified all achievable EE savings
• Funded through a 2.85% surcharge
Senat e Bill 350
(2015)
• Double energy savings t hrough EE measures
and conservat ion
Assembly Bill 2227
(2012)
• Changed AB 2021 t arget requirement to every
four years
• Consolidated POU reporting requirement s
3. Planning Drivers
California Policy Requirements
Vernon Public Utilities 2023 IRP 3-10
Transportation Electrification
Senate Bill 350: Clean Energy and
Pollution Reduction Act of 2015.
SB 350 required utilities to propose
multiyear programs and investments to
accelerate widespread transportation
electrification that reduce dependence on
petroleum, meet air quality standards,
achieve EV charging station goals, and
reduce GHG emissions. The CPUC, in
consultation with CARB and the CEC,
approves these programs and their
investments.
Assembly Bill 1236 (2015): Local
Ordinances Electric Vehicle Charging
Stations.
Figure 20. Electric Vehicle Charging Legislation
AB 1236 required cities and counties to adopt an ordinance that creates an expedited,
streamlined permitting process for EV charging stations based on criteria listed in the
Permitting Electric Vehicle Charging Stations Scorecard.
Senate Bill 1000 (2016): Land Use Safety and Environmental Justice. SB 1000 required the
CEC to assess whether EV charging infrastructure, especially DCFC stations, is
disproportionately deployed by population density, geographical area, or by low-, middle-, and
high-income levels and whether access to these charging stations is disproportionately
available.
Assembly Bill 2127 (2018): Electric Vehicle Charging Infrastructure Assessment. AB 2127
required the CEC to assess all EV charging infrastructures to determine how well they meet the
state’s goal of adding at least five million ZEVs by 2030 and reducing GHG emissions to
40 percent below 1990 levels by 2030.
Assembly Bill 970 (2021): Electric Vehicle Charging Stations Permit Application. AB 970
provides additional details set forth in AB 1236 by clarifying the EV charging station
permitting process and setting deadlines for application acceptance.
The City of Vernon is subject to the regulations outlined in AB 1236 and AB 970, as it requires
all California cities and counties with populations fewer than 200,000 residents to expedite and
streamline permitting process for EV charging stations starting January 1, 2023. See “Electric
Vehicle Charging Infrastructure” on page 5-11 for more detail about how VPU complies with
all EV charging station statutes.
7
E V C h a r g i n g B i l l s
Senat e Bill 1000
(2016)
• CEC assessed EV charging st at ion infrast ruct ure
is proport ionately dist ributed
Assembly Bill 2127
(2018)• CEC assessed EV charging st at ion infrast ruct ure
Assembly Bill 1236
(2015)• St reamlined EV charging st at ion permit ting
Senat e Bill 350
(2015)• Accelerated t ransport at ion electrificat ion
Assembly Bill 970
(2021)
• Set time limit s for the EV charging st at ion
permit ting process
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-11
Energy Storage Resources
In early 2018, the Federal Energy Regulatory Commission (FERC) passed Order 841. The rule
requires all Regional Transmission Organizations (RTOs) and Independent System Operators
(ISOs) to remove barriers by revising its tariff so electric storage resources can participate in the
markets they operate. Order 841 enhances competition, promotes greater efficiency, and
supports resiliency of the bulk power system.
The participation model ensures that an electric storage resource is eligible to provide all
capacity, wholesale energy, ancillary services, and dispatch capability. Energy storage
resources, whether on the transmission system, distribution system, or behind the meter, are
able to participate and respond to wholesale market pricing signals.
Order 841 eliminates a major barrier for energy storage resources by ensuring more
opportunities to provide grid benefits with fair compensation for those services. It enhances the
ability to add increasing amounts of renewable generation to the power grid.
STATEWIDE PLANNING CONSIDERATIONS
Several external factors drive the planning of the IRP.
California Air Resources Board Scoping Plan
The 2022 CARB Scoping Plan for Achieving Carbon Neutrality lays out a sector-by-sector
roadmap for California to achieve carbon neutrality by 2045 or earlier through the reduction of
anthropogenic GHG emissions by 85 percent below 1990 levels, using cost-effective
technology.
Two previous scoping plans focused on GHG reduction targets for industry, energy, and
transportation, with the first scoping plan designed to meet 1990 levels by 2020, followed by
the second scoping designed to achieve at least 40% below 1990 levels by 2030. The 2022
scoping plan extends the previous goals to comply with current legislation. This scoping plan
seeks to eliminate the disproportionate burden of air pollution and ensure equity for
underserved and disadvantaged communities.
The actions and outcomes in the scoping plan will achieve:
▪ A significant reduction in fossil fuel combustion by deploying clean technologies and fuels.
▪ A further reduction in short-lived climate pollutants.
▪ Support for sustainable development.
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-12
▪ Increased action on natural and agricultural lands to reduce GHG emissions, including
CCS technology.
The 2022 Scoping Plan assumes:
▪ Thirty-eight million metric tons (MMT) GHG carbon dioxide (CO2) emission reduction
target by 2030.
▪ Sixty percent RPS by 2030.
▪ Vehicle miles travelled per capita reduced to 4 percent of 2019 levels by 2045. (Per-capita
vehicle miles travelled increased from 2017 to 2019; assuming even a marginal decrease,
without additional action, risks achieving 2030 emission reduction goals.)
Under this Scoping Plan, the role of electricity in powering the economy will grow in almost
every sector. A clean, affordable, and reliable electricity grid will serve as a backbone to
support decarbonization efforts across California’s economy. Energy efficiency and the
replacement of fossil-fueled generation with renewable and zero-carbon resources are two
important components to decarbonizing the electric sector.
The Scoping Plan incorporates the goal of doubling energy efficiency, as set forth in SB 350,
and aligns with:
▪ The CPUC’s IRP 2030 GHG target and latest GHG emissions benchmarks through 2035.
▪ The Governor’s 20 gigawatt (GW) offshore wind and no new natural gas generation goals.
▪ SB 100’s 2030 RPS and 2045 zero-carbon retail sales targets.
The goal is to reduce dependence on fossil fuels in the electricity sector by transitioning
substantial energy demand to renewable and zero carbon resources. Achieving the goals
established in SB 100 require 6 GW of new solar, wind, and battery resources over the next 25
years. This requires tripling the existing amount of solar and wind installations at an eight-fold
acceleration in conjunction with BESS to achieve the 2030 and 2045 targets.
A significant element of this transition is through transportation electrification, which involves
replacing fossil fuel vehicles with ZEVs. CARB’s Advanced Clean Fleet regulation helps
accelerate the timeline of electrifying heavy-duty vehicles. The Advanced Clean Cars II
(ACC II) rule also requires all car sales in California to be 100 percent zero emission by 2035.
To this extent, VPU has made progress in electrifying a portion of its municipal fleet. (See
“Transportation Electrification Impacts” on page 4-13.)
Transportation and building electrification both require substantially increasing clean energy
production and expanding the distribution infrastructure to achieve decarbonization. The
electric power grid must evolve and grow exponentially over the next two decades to ensure
reliable, affordable, and resilient energy delivery.
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-13
This plan also calls for increasing renewable hydrogen for hard-to-electrify end uses. Upon its
full implementation, this Scoping Plan would reduce the demand for petroleum by 94 percent
below 2022 levels by 2045.
CEC Integrated Energy Policy Report Demand Forecasts
The CEC prepares the Integrated Energy Policy Report (IEPR) every two years, updated every
other year. The IEPR outlines a cohesive approach to best manage California’s energy
transition from oil and natural gas to renewable energy resources and alternatively fueled
vehicles. The report assesses and forecasts energy-related trends and, using that information,
develops “energy policies that conserve resources, protect the environment, ensure energy
reliability, enhance the state’s economy, and protect public health and safety.”5
The IEPR includes the California Energy Demand Update (CEDU) for 2022. The CEDU
includes updates to historical data, economic and demographic projections, electricity rates, and
hourly forecasts, as well as incorporates a new assessment approach for the transportation sector,
given the rapid advancements in electrification.
The CEC revised forecasting framework includes a baseline forecast, a planning forecast, and a
local reliability scenario. To better evaluate electricity forecasts, the planning forecast contains
sensitivity scenarios for additional achievable energy efficiency (AAEE), additional achievable
fuel substitution (AAFS), and additional achievable transportation electrification (AATE).
The Final 2022 IEPR Update6 (filed February 28, 2023) assesses several trends: economic and
demographic, climate, behind-the-meter solar photovoltaic (PV) and storage, and
transportation as well as state policies and goals. Using these trends, the IEPR includes
forecasts for the 2023–2035 timeframe for:
▪ Annual electricity consumption
▪ Electricity sales
▪ Managed sales, including AAEE, AAFS, and AATE electricity impacts
▪ Peak demand (load)
These IEPR forecasts provided a necessary framework for the development of the VPU IRP
and its energy and peak demand forecasts.
5 Pub. Res. Code § 25301(a)
6 Final 2022 Integrated Energy Policy Report Update with Errata, California Energy Commission; Docket Number 22-IEPR-01, TN #
248998, February 28, 2023
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-14
CAISO Transmission Planning Process
The CAISO 2021–2022 Transmission Plan (published March 17, 2022) articulated an
accelerated pace for developing new transmission facilities based on an average of 2.7 GW of
new resources per year over the next decade.
On May 23, 2023, the CAISO Board of Governors approved its 2022–2023 Transmission
Plan. That plan updated its needed capacity projections to more than 40 GW of new resources
over the next decade; a sensitivity study projected the need for up to 70 GW over the same
period. CAISO expects that next year’s Transmission Plan will be based on this 70 GW
projection, which is expected to grow to 120 GW to better align with the goal of a carbon-free
power system by 2045. These projections consider the imminent retirement of over 7 GW of
natural gas-powered and nuclear-powered generation.
Several factors drive this accelerated pace:
▪ The urgency of decarbonizing the electricity grid because of emerging climate change
impacts.
▪ Higher electricity forecasts due to the expected electrification of transportation, building and
construction, and other carbon-emitting industries.
▪ Reduced access to opportunity imports with the decarbonization of neighboring systems.
▪ Greater than anticipated impacts of peak demand shifting to evening hours when solar
resources are unavailable.
▪ Maintaining system reliability when the Diablo Canyon Nuclear Power Plant and
quantities of gas-fired generation that relied on coastal waters for once-through cooling
(OTC) retirement.
Decarbonizing the power grid requires increased generation from solar PV, onshore and
offshore wind, geothermal, out-of-state renewables, along with nuclear and hydrokinetic
resources. Battery storage also plays a role in decarbonizing the power grid. In conjunction, the
transmission system must be expanded, upgraded, and reinforced to integrate these resources
to accommodate the expected increase in electricity consumption as transportation and other
industries electrify.7
Several factors drove the new transmission plan. CAISO has received many interconnection
requests from “areas that regulators and load-serving entities have not considered optimal for
additional transmission development.” In addition, CAISO has received “an excessive volume
of interconnection requests” in optimal areas. This resulted in much longer wait times for
resource developers to receive the results of their construction requests and more uncertainty
around load-serving entities (LSEs) procuring additional resources.
7 California ISO 2021–2022 Transmission Plan, CAISO, March 17, 2022; p. 1.
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-15
CAISO has created the new transmission plan in collaboration with the CPUC and the CEC
and with input from hundreds of stakeholders that takes advantage of transmission and
interconnection capacity under development. The interconnection process has also been
optimized for transmission upgrades to accommodate longer-term resource development, such
as out-of-state and offshore wind.8
The transmission plan focuses on ensuring that renewable resources can reliably connect and
be delivered; it does not ensure that congestion would preclude achieving state policy goals.9
The plan outlines potential transmission system solutions, which CAISO can initiate, as well
as non-transmission solutions (such as energy efficiency, demand response (DR), renewable
generating resources, and energy storage programs) that require regulatory approval.10
The 2022–2023 Transmission Plan “tightens the linkages between resource and transmission
planning activities, interconnection processes and resource procurement so California is better
equipped to meet its reliability needs and clean-energy policy objectives required by Senate Bill
100.”11 The plan outlines the need for a total of 46 transmission projects primarily built in
California. The transmission projects range in projected costs from $4 million to $2.3 Billion,
for a total infrastructure investment of an estimated $9.3 Billion.12
Using resource planning information provided by the CPUC, CAISO plans to develop a final
transmission plan, initiate transmission projects, and communicate to LSEs the specific
geographic zones being targeted for such projects. The CPUC, in turn, will direct LSEs to
procure energy from those zones whose interconnection requests will be given priority.
8 http://www.caiso.com/about/Pages/Blog/Posts/A-better-way-to-address-interconnections.aspx
9 CAISO 2022, op. cit.; p. 2.
10 Ibid.
11 California ISO Draft 2022–23 Transmission Plan, CAISO, April 3, 2023; p. 1.
12 Ibid.; p. 3.
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-16
In concert with CPUC-provided resource planning information, the transmission plan
identifies specific geographic zones targeted for transmission projects. Figure 21 depicts these
geographic zones.
Figure 21. CAISO Transmission Planning Zones and Capacities13
Southern California Edison is reconductoring the existing Laguna Bell-Mesa #1 230 kV line
and upgrading the corresponding substation’s terminal equipment because the line has
experienced thermal overloads. This transmission upgrade directly affects VPU. (For details,
refer to “Laguna Bell Corridor Line Upgrades” on page 7-2.)
13 Ibid.; p. 4.
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-17
Resource Adequacy Methodology
In 2004, the CPUC established its RA Program with two goals: (1) to ensure safe and reliable
electric service by providing sufficient resources to CAISO and (2) to create incentives for
siting and constructing new resources.
Resources are counted based on their capacity contribution, as well as on assigned 24-hour
profiles for wind and solar, dispatchable and non-dispatchable resources, dispatchable
hydroelectric, energy storage, hybrid and co-located resources, imported resources, and
demand response. The RA program also adopted monthly effective load carrying capability
(ELCC) values for solar and wind resources beginning in 2023.
RA resources must be available during five-consecutive peak hours as designated by CAISO.
LSEs within CAISO must demonstrate three distinct requirements of RA, System RA, Local
RA, and Flexible RA, and file annual and monthly reports for each requirement.
System RA. This requirement maintains electricity during peak demand periods during the
day, generally early morning and early evening. Capacity is determined by forecasting peak
demand and adding a minimum 15 percent planning reserve margin (PRM).
LSEs must own, control, or contract rights to its RA resources, which must demonstrate
sufficient CAISO-verified net qualifying capacity (NQC) to meet monthly coincident peak
demand plus a PRM. VPU’s seasonal load profile is unique; it has a very high load factor of
above 70 percent during summer and winter months.
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-18
VPU determined the capacity needed to
maintain reliability for each year in the
short-term planning period (2023
through 2031). Results demonstrate that
VPU meets the short-term RA
requirements through existing local and
contracted resources.
Local RA. This requirement maintains
electricity during grid contingencies
where bulk transmission limitations or
other conditions may constrain the
electrical supply available to serve load.
These include transmission line failures
or a power plant tripping offline.
CAISO has identified ten transmission
constrained areas in its jurisdiction area.
VPU resides in the Los Angeles Basin
and meets the 70 MW local RA
obligation through the Vernon-owned
and operated MGS and H. Gonzales
power plants. This local generation
insulates VPU from an N-2 contingency
Figure 22. CAISO Local Capacity Area Map
involving two transmission lines.
Flexible RA. This requirement maintains electricity during evening peak demand when solar
generation is diminishing and ensures enough flexible capacity to meet expected demand.
Increasing amounts of variable renewable generation present a challenge for meeting daytime
demand. Sufficient capacity must be flexible and dispatchable enough to meet daily changing
demand profiles, especially the ramping requirements for meeting peak evening demand.
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-19
The so-called duck curve (Figure 23) demonstrates the balancing act necessary to meet this
challenge.
Figure 23. The Variable Renewable Generation Duck Curve
Every year, CAISO identifies the largest forecasted three-hour net load ramps plus 3.5 percent
to determine the RA requirements for each LSE. The target RA can react quickly enough to
meet net demand without over-generating. Solar generation requires capacity to ramp down in
the morning when solar generation begins, followed by ramping up in the evening when solar
generation wanes.
Flexible RA resources fall into three categories, each with increasingly stringent operating
characteristics: Base Ramping, Peak Ramping, and Super-Peak Ramping. A Base Ramping
resource also qualifies as a Peak Ramping resource, and both resources qualify as a Super-Peak
Ramping resource.
Table 4 outlines the primary characteristics of each Flexible RA category.
Category Available Days Available Hours
Minimum Hours at
Full Effective
Flexible Capacity Minimum Startups
Base Ramping Every day 17 hours per day,
5:00 to 22:00 6 hours 2 per day; 60 per month
Peak Ramping Every day 5 hours per day
hours vary by season 3 hours 1 per day
Super-Peak Ramping Non-holiday weekdays 5 hours per day,
hours vary by season 3 hours 1 per day; 5 CAISO
dispatches per month
Table 4. Flexible Resource Adequacy Categories
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-20
CAISO dictates the Flexible RA requirements for VPU (Table 5). VPU deploys MGS with its
105 MW of eligible flexible capacity and H Gonzales with its 23 MW for eligible flexible
capacity to meet VPU’s Flexible RA requirements. Both MGS and H Gonzalez are locally-
sited and are used to meet VPU’s flexible capacity needs.
Month Base %
Base Ramping
(MW)
Peak Ramping
(MW)
Super-Peak Ramping
(MW)
Total
(MW)
January 40% 16.09 31.30 2.49 49.88
February 40% 20.98 40.80 3.25 65.03
March 40% 21.06 40.97 3.26 65.29
April 40% 20.03 38.95 3.10 62.08
May 50% 27.60 29.75 3.02 60.37
June 50% 27.78 29.93 3.04 60.75
July 50% 26.93 29.02 2.94 58.90
August 50% 27.47 29.61 3.00 60.08
September 50% 28.16 30.35 3.08 61.59
October 40% 20.69 40.24 3.21 64.13
November 40% 18.79 36.55 2.91 58.26
December 40% 16.28 31.67 2.52 50.47
Table 5. Flexible Resource Adequacy Capacity Requirements: 2023
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-21
Increased penetration of solar resources causes an increase in Flexible RA requirements.
VPU’s 2023 Flexible RA requirement increased by slightly more than 58 percent compared to
the requirements stated in VPU’s 2018 IRP. For 2023, VPU assumed that each addition of
60 MW of solar would result in an approximate increase in 60 MW for Flexible RA capacity.
Ongoing increases in Flexible RA requirements, together with their associated costs, were
factored into the modeling and analysis of this IRP’s optimal resource portfolio.
Table 6 lists VPU’s RA capacity for each committed resource compared to its total RA
requirements.
Committed Unit System RA (MW) Local RA (MW) Flexible RA (MW)
Malburg Combined Cycle 139.0 139.0 105.0
H Gonzales 1 & 2 Combustion Turbines 11.5 11.5 11.5
Palo Verde Nuclear 11.0 0.0 0.0
Hoover Dam Hydroelectric 15.0 0.0 0.0
Puente Hills Landfill Gas 4.0 0.0 0.0
Antelope DSR Solar PV 3.0 0.0 0.0
Astoria Solar PV 4.0 0.0 0.0
2023 RA Capacity 187.5 150.5 116.5
2023 RA Requirement 183.0 70.0 66.0
Long (Short) 4.5 80.5 50.5
Table 6. Resource Adequacy Capacity: 2023
Building Electrification Impacts
The CEC Building Energy Efficiency Standards, also known as Title 24 or the Energy Code, is
an integral part of the state’s efforts to reduce carbon emissions and address the ongoing issues
related to climate change. The latest updates to the 2022 Energy Code reinforces the concept of
building electrification, which not only encourages the adoption of efficient all-electric
technologies by reducing emissions from newly constructed buildings but also increases electric
load flexibility to support grid reliability and enable increased opportunities for on-site
renewable energy generation through solar. Along the same lines, the 2022 Strategy for the
State Implementation Plan (SIP) adopted by CARB is also aims to reduce building emissions
in the form of nitrous oxide (NOx) due to natural gas combustion.
For VPU’s customer base, which is mainly comprised of large commercial and industrial
companies, this means newly constructed buildings must utilize electricity as the primary fuel
for its core functions. This approach deviates from traditional fuel sources that includes on-site
combustion of natural gas, oil, propane, or other fossil fuels. While each entity has its own
unique operation, a few overarching concepts for building electrification can include adopting
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-22
heat pumps to decarbonize space and water heating for buildings, coupled with all-electric
boilers and furnaces for operations that require high industrial heat demand.
Opportunities for battery storage systems to respond to an increasingly intermittent grid and
electric vehicle charging infrastructure to support the shift to an all-electric fleet also play vital
roles. Solar PV and heat pump technologies have evolved significantly in various instances and
can provide cost-competitive solutions to making the switch, especially in a new construction
setting.
For industrial operations, adopting all-electric equipment can reduce maintenance costs,
together with improved efficiency and less challenges with meeting air quality standards.
Ultimately, the impacts of building electrification still heavily depend on the difference
between the ongoing costs of energy to run all-electric equipment compared to the
conventional fuel type.
VPU recognizes the need for customers and site owners to assess their potential to electrify,
allowing for better decision-making when it comes to investing in all-electric equipment. As a
result, VPU plans to develop robust customer programs that provide technical support and
incentives to streamline the transition toward building electrification. At the same time, VPU
continues to implement existing programs that encourage the efficient use of energy for
existing and newly constructed buildings.
Transportation Electrification Analysis
Electrification of the transportation sector is vital to reducing California’s GHG emissions.
In 2012, Governor Brown issued Executive Order B-16-2012 to electrify the transportation
sector, calling on the CEC and other state agencies to achieve 1.5 million ZEVs by 2025. In
2018, Governor Brown issued Executive Order B-48-18 that increased that goal to 5 million
ZEVs by 2030.
In August 2022, CARB established an annualized roadmap to phase out the sale of internal
combustion passenger vehicles by issuing its ACC II rule which supports Governor Newsom’s
Executive Order N-79-20. ACC II aims to rapidly scale down light-duty passenger car, pickup
truck, and SUV emissions starting with the 2026 model year through 2035.
3. Planning Drivers
Statewide Planning Considerations
Vernon Public Utilities 2023 IRP 3-23
Figure 24 shows the annual requirements for complying with ACC II, which requires all new
passenger vehicles sold in California to be zero emission by 2035.
Figure 24. Zero-Emission Vehicles Sales Compliance with ACC II14
Transportation currently accounts for more than 50 percent of California’s GHG emissions.
By 2037, the rule will reduce pollution from light-duty vehicles by 25 percent to meet federal
air quality standards. In 2040, GHG emissions from cars, pickups, and sport utility vehicles
(SUVs) will decrease by 50 percent from today’s levels. By 2040, the regulation will cut climate
warming pollution from those vehicles a cumulative total of 395 MMT.
The rule delivers multiple benefits that continue to grow year after year. By 2030, 2.9 million
fewer new gasoline-powered vehicles will be sold in California, rising to 9.5 million fewer
gasoline-powered vehicles by 2035.
14 https://ww2.arb.ca.gov/news/california-moves-accelerate-100-new-zero-emission-vehicle-sales-2035
3. Planning Drivers
Regionalization Considerations and Risks
Vernon Public Utilities 2023 IRP 3-24
REGIONALIZATION CONSIDERATIONS AND RISKS
SB 350 took an essential step toward creating an integrated Western Interconnection system to
consolidate control over electric grid operations, paving the way for easier integration and
continued growth of renewable energy resources. The bill required CAISO to prepare proposed
governance modifications to facilitate its transformation into a regional organization. The bill
started a process for allowing CAISO to expand its wholesale electricity market programs to
include out-of-state transmission owners.
The reorganization of the Western Interconnection is synonymous with grid regionalization.
The Western Interconnection and WECC
The United States power grid, which includes most of Canada, is separated into
interconnection regions. The North American Electric Reliability Corporation (NERC)
develops and enforces reliability standards among the interconnections. Figure 25 depicts a
map of the NERC interconnection regions in North America.
MRO Midwest Reliability Organization NPCC Northeast Power Coordinating Council
RF Reliability First SERC SERC Reliability Corporation
Texas RE Texas Reliability Entity WECC Western Electricity Coordinating Council
Figure 25. North American NERC Interconnections and Governing Organizations15
These interconnections help maintain reliability by enabling generators to supply power to many load
centers through a network of transmission routes.
Three main United States interconnections operate primarily as independent areas from each
other with limited transfers of power between them. The network structure among the
15 https://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx
3. Planning Drivers
Regionalization Considerations and Risks
Vernon Public Utilities 2023 IRP 3-25
interconnections helps maintain the reliability of the power system by providing multiple
routes for power to flow and allowing generators to supply electricity to many load centers.
This redundancy helps prevent transmission line or power plant failures from causing
interruptions in service.
Balancing authorities (BAs) manage this power system to finely balance demand and supply in
real time. There are seven RTOs (or ISOs) that act as BAs for the three interconnections (as
depicted in Figure 26).
Figure 26. Map of Nationwide RTOs16
Five RTOs and a few large ISOs manage most of the Eastern Interconnection. The Electric
Reliability Council of Texas (ERCOT) Interconnection manages itself. The Western
Interconnection, however, is the most widely managed Interconnection in the country.
In 2007, NERC delegated authority to the Western Electricity Coordinating Council (WECC)
as the regional entity to enforce its compliance standards throughout the Western
Interconnection. Its two core missions are to coordinate reliability and transmission access to
the bulk electric system (BES). WECC is responsible for over 300 member organizations, each
operating within one of the 38 BAs in the Western Interconnection. Of those BAs, 37 are
independent utilities; only CAISO is an ISO.
Over the years, CAISO has accomplished much to move the Western Interconnection closer to
a renewable and clean energy future. While effective for several years, this structure is
beginning to create problems for California as it pursues its climate change and clean energy
objectives.
16 https://www.eia.gov/todayinenergy/detail.php?id=790
3. Planning Drivers
Regionalization Considerations and Risks
Vernon Public Utilities 2023 IRP 3-26
CAISO as a Regional Transmission Operator
The Western Interconnection power grid can improve access to renewable energy, strengthen
grid reliability, and unify transmission system planning, thereby reducing costs and GHG
emissions.
CAISO has faced severe challenges in recent years due to several factors. Summer months
have resulted in high demands and energy shortages, coupled with delayed renewable and
clean energy projects. As a result, CAISO had to implement drastic steps to maintain natural
gas plants and diesel backup generators. The option of joining other western states to create a
regional grid operator might be the optimal solution for the transition to an all-clean energy
market with improved grid reliability at lower costs.
In 2018, California legislators proposed AB 813, which would have enabled CAISO to become
an RTO. The bill, however, did not pass. Since then, the struggle of electric utilities in
California to meet state goals has led to a surge in clean energy and transmission expansion
needs and an increase in consumer electric rates. Several mandates exacerbated the need for
renewable and zero-carbon energy:
▪ Sixty percent renewable energy by 2030
▪ One hundred percent carbon-free by 2045
▪ Transportation electrification
▪ Building electrification to meet the GHG emission reduction targets.
Transmission planning under the current system would be suboptimal compared to regional
transmission planning that alleviates regional issues that would result in significant savings on
transmission expansion to move clean energy in the region.
A regional RTO would result in more efficient markets for clean energy through resource
diversity and transmission connectivity between supply and demand regions throughout the
western states.
3. Planning Drivers
Regionalization Considerations and Risks
Vernon Public Utilities 2023 IRP 3-27
Western Energy Imbalance Market
CAISO established the Western Energy Imbalance Market (WEIM) in 2014 as a real-time
energy market. WEIM’s advanced market system automatically finds low-cost energy to serve
consumer demand across the West. Currently, 22 utilities, irrigation districts, and BAs across
11 states participate in WEIM.17
WEIM covers 79 percent of the load in the Western Interconnection. WEIM allows
participants to buy and sell power close to the time electricity is consumed and gives system
operators real-time visibility across neighboring grids. The result improves balancing supply
and demand at a lower cost. The WEIM platform balances fluctuations in supply and demand
by automatically finding lower-cost resources to meet real-time power needs. WEIM manages
congestion on transmission lines to maintain grid reliability and supports integrating renewable
resources. In addition, the market makes excess renewable energy available to participating
utilities at low cost rather than turning the generating units off.
More specifically, regional coordination in generating and delivering energy produces
significant benefits in four main areas:
▪ Reduced costs for participants by lowering the amount of costly spinning reserves utilities
need to carry.
▪ Improved efficiency of the regional transmission system.
▪ Reduced carbon emission and more efficient use and integration of renewable energy. For
instance, when one utility area has excess hydroelectric, solar, or wind power, CAISO can
deliver it to customers in California or to another participant. Likewise, when CAISO has
excess solar energy, it can help meet demand outside of California that otherwise would be
met by more expensive, and less clean, energy resources. Since its inception, WEIM has
reduced renewable energy curtailment by more than 1.8 million MWh and reduced CO2
emissions by 800,000 MT.
▪ Enhanced reliability by increasing operational visibility across electricity grids and
improving the ability to manage transmission line congestion across the region’s
high-voltage transmission system.
Extended Day-Ahead Market
The Extended Day-Ahead Market (EDAM) is a voluntary day-ahead electricity market
designed to deliver significant economic, environmental, and reliability benefits to balancing
areas and utilities throughout the Western Interconnection. Jointly approved by CAISO’s
17 WEIM participants are Arizona Public Ser vice, Avangrid, Avista, Balancing Authority of Northern California (BANC), Bonneville
Power Administration, CAISO, El Paso Electric, Idaho Power Company, Los Angeles Department of Water & Power,
NorthWestern Energy, NV Energy, PacifiCorp, Portland General Electric, Powerex, Public Service Company of New Mexico,
Puget Sound, Salt River Project, Seattle City Light, Tacoma Power, Tucson Electric Power, Turlock Irrigation District, and th e
Western Area Power Administration (WAPA) Desert Southwest Region.
3. Planning Drivers
Regionalization Considerations and Risks
Vernon Public Utilities 2023 IRP 3-28
Board of Governors and WEIM Governing Body in February 2023, the EDAM initiative
leveraged existing features of the CAISO day-ahead market, features found in similar markets
across the country, and used stakeholder feedback to further improve the market design.
The day-ahead market efficiently positions supply to meet forecasted demand across the
EDAM footprint. It identifies economic transfers between participating areas, providing
economic, reliability, and environmental benefits for participating BAs and their utilities.
Economic Benefits. Operational benefits result from reduced production expenses and
providing the least-cost resources to meet demand. Since demand peaks vary for individual
BAs across the year, the day-ahead market seeks to efficiently commit supply to meet peak
needs of the entire footprint.
Reliability Benefits. A regional day‑ahead market positions a comprehensive set of resources
to cost-effectively meet the next day’s conditions by improving visibility and awareness of
conditions across the footprint, including supply availability. A diverse and broad supply pool
allows the market to effectively position supply the day ahead and respond to changes in
conditions while reducing operational risk, and the frequency and magnitude of emergency
conditions.
Environmental Benefits. When excess renewable production occurs in one BA in the regional
day-ahead market, the energy meets demand elsewhere, reducing the need for curtailing clean
energy resources.
A 2022 study quantified the potential savings. EDAM would:
▪ Decrease power production and operational expenses across WECC states by 4.5 percent,
saving up to $543 million annually. California’s expenses would decrease by 6.2 percent,
saving $214 million annually.
▪ Reduce GHG emission by 1.5 percent or 2.92 MMT annually.
▪ Avoid specific capacity resources through an RA program, saving WECC states up to
$557 million, and California $95 million, in avoided investments.
▪ Save WECC states as much as $1.2 Billion annually, with California realizing $309 million
annually.
EDAM is scheduled to be fully implemented in 2025.
Western Resource Adequacy Program
Replacing retiring thermal generation with variable energy resources has led to questions about
whether the region will continue to have an adequate supply of electricity during critical hours.
Numerous studies have shown RA to be an urgent and immediate challenge. Simultaneously,
3. Planning Drivers
Regionalization Considerations and Risks
Vernon Public Utilities 2023 IRP 3-29
customers are consuming more energy. In addition, public policies, such as transportation and
building electrification, are contributing to increasing loads.
The Western Resource Adequacy Program (WRAP) started at the request of the Western
Power Pool (WPP) and by many in the industry concerned about the issue of RA in the West.
WRAP is the first regional reliability planning and compliance program.
WRAP aims to enhance reliability by delivering a region-wide approach for assessing and
addressing RA. Through the collaboration of participants, WRAP can paint a more accurate,
regional picture of resource needs and supply, address resource adequacy, and ensure
reliability by taking advantage of operating efficiencies, diversity, and sharing pooled
resources. WRAP can also maintain existing responsibilities for reliable operations and
observe existing frameworks for planning, purchasing, and delivering energy.
In February 2023, FERC approved the tariff for WRAP, clearing the way for its full
implementation. Twenty-two utilities have already committed to participate in WRAP.18
Later in 2023, all participants are expected to join WRAP’s forward showing and demonstrate
they have secured their share of the region’s energy needs. The operational component,
initiated in winter 2023 and summer 2024, is when utilities with a deficit can tap into the pool
of shared resources as needed.
Ultimately, WRAP expects to maintain reliable service using fewer overall resources, ensure
adequate resources during extreme weather events, and help enable the transition to clean
energy.
Grid Regionalization: Opportunities and Challenges
The concept behind creating a western RTO would be to improve grid reliability, energy
market efficiency, and regional transmission planning, all of which could potentially hasten the
transition to clean energy and lower energy costs for ratepayers. Creating a western RTO
presents many opportunities for California and the region. Its implementation, however,
presents challenges to all participating entities including VPU.
18 As of April 6, 2023, participants included Arizona Public Service, Avista, Bonneville Power Administration, Calpine, Chelan
County Public Utility District (PUD), Clatskanie PUD, Eugene Water & Electric Board, Grant PUD, Idaho Power, Northwestern
Energy, NV Energy, PacifiCorp, Portland General Electric, Powerex, Puget Sound Energy, Public Service Company of New
Mexico, Salt River Project, Seattle City Light, Shell Energy, Snohomish County Public Utility District, Tacoma Power, and The
Energy Authority.
3. Planning Drivers
Regionalization Considerations and Risks
Vernon Public Utilities 2023 IRP 3-30
While regionalizing the western wholesale electricity market presents many benefits, several
questions cannot be fully answered about this effort, specifically:
▪ How does regionalization affect California’s efforts to expand energy efficiency, DR, and
distributed generation if the wholesale market operator projects and determines that
electricity, reliability, or other services shall be fulfilled through transmission and generation
projects?
▪ How are other BAs operating in California affected to having equal access and interactions
between participants and non-participants in the new market?
▪ How are transmission costs allocated to ensure that California ratepayers do not bear a
disproportionate burden?
▪ How are California’s GHG emission reduction goals affected?
Here are several issues to consider in response to these questions and to other challenges.
A Western RTO Governance Structure. California must pass legislation for CAISO to
expand its operations into the rest of the Western Interconnection and become the region’s
RTO. This would allow other utilities in the Western Interconnect to join the RTO.
CAISO would need to create an independent governance structure, which could present a
problem for California. The current CAISO Board of Governors is appointed by California’s
governor and confirmed by the state senate. While the CAISO board operates independently,
these appointees can largely influence policy. The creation of a western RTO operated by
CAISO means that California would make this process moot as a new Board of Governors
would be created with regional input and FERC involvement. This newly formed regional
board would ostensibly operate with the entire region in mind, not just for California. This
presents a potential problem for California’s transition to clean energy as recent history with
other RTOs have demonstrated a negative impact to a clean energy transition.
The composition of governing boards and their decision-making process varies widely across
existing RTOs. To streamline decisions, a group of western state electricity regulators,
including two CPUC commissioners, created a set of governance principles to protect
customers and support state policy mandates in the western electricity grid. These principles
include having a committee to represent state interests, an independent and diverse board,
along with a meaningful and open stakeholder engagement.19 California would benefit if these
types of governance principles were rooted in the creation of a western RTO.
Attaining California’s Clean Energy Goals. By coordinating with neighboring BAs,
regionalization might avert power outages with increased supplies during emergencies (such as
severe heat waves). Regionalization might alter the way California achieves its RPS goals. The
19 State Electricity Regulators. 2022 Letter to Organizations Building Regional Electricity System Optimization, April 18.
https://www.westernenergyboard.org/wp -content/uploads/Multistate- Governance-Principles-4-25-22.pdf
3. Planning Drivers
Regionalization Considerations and Risks
Vernon Public Utilities 2023 IRP 3-31
law requires delivery of renewable energy to a California BA. An RTO would make
out-of-state renewable power eligible under the current rules. Regionalization might also
reduce the need for fossil fuel generation due to an increased supply base.
More States with Clean Energy Goals. Twenty-two states (plus the District of Columbia and
Puerto Rico) currently have 100 percent clean energy goals, as opposed to only one in 2018.
Besides California, other nearby states include Colorado, Nevada, New Mexico, Oregon, and
Washington, which represents about 80 percent of the western state population. A western
RTO would be dominated by participants working toward similar clean energy goals. This
shared goal would maximize, but certainly not ensure, the opportunity for policies that would
better enable California’s transition to clean energy.
Power Market Competition. In 2018, CAISO’s WEIM covered approximately 80 percent of
load in the Western Interconnection. Since 2021, however, the Southwest Power Pool’s (SPP)
Western Energy Imbalance Service (WEIS) has competed directly with the CAISO WEIM.
While CAISO is creating its EDAM to build on WEIM’s success, SPP is responding by
developing its day-ahead Markets+ service to compete directly with EDAM. Eight20 of the 22
organizations participating in WEIM have executed agreements to participate in the
development of Markets+, which jeopardizes their future participation in WEIM and EDAM.
20 Arizona Public Service Company, Bonneville Power Administration, NV Energy, Powerex Corporation, Puget Sound Energy, Salt
River Project, Tacoma Power, and Tucson Electric Power Company.
3. Planning Drivers
Regionalization Considerations and Risks
Vernon Public Utilities 2023 IRP 3-32
Figure 27 compares the CAISO WEIM participants with the eight WEIM members who have
also signed agreements to participate in phase one of SPP’s Markets+ development.
Figure 27. CAISO WEIM Participants21 and SPP Markets+ Development Participants22
Thus, there is a risk that states might organize within the SPP and its Markets+ initiative and
leave California behind to fend for itself.
Improved Resource Sharing. A western RTO would assume the role of the sole BA in the
region. There are currently 38 BAs in the Western Interconnection. BAs plan RA, ensuring
enough resources are available to maintain grid reliability. Grid regionalization accesses a
more extensive and diverse generation pool. It would enable a BA to better meet differences in
peak demand times especially when they occur at different times of the year in different
geographical areas.
In-State Renewable Generation. Current legislation requires that at least 75 percent of
generation necessary to meet California’s RPS requirement be generated within the state. How
a western RTO would affect this requirement is unclear as the potential to import increasing
amounts of RPS-eligible generation would increase, thus affecting the siting of such generation
in California.
Grid Reliability Challenges. Extreme weather events and other circumstances in the past few
years have clearly demonstrated California’s power grid fragility. Grid regionalization could
reduce the overall amount of capacity needed to maintain grid reliability as the larger grid
could better enable shared resources with every utility in the RTO.
21 https://www.westerneim.com/Pages/About/default.aspx
22 https://blog.ucsusa.org/mark-specht/western-grid-regionalization-is-back-on-the-drawing-board-why-now/
3. Planning Drivers
Cost of Service and Rate Impacts
Vernon Public Utilities 2023 IRP 3-33
Efficient Transmission Access. All BAs in the Western Interconnection must coordinate
transmission planning with other BAs. A western RTO, with access to the entire transmission
infrastructure, would be better equipped to manage transmission constraints and could
coordinate responses to extreme weather conditions from multiple resources. In addition, a
western RTO could better manage transmission growth across states.
Coal Power Plant Retirements. A concern in 2018 was that grid regionalization would create
a larger market for coal generation, especially when many coal plants are base loaded
(operating without regard to cost). Today, however, many coal plants have planned retirement
dates within the next decade. Indeed, the Inflation Reduction Act of 2022 only served to
accelerate that trend. A western RTO could reverse this trend although it would take new
legislation.
Organizing a Western RTO Has Already Begun. SPP has already made inroads into the
Western Interconnection in addition to other erosions. State laws may compound this effect.
Both Colorado and Nevada mandate certain utilities join an RTO by 2030. If SPP is the
region’s sole RTO, those utilities will only have one choice. The WPP has already organized
WRAP to effectively share resources and ensure grid reliability across a range of western
states.23
As time passes, other initiatives and collaborations might come to fruition, further limiting
California’s participation, design, and governance of these power structures.
COST OF SERVICE AND RATE IMPACTS
Maintaining competitive and stable electric rates remains an essential goal at VPU and was
fundamental in developing the 2023 IRP. VPU customers consistently place affordable rates as
a priority along with reliability.
The modeling and analysis implemented to arrive at the preferred portfolio employed a
comprehensive production cost model to better ensure that the cost of generation to meet
customer demand resulted in competitive and stable rates. Moreover, the 2023 electric cost of
service and rate design study included key components (load forecast and power supply
expenses) in the 2023 IRP. Two factors drive the production cost model: expected cost and
market exposure. The total cost for generating necessary energy is the expected cost; the
23 Sources include: https://blog.ucsusa.org/mark -specht/western-grid-regionalization-is-back-on-the-drawing-board-why-now/;
https://blog.ucsusa.org/vivian -yang/what-does-western-grid-regionalization-mean-for-california/;
https://www.newsdata.com/clearing_up/opinion_and_perspectives/regionalization -of-caiso-draws-much-comment-on-the-
implications/article_df18e672-b9f1-11ed-85ab-33e4c6d21331.html;
and https://www.ucsusa.org/resources/transformin g-western-power-grid
3. Planning Drivers
Cost of Service and Rate Impacts
Vernon Public Utilities 2023 IRP 3-34
amount of energy purchased from the wholesale market and its ability to effectively handle
price volatility is the market exposure.
The preferred portfolio selected through modeling and analysis balances the increases in
renewable generation and zero-carbon generation with providing reliable service and
affordable rates as well as meeting all statutory requirements. VPU’s goal is to strive for
competitive and stable rates and industry best reliability throughout the entire planning period
of 2023 through 2045.
Vernon Public Utilities 2023 IRP 4-1
4. Energy and Demand Forecasts
Energy and peak demand forecasts are foundational in developing the VPU IRP. The growth
of retail energy sales is one of the main drivers for VPU’s decisions on which resources to
acquire and their associated costs. These forecasts identify the energy needed to serve
customers every hour of every day throughout the year, offset by energy efficiency measures
and DERs. The energy and peak demand forecasts dictate the timing of capacity expansion to
meet impending demand plus a planning reserve margin, which in turn, ensures reliable
energy.
In addition, the IRP process considered price forecasts and the impacts of transportation
electrification.
LONG-TERM ENERGY FORECAST METHODOLOGY
Forecasting for this IRP involved several components, among them:
▪ Energy and peak demand forecasts prepared for VPU’s service territory for both the short-
term and the long-term planning periods.
▪ CEC statewide demand and energy forecasts.
▪ Demographic data and demand projections for the Southern California region and Los
Angeles basin.
▪ Hourly electric system loads and the historical penetration of DERs.
Reliability is a critical factor in each of these components.
VPU contracted with NewGen Strategies & Solutions to create the short-term and long-term
forecast of electric demand used in the development of the IRP.
4. Energy and Demand Forecasts
Long-Term Energy Forecast Methodology
Vernon Public Utilities 2023 IRP 4-2
Random Forest Regression
NewGen employed a random forest regression model that produced an hourly system to
forecast demand from 2023 through 2045. The load forecast model relied on VPU historical
hourly load data from 2014, energy efficiency and demand response program performance, the
quantity of rooftop solar installed, and information regarding known loads added to or
removed from the system.
Many predictive models use the forest regression model. It takes historical trends
and utilizes them to create a forecast that would match the predictor variables. Random
forests utilize decision trees, which are binary decisions that the model makes to determine
data classification. The random forest model takes the predictor variables and produces several
forecasts for the most likely value, in this case the kilowatts consumed in a specific hour, given
those predictors.
These forecasts can all differ slightly as each decision tree can go down a different path based
on the input variables. For instance, one tree could decide that all the predictors resemble the
data point from a specific timestamp, still another tree might decide that the predictors most
resemble data from a different timestamp. The model then forecasts usage as such. The
demand at these two times is likely very similar; the model makes several slightly different
decisions to achieve different results. As a result of these variations, the idea behind decision
forests is to obtain the average prediction from many decision trees to determine the best
possible prediction value for the set of predictor variables that are input into the model.
The model ran 500 iterations of hourly forecast simulations based on a normal distributions of
each predicted hour’s standard deviation to account for peak-causing deviations. Monthly and
annual peaks were then obtained from the 500 simulations. The median peak for each month
in the simulation and the tenth percentile peak (fiftieth highest) are then reported in the results.
Historic Forecasting Predictors
The first step in forecasting VPU’s future load was to explore historical patterns and determine
which items would be important in helping to predict future load.
Historic Annual Demand and Energy
Since the year 2000, VPU’s peak demand and energy load has remained relatively flat with
fluctuations due to changes in the economy, customer migration, new customer additions,
weather and distributed energy resources such as energy efficiency measures and solar PV on
customer sites.
4. Energy and Demand Forecasts
Long-Term Energy Forecast Methodology
Vernon Public Utilities 2023 IRP 4-3
Table 7 shows VPU’s actual peak demand and load since 2014, which NewGen used in its
historical modeling.
Year Peak Demand (MW) Load (GWh) Load Factor
2014 191.00 1,184.0 71.0%
2015 197.00 1,164.0 68.0%
2016 194.00 1,154.0 67.0%
2017 184.00 1,129.0 70.0%
2018 182.83 1,125.7 70.3%
2019 180.35 1,122.7 71.1%
2020 191.37 1,168.3 69.5%
2021 194.31 1,220.3 71.7%
2022 189.49 1,150.6 72.3%
Table 7. Historic Annual Peak Demand and Load
Average Daily Profile by Month
The daily load profile changes
each month throughout the
year (Figure 28). From May
through October, a peak
occurs around noon with a
slight increase in usage around
the later evening hours ending
at 9:00 PM. In the other
months, the period from the
hour ending at 10:00 AM to the
hour ending at 2:00 PM is
relatively flat, then ramps
smoothly into the evening
hours. The annual peak for
Figure 28. Average Daily Profile by Month
VPU happens in August while the lowest peak for the year occurs in December. Given the
differing characteristics of monthly load, the modeling process used individual monthly
profiles to predict load values.
4. Energy and Demand Forecasts
Long-Term Energy Forecast Methodology
Vernon Public Utilities 2023 IRP 4-4
Average Daily Profile by Weekday
Analyzing average usage by
weekday shows that:
▪ Sunday has a generally flat
profile and is the lowest
usage day of the week.
▪ Monday has a ramping up
period in the morning that is
lower than other weekdays.
▪ Tuesday through Thursday
periods have similar load
shapes and are the highest
energy usage weekdays.
▪ Friday has a ramping down
Figure 29. Average Daily Profile by Day
period in the afternoon and evening.
▪ Saturday shows significantly less usage than weekdays but does have a distinct ramping
down shape.
Given these distinct shapes (depicted in Figure 29), the modeling and analysis process used
weekday average daily profiles as input in its forecasting.
Average Daily Profile by Holidays
Holidays generally appear to
have load shapes similar to an
average Sunday profile
(Figure 30). The holidays with
the most significant change in
load included New Year’s
Day, Memorial Day,
Independence Day, Labor
Day, Thanksgiving, and
Christmas. The IRP process
reviewed various holidays on
their actual dates versus the
observed dates, with their
observed dates showing the
Figure 30. Average Daily Profile by Holiday
most significant load shape.
4. Energy and Demand Forecasts
Long-Term Energy Forecast Methodology
Vernon Public Utilities 2023 IRP 4-5
Average Daily Profile Changes Over Time
The monthly and yearly
average load shapes have
demonstrated significant
off-peak usage in recent years,
mainly because a significant
off-peak load was added to the
VPU electric system in the
summer of 2020 (Figure 31).
The year 2021 demonstrated
the highest average daily profile
for August; 2017 demonstrated
the lowest. The modeling and
analysis process used a
classifying variable to indicate
Figure 31. Average August Daily Profile
whether a particular period was before or after June 2020.
Historical Weather and 48-Hour Trailing Weather Predictors
Weather plays a significant role in electric load. In hot weather conditions, more energy is
needed to cool homes, businesses, and manufacturing equipment; and in cool weather
conditions, more energy is needed to warm those homes and businesses.
The IRP process used
historical hourly weather data
from the National Centers for
Environmental Information to
obtain the hourly weather for
the last 20 years in the Vernon
region. Next, a weather
normalization analysis was
performed by first applying the
Rank and Average method for
determining normal weather
using the historical 20-year
weather data. This approach
involves ranking each hour of
Figure 32. Example Rank and Average Weather Profiles
a given year by temperature, then taking an average over the first hottest hours, the second
hottest hours, and so on. This results in a dataset ranging from the average hottest
temperatures to the average coldest temperatures. These average temperatures are then applied
4. Energy and Demand Forecasts
Annual Energy and Demand Forecasts
Vernon Public Utilities 2023 IRP 4-6
to the year of interest, aligning the average hottest temperature with the hottest temperature of
the year (depicted in Figure 32).
ANNUAL ENERGY AND DEMAND FORECASTS
The modeling and analysis employed to develop this IRP was based upon an hourly peak
demand and energy forecast for the entire planning period. The model contains a base forecast
created from the random forest model and from individual load modifiers. The combination of
these two items creates the total projected loads.
The cumulative effect of several modifiers adjusts both the peak demand and energy forecasts.
These modifiers include the forecasted impact of solar PV, DERs, load loss, data centers,
hydrogen fuel, public and private electric vehicle charging stations, and energy efficiency
projects. See Appendix D. Annual Energy Forecast Data for the annual adjustments for these
load modifiers.
4. Energy and Demand Forecasts
Annual Energy and Demand Forecasts
Vernon Public Utilities 2023 IRP 4-7
Annual Peak Demand Forecast
Table 8 lists the median peak demand forecast and the tenth percentile peak demand for the
entire planning period. It was calculated from a base peak demand forecast, then modified by
several load factors. The median peak demand forecasts an 18.7 percent increase over the
entire planning period.
Year
Median Peak Demand (MW) 10th Percentile Peak Demand (MW)
Base Peak Load Modifiers Total Peak Base 10th % Peak Load Modifiers Total 10th % Peak
2023 190.2 (13.1) 177.1 192.8 (13.6) 179.2
2024 190.5 (6.5) 184.0 193.1 (2.8) 190.3
2025 190.2 3.7 193.9 192.8 3.9 196.7
2026 190.4 3.3 193.7 192.6 3.6 196.2
2027 190.3 3.8 194.1 192.2 5.4 197.6
2028 190.2 4.5 194.7 192.9 4.2 197.1
2029 190.4 5.2 195.7 193.1 6.5 199.6
2030 190.4 6.8 197.2 192.8 6.2 199.1
2031 190.1 7.0 197.1 192.8 7.2 200.0
2032 190.2 7.7 197.9 192.7 7.8 200.5
2033 190.2 8.4 198.6 192.8 8.7 201.5
2034 190.3 9.4 199.7 192.9 9.6 202.6
2035 190.3 10.3 200.6 193.0 10.7 203.6
2036 190.1 11.1 201.2 192.5 12.2 204.7
2037 190.0 11.6 201.6 192.9 12.2 205.1
2038 190.3 12.8 203.1 192.8 14.0 206.8
2039 190.1 13.8 203.9 192.8 15.1 207.9
2040 190.2 14.7 204.9 192.8 16.1 208.9
2041 190.0 16.0 206.0 192.7 17.3 210.0
2042 190.3 16.8 207.2 193.0 18.1 211.1
2043 190.2 18.0 208.2 192.7 19.4 212.1
2044 190.3 18.6 208.9 192.8 20.4 213.2
2045 190.3 20.0 210.2 192.6 21.6 214.2
Table 8. Annual Peak Demand Forecast (MW)
4. Energy and Demand Forecasts
Annual Energy and Demand Forecasts
Vernon Public Utilities 2023 IRP 4-8
Annual Energy Forecast
Table 9 lists the energy forecast for the entire planning period. It is similar to the peak demand
forecast, whereas the energy forecast calculates the base energy forecast then modified. The
energy forecasts a 21.22 percent increase over the entire planning period.
Energy Forecast (MWh)
Year Base Energy Forecast Load Modifiers Total Energy Forecast
2023 1,206,173 (66,664) 1,139,509
2024 1,209,911 (29,620) 1,180,292
2025 1,206,671 62,717 1,269,388
2026 1,206,554 95,294 1,301,848
2027 1,206,331 99,282 1,305,613
2028 1,209,919 103,575 1,313,494
2029 1,206,551 107,085 1,313,636
2030 1,206,194 110,958 1,317,152
2031 1,206,671 113,425 1,320,096
2032 1,209,992 118,081 1,328,073
2033 1,206,671 122,181 1,328,852
2034 1,206,671 126,557 1,333,228
2035 1,206,671 130,932 1,337,603
2036 1,209,992 135,633 1,345,625
2037 1,206,671 139,684 1,346,355
2038 1,206,671 144,059 1,350,730
2039 1,206,671 148,435 1,355,106
2040 1,209,992 153,186 1,363,178
2041 1,206,671 157,186 1,363,857
2042 1,206,671 161,561 1,368,233
2043 1,206,671 165,937 1,372,608
2044 1,209,992 170,739 1,380,731
2045 1,206,671 174,688 1,381,359
Table 9. Annual Energy Forecast (MWh)
4. Energy and Demand Forecasts
Rooftop Solar PV Installations
Vernon Public Utilities 2023 IRP 4-9
ROOFTOP SOLAR PV INSTALLATIONS
From 2008–2017, VPU implemented a solar incentive program that encouraged commercial
and industrial businesses to install behind-the-meter solar PV systems. VPU serves customers
who participate in the program according to the terms and conditions of the City’s Net
Metering Service Schedule Number NM.
VPU currently has about 5 MW of existing distributed solar PV on the system. VPU is
currently working with customers on approximately 4 MW of added solar load, of which
3 MW is currently under Building & Safety approval process. Stakeholder surveys indicate that
customers are interested in VPU expanding its current program to include community solar,
customer-sited solar installation, and customer-sited solar system maintenance services.
Table 10 shows the historical and forecast values for distributed solar PV installations. Since
behind-the-meter solar power offsets some of VPU’s system load, the solar PV forecast was
applied to VPU peak demand and energy forecasts.
Year Installed Solar PV Capacity (MW) Installed Solar PV Energy (MWh)
2017 2.481 5.02
2018 3.289 6.66
2019 3.379 6.84
2020 3.628 7.36
2021 4.007 8.11
2022 4.303 8.71
2023 5.000 10.12
2024 5.000 10.14
2025 5.000 10.12
2026 5.000 10.12
2027 5.000 10.12
2028 5.000 10.14
2029 5.000 10.12
2030 5.000 10.12
Table 10. Rooftop Solar PV Historical and Forecast Installation Capacity and Energy Forecast
4. Energy and Demand Forecasts
Energy Efficiency Impacts
Vernon Public Utilities 2023 IRP 4-10
The PV Watts software was
used to model the impact of
additional solar installations.
This tool, provided by
National Oceanic and
Atmospheric Administration,
uses the angle and intensity of
sunlight during each hour of
the year in any city to generate
an hourly load profile for
energy offset by VPU’s solar
generators. Figure 33 depicts
the behind-the-meter solar PV
energy forecast for the
short-term planning period.
Figure 33. Behind-the-Meter Solar PV Energy Forecast
ENERGY EFFICIENCY IMPACTS
VPU has implemented various customer programs to promote the efficient use of energy with
a specific focus on key areas such as lighting, refrigeration, and air conditioning. In total, these
programs have generated approximately 3,479 MWh in annual energy savings for fiscal year
2022, and a cumulative net energy savings of 40,485 MWh from fiscal years 2014–2022.
A series of energy efficiency regulations apply to VPU (discussed in Chapter 5. Resource and
Program Review), including SB 1037, AB 2227, and SB 350. The City’s existing and future
building codes also include the state’s green building requirements outlined in Title 24 and
CalGreen, which contains specific regulations for energy efficiency.
In 2021, the California Municipal Utilities Association (CMUA) hired GDS Associates, Inc
(GDS) to analyze and quantify the potential impact of energy efficiency in VPU’s electric
service territory.24 The CMUA study serves as the foundation for VPU’s energy efficiency
targets for fiscal years 2022 through 2031, which is to achieve 2,567 MWh per year in energy
savings and 337 kW per year in demand reduction. The energy savings and demand reduction
figures were derived from the 10-year average of the forecasted figures developed by GDS and
VPU.
VPU remains committed to developing and implementing cost-effective energy efficiency
programs. Because VPU’s customer base is predominantly businesses that operate during
24 https://www.cmua.org/files/CMUA%202020%20EE%20Potential%20Forecast.pdf
4. Energy and Demand Forecasts
Price Forecasts
Vernon Public Utilities 2023 IRP 4-11
daytime hours, future programs will be focused on round-the-clock refrigeration initiatives as
well as lighting and air conditioning impacts from 7:00 AM to 5:00 PM. The modeling for
energy efficiency programs included flat profiles for the times indicated for refrigeration and
lighting, and temperature weighted loads for air conditioning.
PRICE FORECASTS
California currently mandates a 100 percent shift to zero-carbon energy resources by 2045. As
such, the shift in supply forecasts continued growth leading to increasing curtailment
probability, lower average power prices, and increasing price volatility. The heavy solar
generation during the day in California is forecasted to push on-peak power prices in CAISO
below off-peak power
prices in the near-term.
Power Price Forecast
The shift toward low
to zero variable cost
resources is forecasted
to result in power
prices remaining flat
over the long term,
even as natural gas
prices and carbon costs
increase.
Figure 34. CAISO SP-15 Power Price Forecast
4. Energy and Demand Forecasts
Price Forecasts
Vernon Public Utilities 2023 IRP 4-12
Natural Gas Prices
As more resources
with little to zero
variable cost come
online, implied heat
rates will drop,
resulting in natural gas
plants having a harder
time clearing in the
market. Natural gas
prices are expected to
rise over time while
power prices are
expected to fall in the
near-term and remain
flat in the long-term.
Figure 35. SoCal City Gate Natural Gas Price Forecast
Carbon Prices
Adding to the pressure
on natural gas
resources, the cost of
carbon emissions is
expected to continue to
rise and accelerate over
time. Over the course
of the entire planning
period, the carbon
emission costs are
forecast to quintuple.
Figure 36. Carbon Emission Price Forecast
4. Energy and Demand Forecasts
Transportation Electrification Impacts
Vernon Public Utilities 2023 IRP 4-13
TRANSPORTATION ELECTRIFICATION IMPACTS
The transition to transportation electrification has been spurred by SB 350 and three CARB
measures: the ACC II, Advanced Clean Trucks (ACT), and Advanced Clean Fleets (ACF)
rules.
Zero-Emission Vehicle Adoption and Energy Impacts
The CEC’s IEPR, through an additional achievable transportation electrification (AATE)
framework, forecasts the adoption rate and energy impacts from three ZEV sectors (light-duty,
medium-duty, and heavy-duty) by modeling three scenarios:
Baseline Scenario: Economic and demographic inputs; vehicle attributes such as price, range,
refueling time, acceleration, and model availability; federal tax credits, state rebates and
rewards, and high-occupancy vehicle access incentives; incentives resulting from the 2022
Inflation Reduction Act; consumer model preference; and CARB’s Innovative Clean Transmit
regulation.
Scenario 2: Direct, post-process alignment of light-duty ZEV sales that capture delayed
compliance or some exemptions with CARB’s policies, in particular the ACC II rule;
lower prices for medium-duty battery-electric trucks to capture increased electrification.
Scenario 3: Full compliance with all regulations (including the Advanced Clean Fleets
rule) with a postprocess alignment of new vehicle sales with state light-duty and proposed
medium- and heavy-duty regulations.
Figure 37 shows the forecast for medium-duty and heavy-duty ZEVs a few years beyond the
short-term planning period. Scenario 3, which accounts for complying with the Advanced
Clean Fleet rule, shows a population of approximately 200,000 ZEVs by 2031.
Figure 37. Medium- and Heavy-Duty Electric Vehicle Population Forecast
4. Energy and Demand Forecasts
Transportation Electrification Impacts
Vernon Public Utilities 2023 IRP 4-14
Increases in electricity energy consumption complement the increasing ZEV adoption forecast.
The AATE framework used a managed forecast, which is an energy demand scenario that
adjusts a baseline forecast to reflect either or all the following:
▪ The impacts of policies and programs that cannot be included within the basic architecture
of the forecasting model.
▪ Significant uncertainties about existing programs, funding, or implementation features.
▪ Uncertainties regarding new policies and programs motivated by state or federal goals.
Figure 38 depicts the corresponding increase in energy growth over the same adoption rate
period. An increase of approximately 35,000 GWh is forecast for 2031.
Figure 38. Transportation Electrification Demand Forecast
Technological advances have increased the efficiency of ZEVs. Improved fuel economy,
vehicle travel model improvements, and consumption improvements for PHEVs have slightly
lowered the energy consumption of ZEVs.
Electric Vehicle Impact
While its residential population is low, the City of Vernon sees an influx of almost 50,000
vehicles every day. Because of the ACC II rule, an increasing number of these vehicles will be
ZEVs, and thus increase energy demand and the need for plug-in electric vehicle (PEV)
charging stations.
As of 2022, the City of Vernon had over 120 electric-based, light-duty vehicles registered across
one zip code, which is approximately three percent of all light-duty vehicles in Vernon’s service
territory.25 In addition, VPU expects that several commercial and industrial fleets will
transition to ZEVs, including the City of Vernon’s municipal fleet.
By 2026, over 30 percent of light-duty vehicles in VPU’s territory are expected to be zero-
emissions to meet the ACC II mandate. Based on this knowledge, VPU’s 2023 IRP considered
the increased energy demands of transportation electrification and incorporated various state
mandates in effect.
25 https://www.energy.ca.gov/data-reports/energy-almanac/zero-emission-vehicle-and-infrastructure-statistics/light-duty-vehicle
4. Energy and Demand Forecasts
Transportation Electrification Impacts
Vernon Public Utilities 2023 IRP 4-15
To forecast EV penetration over the short-term planning period, the IRP process used two EV
load profiles: one for public daytime charging and one for non-business hour charging (mostly
for fleets).
The load profiles include an area to scale the amount of anticipated energy for both types of
charging, which was then added to the hourly forecasts. The model assumed fleets grew based
on the City of Vernon’s vehicle electrification plan. The model assumed that approximately
2,500 passenger EVs were added each year, which represents an estimated five percent of the
50,000 vehicles estimated to enter Vernon daily. Finally, the model assumed that 35 percent of
these EVs were charged in Vernon, each averaging 5,000 kilowatt hours (kWh) of total
charging consumption annually.
VPU estimated the increase in PEV adoption compared to the overall adoption rate for the
entire state. Table 11 lists the California and VPU forecast for PEV adoption levels; light-duty,
medium-duty, and heavy-duty ZEV penetration, both for the next decade; together with the
small amount of corresponding addition to peak demand and energy consumption for the
VPU PEV population.
Year
California
PEVs VPU PEVs
Light-Duty
ZEVs
Medium & Heavy
Duty ZEVs
Vernon
ZEVs
Peak Demand
(MW)
Energy
(GWh)
2023 1,394,050 836 1,478,300 5,705 2,500 0.8 4.2
2024 1,625,912 976 1,980,449 7,564 5,000 0.9 4.9
2025 1,866,987 1,120 2,522,018 15,293 7,500 1.1 5.5
2026 2,114,946 1,269 3,024,620 25,066 10,000 1.2 6.2
2027 2,367,753 1,421 3,550,516 39,570 12,500 1.3 6.9
2028 2,623,702 1,574 4,123,937 58,534 15,000 1.4 7.5
2029 2,881,494 1,729 4,743,520 82,450 17,500 1.6 8.2
2030 3,140,242 1,884 5,437,522 108,278 20,000 1.7 8.9
2031* 3,378,183 2,027 6,179,620 137,783 22,500 1.8 9.5
2032* 3,628,471 2,177 6,976,097 168,022 25,000 2.0 10.2
2033* 3,878,759 2,327 7,831,051 198,792 27,500 2.1 10.9
2034* 4,129,047 2,477 8,749,727 229,097 30,000 2.2 11.5
2035* 4,379,335 2,628 9,762,085 262,568 32,500 2.3 12.2
* Amounts in these rows highlighted in blue are extrapolated from 2023–2030 data
Table 11. Plug-In Electric Vehicle Adoption Forecast and Load Impacts
In 2023, the capacity (in MW) required for charging PEVs in the City of Vernon represented
only 0.45 percent of peak demand. By 2035, that amount rises to 1.17% of peak demand, an
increase of almost 260 percent. Similarly, the energy (in GWh) required for charging PEVs in
the City represented only 0.38 percent. By 2035, that amount rises to 0.94 percent, an increase
of almost 250 percent.
4. Energy and Demand Forecasts
Transportation Electrification Impacts
Vernon Public Utilities 2023 IRP 4-16
Scenario 2 from the CEC’s IEPR forecasts an increase of approximately 1,000 percent by 2035,
from approximately 5,000 GWh to approximately 50,000 GWh (see Figure 38).
Table 12 lists the changes in EV coincident peak demand, energy load, GHG emission due to
increasing ZEV penetration, and the increasing number of EV in the City of Vernon contrasted
with the equivalent emissions from the gas-powered vehicles they replace.
Year
EV Coincident
Peak (MW)
EV Energy Load
(GWh)
GHG Emissions
(MT) Number of EVs
Equivalent Emissions
from Gas Vehicles (MT)
2024 0.26 4.79 2,340 5,000 5,406
2025 2.26 9.40 4,592 7,500 10,608
2026 3.00 14.01 6,843 10,000 15,810
2027 4.53 18.62 9,095 12,500 21,013
2028 5.60 23.19 11,327 15,000 26,170
2029 6.90 27.67 13,516 17,500 31,226
2030 7.48 32.04 15,650 20,000 36,157
2031 8.38 36.42 17,790 22,500 41,100
2032 9.11 45.30 22,127 25,000 51,121
2033 10.01 49.55 24,203 27,500 55,918
2034 10.90 53.92 26,338 30,000 60,849
2035 11.79 58.30 28,477 32,500 65,792
2036 13.16 62.85 30,700 35,000 70,927
2037 13.54 67.05 32,751 37,500 75,666
2038 14.49 71.43 34,891 40,000 80,609
2039 15.39 75.80 37,025 42,500 85,541
2040 16.32 80.41 39,277 45,000 90,743
2041 17.17 84.55 41,299 47,500 95,415
2042 18.06 88.93 43,439 50,000 100,358
2043 18.95 93.30 45,573 52,500 105,290
2044 19.90 97.96 47,849 55,000 110,549
2045 20.77 102.05 49,847 57,500 115,164
Table 12. Peak Demand, Energy, and GHG Emission Impacts of ZEV Penetration
Vernon Public Utilities 2023 IRP 5-1
5. Resource and Program Review
As required by SB 350, the CEC established annual targets that will achieve a cumulative
doubling of statewide energy efficiency savings as well as demand reductions in electricity and
natural gas end uses by 2030. In addition, Executive Orders N-79-20 and B-32-15 established
targets for ZEV sales and expansion of EV charging infrastructure. AB 617 directed CARB and
all local air districts to take measures to protect disadvantaged communities (DACs) from
adverse impacts of air pollution.
VPU offers several incentives and programs to support energy efficiency, demand response,
and EV adoption to align with the state’s climate and transportation electrification goals. VPU
is also actively investing in expanding EV charging infrastructure for the public and for the
City of Vernon’s EV fleet.
ENERGY EFFICIENCY TARGETS
PUC Section 9621 requires the CEC to address energy efficiency and DSM programs, energy
storage, RA, and transportation electrification. SB 350 established annual targets for statewide
AAEE savings and demand reduction that will produce a cumulative doubling of statewide
energy efficiency savings for end-use retail customers by 2030. Utility and non-utility programs
for both gas and electricity can contribute toward that goal.
Table 13 contains VPU’s annual and cumulative energy efficiency saving targets with CEC
adjustments.
VPU 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Annual 6 2 4 3 3 3 4 4 3 3 3 3 3 2 2
Cumulative 6 8 12 15 18 21 25 29 32 35 38 41 44 46 48
Table 13. Annual Electricity Savings Targets with Adjustments (GWh)26
26 Senate Bill 350: Doubling Energy Efficiency Savings by 2030. California Energy Commission. Publication Number:
CEC-400-2017-010-CMF; Table A-10.
5. Resource and Program Review
Energy Efficiency Programs
Vernon Public Utilities 2023 IRP 5-2
Adjustments to these targets generally involve shifting savings to avoid double counting, and to
extrapolate savings for 2027 through 2029. VPU continues to utilize all available resources to
achieve the energy efficiency targets, including continued implementation of its long-standing
customer programs and identifying future challenges that can drive the development of new
offerings and services.
ENERGY EFFICIENCY PROGRAMS
To comply with AB 1890, VPU must charge 2.85 percent of electric revenues to implement the
following Public Benefit program categories:
▪ Cost-effective energy efficiency programs and services
▪ Development and implementation of existing and emerging renewable resource
technologies
▪ Research, development, and demonstration programs and projects
▪ Income-qualified bill assistance
Since 2011, VPU has offered cost effective energy efficiency and DSM programs to achieve its
annual savings targets and assist customers in managing their energy bills. These programs
include incentives to explore and implement energy efficiency technologies. The current VPU
program provides incentives to customers for energy savings that are obtained by retrofitting to
LED lighting technology and installing energy efficient equipment. In addition, VPU also
offers free comprehensive energy audits to all electric customers, which provide a starting point
for organizations interested in developing a broader energy management strategy. Through this
service, customers receive a detailed analysis of their energy consumption, coupled with
suggested energy efficiency improvements, to realize cost savings.
To comply with SB 350, VPU has established annual targets for statewide energy efficiency
savings and demand reduction that will achieve a cumulative doubling of energy efficiency
savings from retail customers by January 1, 2030. Through its comprehensive energy audit
services and overall customer education, VPU has encouraged its commercial and industrial
customers to remain steadfast in evaluating ongoing potential energy savings realized by
replacing inefficient compressors or use of heat conversion and refrigeration controls
technology to save energy. VPU has also sought energy efficiency savings through water and
gas infrastructure upgrades, distribution system equipment and conductor upgrades, and
retrofitting City facilities.
The increases in energy efficiency savings are reflected in the VPU peak demand and energy
forecasts.
5. Resource and Program Review
Energy Efficiency Programs
Vernon Public Utilities 2023 IRP 5-3
Demand Response Programs
Based on its commercial and industrial customer base, VPU has limited capabilities for
demand response (DR) programs since most business processes cannot be readily interrupted
to avoid economic losses from a lapse in customer production processes. Since VPU customers
did not indicate a strong interest in traditional DR programs, DR resources are not included as
candidate resource options in the modeling for a preferred portfolio. Nevertheless, VPU
continues to identify strategic partnerships to advance energy storage on customer premises as
a form of DR.
VPU implements a few reliability-driven programs and services that differ from traditional DR
offerings. For example, VPU offers a voluntary load reduction program in the form of
discounted rates to customers who can reduce their load in the event of an energy emergency.
Demand-Side Management Programs
VPU offers several energy efficiency and DSM programs for its commercial and industrial
customers.
Customer-Directed Programs. VPU funds customized projects demonstrating energy
efficiency and cost savings. Customers must fund at least 25 percent of the total project cost.
Projects are only eligible if they do not qualify for the other programs.
Energy Audit Program. This program provides free on-site audits for commercial and
industrial customers, and includes a comprehensive audit that analyzes a customer’s energy
usage and costs, identifies potential energy conservation measures, and recommends efficiency
improvements.
Time-of-Use Rate Programs. Any customer with an electrical load that exceeds 100 kW is
eligible for time-of-use rates. By shifting energy usage to times of the day when electric rates
are lower, customers can achieve cost savings. In addition, energy consumption by customers
during off-peak hours also lowers VPU’s peak demand, which potentially defers the need to
add more resource capacity. Most of VPU’s large commercial and industrial customers use the
TOU rate schedule.
Customer Incentive Program. This program funds the retrofit and implementation of energy
efficiency technologies and equipment, such as LED lighting, variable speed drives, air
compressors, motors, refrigeration, and air conditioning upgrades. The City of Vernon, also a
VPU electric customer, successfully utilized this program to retrofit city facilities with LED
lighting to reduce energy consumption in municipal operations.
Net Energy Metering. Since January 2010, VPU has offered a NEM program for customers
that install qualifying solar PV systems on their premises.
5. Resource and Program Review
Energy Efficiency Program Impacts
Vernon Public Utilities 2023 IRP 5-4
ENERGY EFFICIENCY PROGRAM IMPACTS
The impacts from VPU’s energy efficiency and DSM programs are quantified in Table 14,
which contains the annual net savings in MWh from fiscal years 2014–2022.
Description
Installation Year and MWh Savings
2014 2015 2016 2017 2018 2019 2020 2021 2022
Cumulative Net 2,299 8,123 10,253 12,349 17,733 25,387 33,967 37,006 40,485
First Year Net 2,299 5,824 2,130 2,096 5,384 7,654 8,580 3,039 3,479
Lifecycle Net 25,943 17,689 12,615 17,826 66,720 92,782 108,940 38,250 46,866
Table 14. Cumulative Historical Energy Efficiency Savings: Fiscal Years 2014–2022
Energy Efficiency Incentive Program
Improvements in lighting technology have resulted in efficient LED solutions that use less
energy and create a longer, useful life. The VPU Customer Incentive Program provides rebates
on above code kWh savings from LED lighting retrofits. The non-lighting incentive portion of
the VPU program includes variable speed drives, air compressors, motors, refrigeration, chiller
replacement, air conditioner replacement, and building envelope upgrades. The program also
includes rebates for the above-code savings generated via energy management systems or other
load-controlling devices.
Table 15 lists the energy savings for the Customer Incentive Program from fiscal years 2018
through 2022.
Program
Savings
FY 2018 FY 2019 FY 2020 FY2021 FY2022
MWh MW MWh MW MWh MW MWh MW MWh MW
Lighting 4,528 0.95 7,209 1.67 6,585 0.98 2,687 0.43 2,934 0.65
Non-Lighting 856 0.00 445 0.00 1,995 0.02 352 0.13 545 0.04
Total 5,384 0.95 7,654 1.67 8,580 1.00 3,039 0.56 3,479 0.69
Table 15. Historical Lighting Incentive Program Savings: Fiscal Years 2018–2022
5. Resource and Program Review
Energy Efficiency Potential Forecasts
Vernon Public Utilities 2023 IRP 5-5
ENERGY EFFICIENCY POTENTIAL FORECASTS
To comply with AB 2021, POUs like VPU must identify 10-year energy efficiency and
demand reduction forecasts every three years. AB 2227 changed the adoption timeline from
every three years to every four years, starting in 2013. VPU’s current ten year forecast runs
from 2022–2031, with a four-year adoption timeline from fiscal year 2022 through fiscal year
2025.
VPU’s annual energy efficiency and demand reduction targets are 2,567 MWh and 337 kW.
The targets were derived based on the ten-year average market potential.
Energy Efficiency Potential Forecasting Study
VPU contracted with GDS to conduct the 2020 California Municipal Utilities Association
(CMUA) Energy Efficiency Potential Forecasting Study. The study results are specific to
VPU’s service territory and account for unique characteristics, customer base, climate zone,
economic conditions, and other relevant factors. The study forecasted potential energy
efficiency savings for 2022 through 2031. VPU plans to conduct the next study during fiscal
year 2025 to forecast potential savings for 2026 through 2035.
The study provides a roadmap for VPU as it develops strategies and programs for energy
efficiency. The development of market potential estimates for a range of feasible measures is
useful for program planning and modification purposes.
Summary of Market Potential
VPU’s cumulative energy efficiency potential forecast from fiscal year 2022 through fiscal year
2031 is pre-set at 25,665 MWh. This results in an average annual gross savings target of
0.22 percent of forecasted retail energy sales. Table 16 contains the specific annual demand
reduction impacts by sector. These data were used to create Figure 39: Net Incremental
Market Potential by Sector (MWh) and Percent of Sales.
10-Year Demand Goals (Incremental kW)
All Sectors 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Total Market Potential 749 765 694 604 356 103 40 16 17 18
Residential Market Potential 0 0 0 0 0 0 0 0 0 0
Non-Residential Market
Potential 749 765 694 604 356 103 40 16 17 18
Table 16. Net Incremental Market Demand Potential By Sector
5. Resource and Program Review
Energy Efficiency Potential Forecasts
Vernon Public Utilities 2023 IRP 5-6
Table 17 contains the specific annual energy impacts by sector. These data were also used to
create Figure 39: Net Incremental Market Potential by Sector (MWh) and Percent of Sales.
10-Year Energy Goals (Incremental Net MWh)
All Sectors 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Total Market Potential 5,247 5,504 5,069 4,489 2,575 876 564 446 445 449
Residential Market Potential 0 0 0 0 0 0 0 0 0 0
Non-Residential Market
Potential 5,247 5,504 5,069 4,489 2,575 876 564 446 445 449
Total Potential as a % of Total
Sales 0.45% 0.47% 0.44% 0.39% 0.22% 0.08% 0.05% 0.04% 0.04% 0.04%
Residential Potential as a % of
Residential Sales 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%
Non-Residential Potential as
a % of Non-Residential Sales 0.45% 0.47% 0.44% 0.39% 0.22% 0.08% 0.05% 0.04% 0.04% 0.04%
Table 17. Net Incremental Market Energy Potential By Sector
The energy impacts are a percentage of forecasted sector-level and total sales. Incremental
annual savings range from 2,622 MWh to 9,912 MWh, which corresponds to 0.04 percent to
0.47 percent of forecasting sales.
Figure 39 depicts the
market potential for
the residential and
non-residential sectors,
as well as the total
incremental potential
as a percentage of total
sales for the 10-year
period of 2022 to 2031.
At a glance, the City of
Vernon’s results
include:
▪ A 2022–2031
average annual
gross savings target
Figure 39. Net Incremental Market Potential by Sector (MWh) and Percent of Sales
of 0.22 percent of forecasted retail sales.
▪ A 2022–2031 average annual net savings target of 0.22 percent of forecasted retail sales.
The results also include separate estimates of the future energy savings impact from Codes and
Standards advocacy.
5. Resource and Program Review
Energy Efficiency Potential Forecasts
Vernon Public Utilities 2023 IRP 5-7
Codes and Standards
The summary of potential energy efficiency savings represents the base case results. GDS also
produced estimates of savings claims for Codes and Standards advocacy. Table 18 lists the
base market potential and an estimate of Codes and Standards advocacy savings. The Codes
and Standards estimates are considered as secondary to the base market potential.
10 Year Energy Goals (Incremental Net MWh)
All Sectors 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Base Market Potential 5,247 5,504 5,069 4,489 2,575 876 564 446 445 449
Codes & Standards Advocacy 4,209 4,118 3,790 3,699 3,547 3,390 3,153 2,766 2,450 2,138
Table 18. Net Incremental Market Potential – Base And Codes and Standards
Potential Net Market Energy Efficiency Savings
Figure 40 depicts the
incremental net market
potential energy
efficiency energy
savings (in MWh) until
2031. The impact of
energy savings through
Codes and Standards
savings are also
included. The
residential impact is
minimal due to the
small number of
residential accounts in
VPU’s territory.
Figure 40. Incremental Net Market Energy Efficiency Potential by Sector
5. Resource and Program Review
Transportation Electrification
Vernon Public Utilities 2023 IRP 5-8
Figure 41 depicts the
cumulative net market
potential energy
efficiency energy
savings (in MWh) until
2031. The impact of
energy savings through
Codes and Standards
savings are also
included. The
residential impact is
minimal due to the
small number of
residential accounts in
VPU’s territory.
Figure 41. Cumulative Net Market Energy Efficiency Potential by Sector
TRANSPORTATION ELECTRIFICATION
Emissions from the transportation sector constitute California’s largest source of GHGs,
representing more than double the GHG emissions associated with the electricity sector.27
Transportation electrification helps reduce GHG emissions while meeting California’s
aggressive climate goals. Executive Order B-48-18 signed by Governor Brown in 2018 set a
target for five million zero-emission vehicles and 250,000 public EV charging stations by 2030.
In 2020, Governor Newsom set a goal under Executive Order N-79-20 for all in-state sales of
new passenger to be zero-emissions by 2035 and all new medium and heavy-duty vehicles to
be zero-emission by 2045.28
VPU is committed to supporting the transportation electrification goals set by California and
align with the state’s GHG emissions reduction targets.
27 https://ww2.arb.ca.gov/ghg-inventory-data
28 https://www.cpuc.ca.gov/industries -and-topics/electrical-energy/infrastructure/transportation-electrification
5. Resource and Program Review
Transportation Electrification
Vernon Public Utilities 2023 IRP 5-9
Transportation Electrification Programs
To help support the growth of transportation electrification, VPU has several incentive
programs designed to encourage the adoption of EVs and expand EV charging infrastructure.
VPU Commercial EV Charger Incentive Program. This program is designed to offset the
upfront costs of purchasing and installing qualifying EV chargers for your business, fleet, or
employees. All commercial VPU electric customers can receive a $3,000 rebate per port for the
installation of a qualifying smart L2 EV charger. Additional bonus incentives are available for
VPU customers that install L3 DCFCs or install qualifying smart L2 EV chargers at affordable
housing structures serving 80 percent or more income-qualified individuals (defined as persons
and families at or below 50 percent of Los Angeles County median income, adjusted for family
size and revised on an annual basis).
VPU Commercial Electric Forklift Incentive Program. This program is designed for
commercial and industrial customers looking to electrify their forklift fleet. VPU offers a
$3,000 rebate toward the lease or purchase of an electric forklift. VPU recognizes the
importance of reducing GHG emissions through electrifying the movement of goods and
off-road vehicles.
VPU Residential EV Rebate Program. This program provides eligible residential electric
customers with $2,500 for purchasing or leasing an EV and $2,500 for installing a qualifying
EV charger.
VPU continues to explore additional opportunities to provide incentives for the electrification
of medium- and heavy-duty vehicles and rail.
Customer Education and Outreach
VPU cross-promotes several external resources available for customers who are looking to
make the switch to electric vehicles or considering installing EV charging infrastructure.
The “Electric For All” platform, available through Veloz, contains a wealth of resources
designed to inform utility customers on everything related to EVs. This includes a tool to
search for various consumer electric vehicle and charger incentives. The platform also contains
a home charging advisor who can estimate the cost of equipment, installation, and operation
of EV chargers.
The “Replace Your Ride” program from the South Coast Air Quality Management District
(SCAQMD) offers up to $9,500 to replace gasoline vehicles 2007 or older with EVs for
qualifying customers.
The CA Clean Vehicle Rebate Program offered by CARB provides up to $7,500 in rebates for
qualifying customers to buy or lease an eligible EV.
5. Resource and Program Review
Transportation Electrification
Vernon Public Utilities 2023 IRP 5-10
To increase community awareness and engagement, VPU has developed a custom branding
called “Electrify Vernon” placed on all of the publicly available DCFCs owned by the City of
Vernon. VPU promotes its public EV charging depots on the City’s social media accounts
along with content in its newsletters. VPU is working closely with its customers to better
understand the different transportation electrification roadmaps for each organization and how
VPU can provide support through this transition, either with infrastructure adjustments or
financial incentives. VPU continues to consider additional customer education and outreach to
support transportation electrification.
Electric Vehicle Charging Rates
VPU offers qualifying commercial electric customers a time-of-use rate plan (TOU-V)29. The
TOU-V electric rate schedule includes the following monthly charges:
▪ Customer and automated meter reading (AMR) charges that remains the same year-round.
▪ Energy charge for on-peak, mid-peak, and off-peak
energy charges for the summer and winter seasons.
▪ Demand charge for on-peak and mid-peak charges for
summer and winter seasons. Off-peak is not charged,
but customers are subject to minimum demand charges.
The summer season runs from May 1 through October 31
each year; the winter season runs from November 1
through April 30. On-peak hours are 1 PM to 7 PM on
summer weekdays except holidays. Mid-peak hours are 9 AM to 1 PM and 7 PM to 11 PM on
summer weekdays except holidays, and 8 AM to 5 PM on winter weekdays except holidays. All
other hours are off-peak.
In the near term, VPU plans to review electric rate design options for electric vehicles.
Municipal Fleet
The City of Vernon’s municipal fleet consists of nearly 200 vehicles, including approximately a
dozen light-duty EVs that are currently in operation. The City is planning to add ten more
EVs. Out of these ten, three EVs have been ordered and will be delivered in the near future; the
remaining seven EVs will be integrated into the city fleet as existing ICE vehicles are replaced
and taken out of operation. Both VPU and the City will continue to evaluate opportunities to
convert older and higher polluting fleet vehicles to EVs as more options become available from
vehicle manufacturers.
29 https://www.cityofvernon.org/government/public -utilities/rates-fees/-folder-49
5. Resource and Program Review
Transportation Electrification
Vernon Public Utilities 2023 IRP 5-11
Electric Vehicle Charging Infrastructure
VPU continues to expand its EV charging infrastructure for the public, City employees, and
the municipal fleet while utilizing its incentive programs to encourage the installation of EV
chargers on private properties.
VPU is also proactively transforming its power distribution systems to accommodate the
growth of EV charging. In particular, the utility’s 2020 CIP included funding to replace aging
substation transformers, upgrading them with a reliability investment for a voltage conversion
that added capacity. These distribution upgrades formed the structural underpinnings
necessary to expand future EV charging infrastructure. The upgrades enabled VPU to engage
various commercial and industrial customers who are interested in increasing their existing
capacity to electrify their fleet.
EV Charging Station Installations
Starting with the City of Vernon, VPU has installed L2 EV chargers at several city sites, with
plans to continue and expand the availability of EV charging to support current and future
needs of employees and the municipal fleet. To promote adoption of EVs among city
employees and provide EV charging to the existing city fleet, VPU installed over 40 L2 EV
chargers at Vernon City Hall. In addition, VPU also installed four L2 EV Chargers at MGS to
support fleet and employee charging. VPU plans to continue to offer utility and City
employees with access to EV charging infrastructure located in employee and fleet parking
facilities.
VPU has expanded its public EV charging infrastructure with several new capital projects,
including two future sites that are anticipated to be completed in 2024. In July 2023, VPU
partnered with Tesla to launch its first public DCFC site. The Soto EV Charging Depot
features ten ChargePoint DCFCs that deliver up to 62.5 kW of energy and eight Tesla V3
Superchargers. VPU plans to partner with Tesla to open its second site called the Alameda EV
Charging Depot, which will also be equipped with a mixture of ChargePoint DCFCs and
Tesla V3 Superchargers. VPU is currently developing its third, public DCFC site that will offer
between 10 to 14 L3 EV chargers.
Future EV Charging Station Projects
The City of Vernon is anticipating the launch of its first commercial fleet charging depot soon.
The EV charging depot will be equipped with a mixture of L2 and L3 fast chargers. VPU is
working to provide temporary electricity service so the depot can be operational by the end of
the calendar year.
VPU expects the electric load to be approximately 3 MW once the depot becomes fully
operational. VPU is actively working to connect Vernon businesses that are interested in a
5. Resource and Program Review
Underserved and Disadvantaged Community Initiatives
Vernon Public Utilities 2023 IRP 5-12
dedicated site for commercial EV fleet charging. The City’s end goal is to meet the growing
needs and goals of transportation electrification for local companies.
UNDERSERVED AND DISADVANTAGED COMMUNITY INITIATIVES
VPU is committed to ensuring that potential impacts on income-qualified customers and
DACs are a primary consideration when designing EV programs and expanding EV charging
infrastructure.
EV Chargers in DACs
Based on the California Office of Environmental Health Hazard Assessment (OEHHA),
VPU’s entire electric service territory (zip code 90058) is located in a DAC. VPU is actively
addressing the lack of EV charging infrastructure in the DAC by launching its first publicly
available L3 DCFC depot in July 2023. A second proposed site is scheduled to be completed
by the end of 2023, with a third proposed site scheduled for completion in 2024. All three of
the public DCFC depots are located close to several major interstate and intrastate highways.
Vernon’s public EV charging depots provides the infrastructure necessary to support battery
electric vehicles in the “Gateway Cities” region in Southern California and help encourage the
adoption of zero emission electric vehicles in underserved communities.
As noted under the “Transportation Electrification Programs” section, EV charging
infrastructure serving affordable housing qualifies for additional “bonus” incentives of up to
$12,000 per eligible EV charger. VPU residential customers can also receive up to $5,000 with
the purchase of a qualifying EV and installation of an eligible EV charger. VPU will continue
to offer rebates and work closely with its customers to remove EV adoption barriers across its
service territory.
Environmental Sustainability
AB 617 directed CARB and all local air districts, including the South Coast Air Quality
Management District (SCAQMD), to take measures to protect communities disproportionally
impacted by air pollution. The bill promoted the development of a new community-focused
program to effectively reduce exposure to air pollution and preserve public health. Among the
highest priority communities are East Los Angeles, Boyle Heights, and West Commerce;
southeast Los Angeles; and south Los Angeles, all areas that are in close proximity to the City
of Vernon.
5. Resource and Program Review
Underserved and Disadvantaged Community Initiatives
Vernon Public Utilities 2023 IRP 5-13
Vernon is developing an Environmental Sustainability Action Plan to comply with AB 617.
The City has solicited a survey to gather the top concerns of residents and city employees. The
Sustainability Action Plan is expected to be finalized later this year. In the meantime, the City
has already undertaken a number of initiatives toward this issue.
Vernon Public Works developed of an Urban Tree Canopy assessment in partnership with
Gateway Cities Council of Governments (GCCOG), Loyola Marymount University Center
for Urban Resilience (LMU CURes), and TreePeople. The assessment found that up to
51 percent of the City’s surface area could accommodate tree plantings; it also identified highly
suitable locations for prioritizing plantings. The Urban Tree Canopy anticipates
communitywide benefits from tree plantings that include greener spaces and beautification,
shading, mitigation from heat, improvements to local air quality, and improvements to
pedestrian pathways. The City of Vernon is recognized as a Tree City by the Arbor Day
Foundation.
As the City’s electric utility, VPU:
▪ Has reduced generation from its local natural gas power plant, MGS, over the last year by
approximately 23 percent by favoring lower cost renewables during peak production of
renewables. This reduction has also reduced GHG emissions in the area.
▪ Continues to provide free comprehensive energy audits for industrial businesses that are
uniquely tailored to their needs. Recommendations include efficient lighting, cold storage
refrigeration, and energy efficient machinery.
▪ Offers two rebate programs that help reduce GHG emissions: a rebate of up to $5,000 for
EV purchases for residential electric customers and a broader GHG reduction rebate for gas
customers. Using the gas utility’s GHG reduction rebate, VPU has funded Vernon business
customers’ unique GHG reduction programs including the purchase of lower emission
machinery, electric forklifts, and natural gas truck fueling stations.
▪ Provides net metering rates for customers who install behind-the-meter renewable
generation.
The City of Vernon and VPU continue to explore, and implement, when possible, initiatives
that support GHG emission reductions that directly affect DACs.
Vernon Public Utilities 2023 IRP 6-1
6. Transmission and Distribution
BULK TRANSMISSION SYSTEM
Bulk Transmission System
VPU is a POU whose load is under CAISO’s jurisdiction. Most of VPU’s load and generation
capacity is within the CAISO BA. As such, VPU accesses the CAISO transmission grid for
delivery of its market energy purchases and regional PPA generation to its energy needs.
VPU customers, through their electric rates, pay a transmission access charge (TAC) and a grid
management charge (GMC), through a Transmission Control Agreement (TCA), to CAISO
for transmission access. VPU was one of many Participating Transmission Owners (PTOs) in
CAISO. Capital costs for transmission system upgrades and expansions within CAISO’s
transmission network are included in the TAC and GMC and recovered through CAISO’s
TCA.
Transmission Service Agreements
The City of Vernon had executed CAISO’s TCA in 2001 and was a PTO, only by virtue of its
three Existing Transmission Contracts (ETCs), which were turned over to CAISO’s
Operational Control as Transmission Entitlements.
VPU relied on transmission contracts with Los Angeles Department of Water and Power
(LADWP) and Southern California Edison (SCE) to transmit its out-of-state power resources
to its electric system load.
These contracts entitled VPU to:
▪ Victorville-Lugo Midpoint 500 kV line that interconnects the LADWP Victorville
substation to the SCE Lugo substation.
▪ Lugo Midpoint-Laguna Bell 500 kV line that interconnects the SCE Lugo substation to the
Vernon Laguna Bell substation. These rights included transmitting the capacity from the
Palo Verde Nuclear Generating Station in Arizona.
6. Transmission and Distribution
Bulk Transmission System
Vernon Public Utilities 2023 IRP 6-2
▪ Mead-Laguna Bell 230 kV line that interconnects the SCE Mead substation to the Vernon
Laguna Bell substation. These rights included transmitting the capacity from the Hoover
Dam Hydroelectric Power Plant in Nevada.
On October 7, 2022, VPU terminated all three of its transmission contracts with SCE and
LADWP after determining that the existing ETCs were no longer economically beneficial for
its ratepayers. As a result, VPU no longer participates in the CAISO market as a PTO. VPU
continues to participate in the CAISO market as a metered subsystem (MSS) under an MSS
Agreement with CAISO. CAISO concurred with the termination of these three ETCs and
Entitlements, and VPU’s withdrawal from the TCA. VPU then filed for FERC approval to
terminate its Transmission Owner (TO) Tariff and received approval in 2023.
Laguna Bell Corridor Line Upgrades
In 2020, CAISO approved a major upgrade to the Laguna Bell transmission corridor. An
assessment of the SCE metro area identified thermal overloads on the transmission line.
The Laguna Bell-Mesa #1 230 kV line overloaded for a common-mode P7 outage as well as
for P3 and P6 contingencies. The Laguna Bell-Mesa #1 230 kV line overload mitigation
identified in the policy-driven needs assessment eliminated the overloads.
SCE submitted a proposal to reconductor the existing Laguna Bell-Mesa #1 230 kV line with
Aluminum Conductor Composite Core (ACCC) conductors to increase the line rating. The
project could address the portfolio resource deliverability issue identified in the policy-driven
transmission analysis and provide reliability and economic benefits. The length of the line to be
rewired is approximately five miles. The targeted in-service date is the fourth quarter of 2023.
The initial conceptual estimated cost for the project is $15 million. After further evaluation,
SCE adjusted the cost to $17.3 million, which includes necessary upgrades of the Laguna Bell
Substation terminal equipment that were not part of the original estimate.
The project increases the line rating by approximately 42 percent, to 3250/4760 amps SN/SE.
When completed, the line upgrade will mitigate P3 (generator outage followed by loss of
another element), P6 (loss of two non-simultaneous elements), and P7 (loss of two circuits on a
common tower) contingencies.
6. Transmission and Distribution
Distribution System
Vernon Public Utilities 2023 IRP 6-3
Table 19 lists the four upgrades that are being implemented on the Laguna Bell-Mesa #1
230 kV transmission line.
Year Item
Existing
Emergency
Rating* Contingency Category
Post
Contingency
Loading
Proposed
Emergency
Rating*
Contingency
Loading with
Proposed Upgrade
2023 1 3341/1331 Lighthipe-Mesa & Laguna
Bell-Mesa #2 230 kV lines P7 103% 4760/1896 ≤100%
2026 2 3341/1331 Lighthipe-Mesa & Laguna
Bell-Mesa #2 230 kV lines P7 104% 4760/1896 ≤100%
2031 3 3341/1331 Lighthipe-Mesa 230 kV line &
Huntington Beach Repower P3 104% 4760/1896 ≤100%
2031 4 3341/1331 Lighthipe-Mesa & Laguna
Bell-Mesa #2 230 kV lines P7 112% 4760/1896 ≤100%
* Ratings are amperes/mega volt-ampere (MVA)
Table 19. Laguna Bell-Mesa #1 230 kV Line Rating Increase Summary
Transmission deliverability into the Los Angeles Basin and the local capacity requirement
(LCR) will also benefit from these line upgrades.
DISTRIBUTION SYSTEM
VPU has maintained a highly reliable electric system
as evidenced by its Diamond Level RP3 designation
over the last nine years from the APPA (see “Award
Winning Grid Reliability and Service” on page 2-10).
VPU’s distribution system is located entirely within
the CAISO BA. It is connected to CAISO
transmission and distribution system through the
SCE 220-66 kV Laguna Bell Substation. Five 66 kV source lines that exit the SCE Laguna Bell
220-66 kV Substation supply and support the Vernon load. Due to the presence of local MGS
generation, VPU’s electric system is able to withstand a double contingency (N-2) situation
when two 66 kV transmission lines are out of service.
VPU’s service territory includes approximately 145 miles of transmission and distribution lines
and includes three voltage levels: 7 kV, 16 kV, and 66 kV. Approximately 80 percent of the
distribution system conductors and lines are overhead. The VPU electric system has nine
substations. Four (Leonis, McCormick, Vernon, and Ybarra) are system-wide distribution
substations. The remaining five are customer-dedicated substations: Owill, Beejay, Kinetic,
Trigas, and Maisano.
6. Transmission and Distribution
Distribution System
Vernon Public Utilities 2023 IRP 6-4
Large industrial and commercial loads create abnormal challenges for operating and protecting
VPU’s electric system. The small geographical service area and dense loading results in shorter
than average distribution circuits with multiple circuits on the same pole.
Distributed Generation Evaluation and Recommendations
In 2015, VPU completed a comprehensive Distributed Generation Impact Study to address the
impacts of environmental, physical, and efficiency aspects of its distribution system through
the addition of increasing amounts of solar PV DERs. The study assessed the impact of
interconnecting solar, wind, diesel, and natural gas fueled facilities as well as the current
mandatory requirement of a conditional use permit (CUP) for all distributed generation.
Vernon’s engineering staff currently uses the ETAP system model for distribution load flow,
short circuit, transient flicker, and motor-starting analysis.
The study reviewed current electric rates, evaluated the potential rate impact associated with
integrating increasing amounts of DERs, and outlined the optimal level of DERs without
causing significant impacts by recommending a restructuring of electric rates for long-term
financial security and stability.
Using this study as a starting point, the IRP analyzed the condition of VPU’s existing
interconnection and distribution system to identify safety, reliability, rate impacts, and
operation issues and to determine the capabilities of VPU’s current system. The analysis
assessed the impacts of DERs and reviewed the existing rules and guidelines for the DER
interconnection. This analysis served as a foundation for considering new improvements and
measures to be undertaken to enhance the distribution system.
The results of the Distributed Generation Impact Study indicate that:
▪ The existing distribution system can support up to a full peak load 190 MW of DERs, but
cannot be connected to any of Leonis Substation 7 kV distribution circuits until the feeder
circuit breaker is replaced with a higher interrupting current rating.
▪ DERs of up to 5 percent of peak loads (non-coincident peak load of each class of customers)
can be added, as required by net metering law and AB 327.
▪ Solar PV projects up to 1.0 MW can be exempted from the CUP requirements without
significant environmental impacts. The CUP requirement should be maintained for the
other types of DERs evaluated in the study and solar PV projects above 1.0 MW.
▪ Existing regulations provide adequate safety protection related to hazardous materials that
are associated with solar PV, fuel cells, and fossil-fuel DER projects. Electric safety hazards
can be managed by adopting prudent operating and maintenance procedures,
interconnections agreement requirements, and guidelines and requirements that comply
with DER and industry standards (such as IEEE Std.1547 and UA 1741).
6. Transmission and Distribution
Distribution System
Vernon Public Utilities 2023 IRP 6-5
The study recommended the following:
▪ Permit solar PV DERs of up to 1.0 MW without CUP process and continue CUP process
for all other types of DERs, both renewable and non-renewable. Modify and update CUP
language regarding diesel engines strictly used as back-up and stand-by generators, to clarify
that those are exempt from the CUP.
▪ Replace all 7 kV circuit breakers at the Leonis substation with higher interrupting current
rating to allow for DER connection on 7 kV circuits.
▪ Continue upgrading the VPU distribution infrastructure to maintain system reliability
(accomplished through an approximate $5 million annual capital budget).
▪ Upgrade line conductors, transformers, and other aging infrastructure as part of its Capital
Improvement Plan.
Distribution System Capital Improvement Project
VPU has developed a program to invest in its infrastructure. Over the past decade, this
program has resulted in VPU successfully completing several major capital improvements
projects to its distribution system.
Over the past three years alone, VPU has successfully completed over $25 million in system
enhancements, including replacing over 100 distribution poles and two circuit miles of
underground cable upgrades, converting the voltage in load growth areas, and completely
rebuilding a major substation that is responsible for over one third of the City’s electrical load.
In addition, VPU has recently completed substation upgrade projects on all of its major
substations. Included in these upgrades is a four-year project at Leonis substation, which saw
the replacement of all five transformer banks which had been in service since the 1950s. The
transformers, responsible for over 30 percent the City’s electrical load, were upgraded to add
an additional 100 MW of capacity to the Vernon electric distribution system. The project also
replaced circuit breakers, capacitor banks, and protective relays, essentially creating a new
substation to provide reliable electric service to residential and business customers in the
center, south, and east ends of the City for the next several decades.
Through the program, VPU successfully reduced the frequency and duration of distribution
outages, maintained system reliability, improved safety, system efficiency, and operating
flexibility. As the power system becomes more decentralized, the VPU distribution system
needs to evolve, modernize, and incorporate emerging technology to support higher
penetration levels of DERs.
While not subject to CPUC jurisdiction, VPU follows CPUC General Orders (GO) as a best
practice. VPU performs inspections that adhere to with GO 165 and GO 174. Accordingly,
VPU replaces deteriorating equipment that is identified as deficient under GO standards
6. Transmission and Distribution
Distribution System
Vernon Public Utilities 2023 IRP 6-6
including wood power poles, oil-filled substation circuit breakers, aging underground
substation getaway cables, and numerous electromechanical relays with solid state relays. VPU
has also performed voltage conversion on limited segments of its distribution system, installed
a comprehensive geographic information system (GIS), and performed many additional
upgrades and replacements of capital infrastructure.
Vernon has assessed its distribution system to ascertain the condition of the existing system.
The study has identified a number of distribution improvements that are needed to maintain
system reliability, improve safety, system efficiency, and operating flexibility.
For the past three years, from 2020 through 2023, VPU has been working on a distribution
Capital Improvement Plan (CIP) focused on strengthening infrastructure to better prevent
outages, grid resiliency to sustain robust reliability, and maintain high service quality.
The result is VPU’s Five-Year CIP. The plan focuses on infrastructure upgrades to help
achieve a strategic vision that addresses its five-square-mile service territory and unique
industrial characteristics that make up the City. The plan defined strategies that involved
in-depth evaluation of the condition of the electric system; performed detailed engineering
analysis of distribution system capability and performance; and listed construction and
upgrade projects to help transform the system into an intelligent, increasingly automated, and
technologically advanced electric system.
The CIP addresses the key areas and construction required for replacements or upgrades. The
success of this project will be measured in the improved electric system reliability provided to
the City of Vernon residential and business customers and, in turn, the benefits provided to the
surrounding communities. The plan also aims reduce the carbon footprint of VPU by
removing greenhouse gas emissions from the system. The plan includes replacing switches and
circuit breakers that use sulfur hexafluoride (SF6) for insulation and leverages new technologies
for replacing and upgrading these units. The plan’s goal is to increase system reliability for the
local electric grid and environmental improvements for a sustainable future for the community.
Specific projects include replacing five aging substation transformers and upgrading to an
additional 100 MW each of capacity; performing $5 million worth of reliability investment by
upgrading 7 kV circuits to 16 kV; and replacing over 100 deteriorated wooden poles, 10,000
feet of underground primary cable, and all high-pressure sodium streetlight fixtures with new
more efficient LED lights.
Actions that are part of the CIP include the following:
▪ Continue to replace and upgrade Vernon distribution aging infrastructure to maintain
system reliability.
▪ Implement new distribution system automation by installing intelligent line switches and
automatic reclosers for improvement of VPU’s smart grid.
6. Transmission and Distribution
Distribution System
Vernon Public Utilities 2023 IRP 6-7
▪ Upgrade line conductors, transformers, and complete voltage conversions at electric
substations.
▪ Perform system undergrounding in conjunction with development projects and City
projects for improved system reliability.
These efforts provide VPU the opportunity to engage various commercial and industrial
customers who are interested in increasing their existing capacity to meet expanding demand,
electrify their fleet, and install EV charging infrastructure.
The Plan focuses on three target areas for improvement of the electric distribution system:
▪ Deteriorated wood pole replacements
▪ Reconductoring
▪ Sulfur hexafluoride (SF6) gas removal
The purpose of each of the areas of improvement is outage prevention, hardening against
natural disasters and extreme weather due to climate change, enabling quick recovery of the
grid from disruptions, and decarbonization of the electric system.
The $25 million five-year CIP is summarized into three main distribution categories as
outlined in Table 20.
Five-Year Capital Improvement Plan Budget ($ Thousands)
Project 2024 2025 2026 2027 2028 Total
Deteriorated Wood Pole Replacement $3,000 $3,000 $3,000 $3,000 $3,000 $15,000
Reconductoring $500 $2,550 $350 $500 $600 $4,500
Sulfur Hexafluoride (SF6) Gas Removal $500 $900 $1,100 $1,500 $1,500 $5,500
Total $4,000 $6,450 $4,450 $5,000 $5,100 $25,000
Table 20. Five-Year Capital Improvement Plan Budget
VPU will also continue with other capital improvements including the replacement of all SF6
circuit breakers with vacuum circuit breakers, replacement of all underground SF6 distribution
switches with solid dielectric switches, adding new distribution circuit extensions, replacing
substation getaways, and further upgrading substations.
6. Transmission and Distribution
System Reliability
Vernon Public Utilities 2023 IRP 6-8
SYSTEM RELIABILITY
VPU places significant emphasis on operational reliability indices as a cornerstone of its
strategic vision. These indices serve as vital metrics to assess and enhance the resilience and
dependability of VPU’s services. By meticulously tracking and analyzing key reliability
indicators, VPU proactively identifies areas for improvement, allocates resources effectively,
and implements targeted strategies to maintain an unwavering commitment to providing
consistent and uninterrupted power supply to its valued customers. This dedicated focus on
reliability indices underscores VPU’s dedication to delivering excellence in service while
ensuring the utmost satisfaction and trust among its stakeholders.
Three Reliability Indicators
VPU tracks three reliability indicators that the electric utility industry uses to assess and
improve the performance of power distribution systems.
▪ System Average Interruption Frequency Index (SAIFI): Quantifies the frequency of power
outages per customer within a year.
▪ System Average Interruption Duration Index (SAIDI): Measures the duration of power
outages experienced by the average customer over a year.
▪ Customer Average Interruption Duration Index (CAIDI): Provides the average time it takes
to restore power after an outage, calculated by dividing SAIDI by SAIFI.
These indices collectively play
a pivotal role in guiding VPU’s
efforts to enhance service
quality, minimize downtime,
and ensure a resilient and
dependable power supply to
consumers.
VPU utilizes data from the
U.S. Energy Information
Administration (EIA), which
annually calculates a
nationwide electric utility
reliability benchmark. This
Figure 42. SAIFI Outage Frequency Comparison
6. Transmission and Distribution
System Reliability
Vernon Public Utilities 2023 IRP 6-9
benchmark enables VPU to
evaluate and compare its
operational performance
against industry standards and
best practices. This process
involves measuring various
reliability indices, outage data,
and service quality metrics,
and then comparing these
results to those of other
utilities. From these results,
VPU gains valuable insights
into its strengths, weaknesses,
and areas for improvement,
Figure 43. SAIDI Outage Duration Comparison
fostering a culture of
continuous enhancement.
Figure 42 shows that VPU’s
SAIFI outage frequency is
64 percent of all other POUs,
37 percent of statewide IOUs,
and 39 percent of all utilities
nationwide. Figure 43 shows
that VPU’s SAIDI outage
duration is 67 percent of all
other POUs, 23 percent of
statewide IOUs, and 31 percent
of all utilities nationwide.
Figure 44 shows that VPU’s
Figure 44. CAIDI Average Outage Restoration Time Comparison
CAIDI average outage restoration time is approximately the same as all other POUs,
52 percent of statewide IOUs, and 65 percent of all utilities nationwide. (All figures are from
2021.)
6. Transmission and Distribution
System Reliability
Vernon Public Utilities 2023 IRP 6-10
For 2021, VPU was ranked among the top 25 percent of the electric industry in reliability.
Being in the top quartile of the benchmarking is significant for a utility for several reasons:
Customer Satisfaction. Utilities in the top quartile provide more reliable and consistent
service, resulting in higher customer satisfaction. Fewer outages and quicker restoration times
contribute to improved customer experiences and loyalty.
Economic Impact. A reliable utility with minimal service disruptions positively impacts the
local economy. Businesses can operate without interruptions, productivity remains steady, and
economic growth is sustained.
Operational Efficiency. Utilities in the top quartile often exhibit efficient operations and well-
maintained infrastructure, leading to reduced downtime and operational costs.
Regulatory Compliance. Many regulatory authorities set reliability and safety standards that
utilities must adhere to. Achieving top-quartile performance demonstrates compliance to the
standards, avoiding potential penalties and demonstrating a commitment to compliance.
Resilience and Preparedness. Being in the top quartile signifies a utility’s ability to effectively
respond to and recover from unforeseen events such as storms, ensuring minimal disruption to
the lives of its customers.
Stakeholder Confidence. High reliability levels demonstrate a utility’s stability and
competence, attracting stakeholder confidence and potentially leading to better access to
funding for infrastructure improvements and expansion.
Customer Reputation. A utility’s reputation for reliability and top-tier performance can
positively influence public perception, attracting new customers and fostering positive
community relationships.
Environmental Impact. A reliable utility may reduce the need for backup power sources or
emergency generators, leading to lower emissions and a smaller carbon footprint.
In essence, being in the top quartile of electric utility reliability benchmarking signifies a
commitment to excellence, ensuring that a utility consistently delivers dependable service,
promotes customer satisfaction, and contributes positively to the overall well-being of the
community it serves. These are all benefits that VPU enjoys as a result of its exemplary
reliability and service to customers.
6. Transmission and Distribution
System Reliability
Vernon Public Utilities 2023 IRP 6-11
Cause of Outages
Virtually all outages in the City of Vernon are from accidental causes that are beyond VPU’s
control. Figure 45 depicts the various causes of the outages that VPU experienced in 2021.
Contact with metallic balloons are the primary causes of outages (indicated as “foreign object”
in Figure 45). The Other category includes single instances of storm damage, direct strike, and
equipment damage.
Figure 45. Causes of Outages
Vernon Public Utilities 2023 IRP 7-1
7. Resource Portfolio
VPU’s load is served by a combined-cycle (CC) and two simple cycle (SC) natural gas plants,
both locally owned and locally sited, two zero-carbon resource PPAs, a landfill gas
RPS-eligible resource PPA, three solar PV RPS-eligible PPAs, and short-term market power
purchases. In addition, VPU has recently signed two solar PV plus BESS RPS-eligible PPAs,
which are scheduled to come online in the near-future.
RESOURCE PORTFOLIO OVERVIEW
Table 21 summarizes VPU’s current and near-term generation portfolio mix.
Unit Owner
Nameplate
(MW)
VPU Share
(MW)
VPU Energy
(MWh) RPS Status
End/
Retire
Malburg Generating Station VPU 139.0 139.0 426,500 None 2036
H Gonzales Generating Station
Units 1 & 2 VPU 11.5 11.5 383 None —
Palo Verde Nuclear Station SCPPA 3,937.0 11.0 92,427 Zero Carbon 2045
Hoover Dam Hydroelectric WAPA 2,080.0 22.0 18,809 Zero Carbon 2067
Puente Hills Landfill Gas LA Sanitation District 46.0 10.0 37,863 RPS Eligible 2030
Astoria II Solar PV Recurrent Energy 100.0 30.0 92,900 RPS Eligible 2036
Antelope DSR 1 Solar PV sPower 50.0 25.0 64,113 RPS Eligible 2036
Desert Harvest REC Solar PV EDF Renewables 70.0 12.0 32,908 RECs 2045
Daggett Solar PV
& BESS*
Clearway Energy
Group
65.0
33.0
60.0
30.0 154662 RPS Eligible 2044
Sapphire Solar PV
& BESS‡ EDF Renewables 117.0
59.0
39.0
19.7 124,007 RPS Eligible 2046
Total Generation
Total BESS — 6,610.5
92.0
354.5
49.7
1,044,572 — —
* Daggett COD: December 20, 2023
‡ Sapphire COD: December 1, 2026
Table 21. Current VPU Owned and Contracted Generation Resources
Energy output is based on calendar year 2022.
7. Resource Portfolio
Resource Portfolio Overview
Vernon Public Utilities 2023 IRP 7-2
The Daggett Solar PV energy is based on a first year PV generation projection of
208,499 MWh minus a round-trip efficiency loss of 15 percent (40,953 MWh) for the BESS.
Since the Sapphire BESS has not received a Large Generator Interconnection Agreement
(LGIA) from CAISO, its energy is based solely on a first year PV generation projection for
VPU’s share without an adjustment for round-trip efficiency.
Figure 46 graphs the current and near-term generation mix. The five light green slices represent
current and near-term renewable generation, the two dark green slices represent zero-carbon
resources, and the two dark gold represent its natural gas resources. By 2030, the renewable
portion of VPU’s portfolio will increase to 60 percent of total generation to comply with the
state’s RPS requirement.
Figure 46. Current and Near-Term Generation Mix
7. Resource Portfolio
Current Resource Portfolio
Vernon Public Utilities 2023 IRP 7-3
CURRENT RESOURCE PORTFOLIO
The VPU portfolio consists of natural gas plants, nuclear, large hydroelectric, landfill gas, and
solar PV facilities.
Natural Gas Resources
Malburg Generating Station
MGS is a 139 MW combined-cycle (CC)
plant located in the City of Vernon. MGS
includes two Siemens (formerly Alstom)
GTXI00 natural gas-fired combustion turbine
generators (CTGs) and a steam turbine
generator (STG). MGS has duct burners and
evaporative inlet air coolers and filters that
enable the units to achieve higher levels of
power output in selected modes of operation.
MGS was originally built by the City of
Vernon, later sold to Bicent Power LLC, then
purchased back from Bicent in late 2021.
Figure 47. Malburg Generating Station
H. Gonzales Generating Station Units 1 & 2
The H. Gonzales Generating Station Unit 1
and Unit 2, located within the City of Vernon,
is a natural gas-fueled facility powered by two
Allison 571-KA combustion turbines (CTs),
each rated at 5.75 MW that operate solely as
peaking units. Both CT units began
commercial operation in 1988. Each unit is
restricted by air quality regulators to run on
natural gas for no more than six hours per day.
Figure 48. H Gonzales CT1 and CT2
7. Resource Portfolio
Current Resource Portfolio
Vernon Public Utilities 2023 IRP 7-4
Zero-Emission Resources
Palo Verde Nuclear Station
The Palo Verde Nuclear Generating Station
(PVNGS)30 is located in Tonopah, Arizona,
approximately 55 miles west of Phoenix. Palo
Verde generates the largest capacity of
electricity in the United States, with the second
largest rated capacity. The Palo Verde plant
consists of three nuclear electric generating
units. Unit 1 is rated at 1,311 MW, Unit 2 at
1,314 MW, and Unit 3 at 1,312 MW.
In 1981, VPU signed a “take or pay” contract
with SCPPA for 11 MW of power from Palo
Figure 49. Palo Verde Nuclear Station
Verde. Under the PPA, VPU must pay for its proportionate share of power generated as well
as operating and maintenance expenses, regardless of the amount of power taken. The PPA
also requires VPU to pay its proportionate share of debt service on any bonds or debt,
regardless of whether the project or any part of the project or its output is suspended, reduced,
or terminated.
Hoover Dam Hydroelectric Power Plant
The Hoover Dam Hydroelectric Power Plant
is located on the Arizona-Nevada border
approximately 25 miles southeast of Las
Vegas. This hydro power plant is part of the
larger Hoover Dam facility, which was
completed in 1935 and controls the flow of
the Colorado River. The Hoover Dam facility
consists of 17 generating units and two service
generating units with a total installed capacity
of 2,080 MW.
In 1987, Vernon entered into a PPA to
purchase 22 MW of firm capacity from the
Figure 50. Hoover Dam Hydroelectric Power Plant
30 Palo Verde is jointly owned by Arizona Public Service (29.1%), Salt River Project (20.2%), El Paso Electric (15.8%), Southern
California Edison (15.8%), PNM Resources (7.5%), Southern California Public Power Authority (5.9%), and Los Angeles
Department of Water and Power (5.7%).
7. Resource Portfolio
Current Resource Portfolio
Vernon Public Utilities 2023 IRP 7-5
Western Area Power Administration (WAPA). SCPPA and other contractor allocations of
Hoover power and energy has been extended for 50 years beyond the PPA’s original
expiration in 2017, which now expires in 2067.
Renewable Energy Resources
Puente Hills Landfill Gas Plant
The Puente Hills Landfill Gas-to-Energy
facility is a 46 MW conventional Rankine
Cycle Steam Power Plant that uses landfill gas
as fuel to generate electricity. Landfill gas is
fired in the plant’s boilers producing
superheated steam. The superheated steam is
used to drive the steam turbine to generate
electric power. The Puente Hills Landfill
Gas-to-Energy facility was constructed by the
Los Angeles County Sanitation District
(LACSD) and began full commercial
Figure 51. Puente Hills Landfill Gas Plant
operation in January 1987; it has remained online 95 percent of the time since then.
On behalf of its members, SCPPA entered into a PPA with LACSD for 43 MW of generating
capacity from the Puente Hills Landfill Gas-to-Energy facility. VPU, through SCPPA, is
entitled to 10 MW of renewable capacity from the facility. The PPA expires on December 31,
2030.
Astoria II Solar Photovoltaic Facility
The Astoria II Solar PV facility is sited on
approximately 840 acres between Los
Angeles and Kern Counties, and
interconnects with the CAISO system at the
SCE Whirlwind Substation.
The City of Vernon, in conjunction with five
other SCPPA municipal utilities, participated
in a PPA with Recurrent Energy to purchase
Figure 52. Astoria II Solar Photovoltaic Facility
the output from the Astoria II Solar facility for 20 years. The PPA entitled Vernon to 20 MW
of capacity from January 2017 to December 2021. Starting in January 2022 and extending
until the PPA’s expiration in December 2036, VPU is entitled to 30 MW of power.
7. Resource Portfolio
Current Resource Portfolio
Vernon Public Utilities 2023 IRP 7-6
Antelope DSR 1 Solar PV Facility
The Antelope DSR 1 Solar PV facility is
located in the City of Lancaster, Los Angeles
County. It was developed by the Sustainable
Power Group (sPower) and came online in
December 2016.
Through SCPPA, VPU owns a PPA with
Antelope DSR 1 LLC (a subsidiary of
sPower) for 25 MW of output, 50 percent of
the facility’s 50 MW capacity, through
December 31, 2036.
Figure 53. Antelope DSR 1 Solar PV Facility
In conjunction with the solar facility, the cities of Riverside and Vernon negotiated an energy
storage option in the PPA, which provides for potential to design, build, and operate an energy
storage facility at the site when economically feasible.
Desert Harvest 2 REC Solar PV Project
On December 17, 2020, SCPPA initiated a
PPA with EDF Renewables for 70 MW of
solar PV capacity from the Desert Harvest 2
Solar PV project. The project is a fixed-tilt PV
system that interconnects at the Marketplace
substation and is located on 1,200 acres of
Bureau of Land Management (BLM) land in
Figure 54. Desert Harvest 2 REC Solar PV Project
Desert Center, California. The REC + Index agreement serves the cities of Anaheim, Burbank,
and Vernon.
VPU is entitled to 17.14 percent of the Project’s output, or about 12 MW. This PPA, which
expires at the end of 2045, provides RECs only.
7. Resource Portfolio
Wholesale Market Power Purchases
Vernon Public Utilities 2023 IRP 7-7
Daggett Solar PV and BESS Project
The Daggett Solar plus BESS project is a
single-axis tracker 65 MW solar with a
33 MW (132 MWh) 4-hour Lithium-Ion
BESS. The COD is December 20, 2023. The
project, located in City of Daggett in San
Bernardino County, is a portion of an
approximately 482 MW solar PV facility. The
project is being developed by Clearway
Energy Group and is owned by Daggett Solar
Power 2 LLC.
Figure 55. Daggett Solar PV and BESS Project
On June 24, 2022, SCPPA executed a PPA for 65 MW for the cities of Vernon and Cerritos.
The PPA entitles VPU to 60 MW of solar PV output and 30 MW of energy storage. The PPA
expires at the end of 2044.
The contract will provide VPU with 60 MW of solar and 30 MW of Storage. City of Cerritos is
entitled to 5 MW of solar and 3 MW of the storage in this project. This contract will expire on
December 31, 2044.
Sapphire Solar and BESS Project
The Sapphire Solar project is a solar PV and BESS facility being developed by EDF
Renewables. Located on 1,140 acres of private land in Riverside County, the project will
generate 117 MW of solar power paired with a 59 MW 4-hour Lithium-Ion BESS with a total
capacity of 236 MWh.
The project will interconnect on an existing Desert Harvest transmission line and deliver to the
CAISO System. The bundled energy products include renewable energy, RECs, RA, and other
energy attributes. The COD is December 31, 2026. VPU has acquired a PPA for 39 MW of
solar output combined with 19.67 MW of BESS. The PPA expires on December 1, 2046.
WHOLESALE MARKET POWER PURCHASES
VPU participates in the CAISO market under a metered subsystem agreement (MSSA). The
agreement allows Vernon to balance its load and resources within its city limits. As CAISO
serves as VPU’s Balancing Authority, VPU bids its resources and load into the CAISO market.
Based on market pricing, CAISO determines the amount of energy supplied by VPU’s
resources into the market. If the local generation cost is above the market price, then CAISO
meets VPU’s load with market resources.
Vernon Public Utilities 2023 IRP 8-1
8. Renewable Energy and RPS
Compliance
As with many other utilities in the state, VPU faces the task of meeting its RPS and
zero-carbon requirements cost effectively while balancing that with its existing resources.
These requirements must be achieved while retaining its award-winning level of reliability and
high customer satisfaction.
Ascend took a broad approach when considering, modeling, and analyzing how VPU would
meet state mandates over the next two decades. In this process, Ascend reviewed the following
for the City: its current RPS compliance status for 2023 through 2045, its current RPS-eligible
and zero-carbon contracts, its planned projects through 2045, and its plans beyond 2023. From
this analysis, Ascend calculated the “net short” position or the difference between VPU’s RPS
requirement and its existing resources and planned PPAs. Using this information, Ascend
modeled three different portfolios to determine the optimum, most cost-effective, mix of
resources that meet the RPS and clean energy goals. In addition, the modeled portfolios had to
maintain reliability and maximize benefits to the City. For these portfolios, Ascend considered
a number of resource options with mature technologies. From this process, one portfolio
emerged as most advantageous.
RENEWABLE GENERATION
VPU already has executed several solar PPAs as well as a couple of storage plus solar
resources to add to its renewable portfolio. Any positions not met with its current renewable
portfolio are covered by short-term REC purchases to comply the RPS requirements.
As California moves toward a carbon-free grid, VPU must consider how to replace MGS. One
focus of this IRP is to consider replacing MGS, if implemented, with renewable and clean
alternatives while maintaining reliable service and competitive and stable rates.
8. Renewable Energy and RPS Compliance
RPS Compliance
Vernon Public Utilities 2023 IRP 8-2
RPS COMPLIANCE
In 2022, VPU received 227,784 MWh of RECs from its contracted renewable resources
(outside of market purchases). Table 22 lists the resources in VPU’s portfolio that generate
RECs used to comply with the SB 1020 RPS targets.
Resource RECs in 2022 (MWh)
Antelope DSR Solar 64,113
Astoria II Solar 92,900
Puente Hills Landfill Gas 37,863
Desert Harvest Solar (RECs only) 32,908
Market Purchases 170,631
Total RECs 398,415
Table 22. REC Generation by Resource in 2022
Most recently, VPU has contracted with two new solar energy plus storage projects: Daggett
Solar PV in 2024 and Sapphire Solar PV in 2026. Both projects include a BESS. This gives
VPU the ability to shift a portion of the solar generation to hours that provide higher value.
Generation from Daggett and Sapphire is expected to add 310,000 MWh per year, pushing
VPU’s RPS position to 46 percent by 2027. SB 100 requires VPU to cover 52 percent of its
retail load (less municipal usage) with renewable energy in 2027. Thus, VPU must procure
additional sources of renewable energy or purchase more short-term RECs to meet the RPS
requirements.
8. Renewable Energy and RPS Compliance
RPS Compliance
Vernon Public Utilities 2023 IRP 8-3
Aside from the RPS targets for renewable energy, VPU must plan to meet SB 100’s
requirements that stipulate the following percentages of its retail sales (less municipal load) of
electricity must be served with renewable energy and zero-carbon resources by specific years:
90 percent by 2035, 95 percent by 2040, and 100 percent by 2045. Zero-carbon resources, such
as large hydroelectric and nuclear generation, are considered clean energy.
Figure 56 shows the RPS position by year for Vernon through 2035. Resources include all
current and recently contracted PPAs, which is mostly from solar PV plus BESS. The blue
hatched area depicts the calculated “net short” that VPU must fill with RPS eligible resources
to meet state requirements.
Figure 56. Market Purchases and Clean Energy Position until 2035
8. Renewable Energy and RPS Compliance
RPS Compliance
Vernon Public Utilities 2023 IRP 8-4
RPS and Clean Energy Portfolio 1
The first portfolio modeled for the IRP includes solar, wind, biomass, and storage resources to
meet RPS requirements. Existing nuclear and large hydro resources count toward zero-carbon
requirements.
Figure 57 depicts how eligible RPS resources modeled are selected for Portfolio 1 to meet the
state mandated RPS requirements over a short-term planning period of 2024 through 2034.
Figure 57. RPS Position for Portfolio 1
Figure 58 depicts how both the eligible RPS and zero-carbon resources modeled in Portfolio 1
meet the clean energy requirements over a long-term planning period of 2035 through 2045.
Figure 58. RPS and Clean Energy Position for Portfolio 1
8. Renewable Energy and RPS Compliance
RPS Compliance
Vernon Public Utilities 2023 IRP 8-5
RPS and Clean Energy Portfolio 2
The second portfolio modeled for the IRP includes solar, wind, biomass, and geothermal
resources to meet RPS requirements. Existing nuclear and large hydro resources count toward
zero-carbon requirements.
Figure 59 depicts how eligible RPS resources modeled in Portfolio 2 would meet the state
mandated RPS requirements over a short-term planning period of 2024 through 2034.
Figure 59. RPS Position for Portfolio 2
Figure 60 depicts how both the eligible RPS and zero-carbon resources modeled in Portfolio 2
meet the clean energy requirements over a long-term planning period of 2035 through 2045.
Figure 60. RPS and Clean Energy Position for Portfolio 2
8. Renewable Energy and RPS Compliance
RPS Compliance
Vernon Public Utilities 2023 IRP 8-6
RPS and Clean Energy Portfolio 3
The third portfolio modeled for the IRP includes the same resources as in the first portfolio:
solar, wind, and biomass resources to meet RPS requirements. As in the second portfolio,
Existing nuclear and large hydro resources count toward zero-carbon requirements.
Figure 61 depicts how eligible RPS resources modeled in Portfolio 3 meet the state mandated
RPS requirements over a short-term planning period of 2024 through 2034.
Figure 61. RPS Position for Portfolio 3
Figure 62 depicts how both the eligible RPS and zero-carbon resources modeled in Portfolio 3
meet the clean energy requirements over a long-term planning period of 2035 through 2045.
Figure 62. RPS and Clean Energy Position for Portfolio 3
8. Renewable Energy and RPS Compliance
Portfolio Compliance
Vernon Public Utilities 2023 IRP 8-7
PORTFOLIO COMPLIANCE
In addition to RPS requirements, there are additional requirements. SB 350 established a
long-term procurement requirement for new generation. All resources must be from one of
three PCCs.
PCC-1 generation must be at least 75 percent of total procured generation. PCC-1 generation
must comply with one of the following stipulations:
▪ Have a first point of interconnection with a California balancing authority.
▪ Have a first point of interconnection with distribution facilities used to serve end users
within a California balancing authority area.
▪ Scheduled from the eligible renewable energy resource into a California balancing authority
without substituting electricity from another source.
▪ Beginning in 2021, at least 65 percent of this 75 percent of new renewable generation must
be from PPAs or in ownership agreements that are at least ten years in duration.
▪ Have an agreement to dynamically transfer electricity to a California balancing authority.31
A maximum of 15 percent of new procurement can come from PCC-2 generation, which is
“firmed and shaped eligible renewable energy resource electricity products providing
incremental electricity and scheduled into a California balancing authority.”32
Finally, a maximum of 10 percent of new procurement can be PCC-3 generation: “eligible
renewable energy resource electricity products, or any fraction of the electricity generated,
including unbundled RECs”33, that does not qualify as a PCC-1 nor PCC-2 resource.
VPU currently purchases RECs to comply the RPS requirements. These requirements can also
be met with PCC-1, PCC-2, and PCC-3 resources.
31 California Legislative Information, SB-350 Clean Energy and Pollution Reduction Act of 2015;
https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=20 1520160SB350
32 Ibid.
33 Ibid.
Vernon Public Utilities 2023 IRP 9-1
9. Market Resource Portfolios
The fundamental purpose of integrated resource planning is to ensure adequate capacity to
generate energy for current and forecasted demand while maintaining reliability and
competitive and stable rates as well as meeting state regulatory requirements.
THE FOUNDATION OF THIS IRP
To address these issues, Ascend considered a series of fundamental market portfolio scenarios
to test various resource mixes, assess their viability, and plan a timeline for this capacity
expansion. These scenarios addressed key market and industry-side trends and conditions,
supply and demand possibilities, and energy price forecasts. The market scenarios addressed
several factors, including peak demand and energy forecasts, GHG emission reductions,
renewable and clean energy integration, energy efficiency measures, energy storage, EV
penetration, and building electrification. The scenarios are based on a wide-ranging set of
assumptions and risk factors that might evolve over the long-term planning period of 2023
through 2045.
As a result of this planning, Ascend modeled three future market-based scenarios to identify a
preferred portfolio of generation resources that meet all VPU goals and state regulatory
requirements. Each portfolio consisted of a different mixture of resource options and other
factors. Ascend ran capacity expansion and production cost models in its analysis software,
PowerSIMM, to assist VPU in planning its resource mix over the entire extent of the long-term
2023–2045 planning period.
Vernon and Ascend worked together on portfolio scenarios that provided realistic
representations of potential future paths for VPU. The portfolios shared a number of input
assumptions, a key assumption being the reduction in MGS capacity in 2030 and its status in
2035.
A key goal of the scenario planning process is to provide City management with a robust
quantitative assessment of how its business planning projections could be affected by key risk
variables. Implementing the selected preferred portfolio will assist the City in identifying
additional detailed analyses needed to further quantify operational and financial requirements
while examining business planning risks and potential outcomes.
9. Market Resource Portfolios
Modeling and Analysis Framework
Vernon Public Utilities 2023 IRP 9-2
MODELING AND ANALYSIS FRAMEWORK
IRP modeling is a multi-step process to create capacity expansion plans and calculate their
associated cost to serve Vernon’s load. These costs include the production cost of VPU’s
generation assets as well as the costs and revenues associated with energy transactions in the
CAISO markets. The objective is to find the optimum balance among cost, resource adequacy,
environmental requirements, and policy objectives.
The process starts by defining the objectives, assumptions, and inputs into the capacity
expansion models. Primary inputs include the physical and financial parameters of VPU’s
current resources, VPU’s load
forecast, the candidate
resource options, price
forecasts (power, natural gas,
and carbon), and model
constraints such as capacity
needs, energy needs, and
resource build limitations.
Figure 63 outlines the optimal
supply portfolio.
Ascend worked with VPU staff
to create a model of its existing
Figure 63. Optimal Supply Portfolio
system. Staff gathered data on VPU’s supply resources and load, including historical data
along with future plans and projections for resource updates and expected changes in customer
load.
Capacity expansion models provide a least-cost set of resources that meet the constraints
defined in the model. Portfolio outputs from the capacity expansion models are analyzed for
resource adequacy. If a portfolio cannot adequately serve load, additional resources are added.
Finally, portfolios are analyzed in a production cost model to determine production costs,
emissions, market interactions, among other outputs.
Once all the input assumptions are defined, the VPU modeling team developed an initial list of
scenarios and sensitivities. Scenarios are core frameworks for possible future portfolios, and
sensitivities are variations on the scenarios to test how changing assumptions affect the
resource selection and production costs.
Scenario development provides an opportunity to consider different future paths. In this case,
the scenarios consider alternative replacement options for MGS. Modeling VPU’s system with
different scenarios gives important feedback on total system costs, reliability, emissions, and
9. Market Resource Portfolios
Input Assumptions and Portfolio Modeling
Vernon Public Utilities 2023 IRP 9-3
resource operations. VPU relied on this resource modeling to chart a path toward a clean,
reliable system with competitive and stable rates.
INPUT ASSUMPTIONS AND PORTFOLIO MODELING
VPU licensed PowerSIMM, developed by Ascend Analytics, for the modeling work in this
analysis. PowerSIMM provides capacity expansion, resource adequacy, and production cost
modeling. The modeling in this IRP relied on stochastic models for capacity expansion and
production cost. The modeling team configured PowerSIMM to capture variability and
uncertainty in load, renewables, and prices while maintaining structural parameters among the
variables.
PowerSIMM simulations combine future expectations for load, markets, and renewables, with
historical data to create realistic future simulations of the power system. Simulations are scaled
to future expectations based on monthly forecasts for renewable generation, load, and prices
including price volatility and daily price shapes. The result is a set of simulations covering a
useful and accurate range of potential future paths.
Automated Resource Selection (ARS) is the capacity expansion module in PowerSIMM. ARS
selects the least-cost resource procurements or retirements that satisfy the model constraints.
The models begin with a dispatch of existing and candidate resources to determine variable
costs, energy generation, carbon emissions, and renewable generation over the long-term
planning period. The modeling employed four constraints.
Planning Reserve Margin. Requires portfolio to meet projected annual peak demand plus a
15 percent PRM. Current discussions are considering increasing the PRM to 17 percent.
Emissions. Disallows new fossil fuel resource additions and reduce reliance on existing natural
gas assets to ensure the resultant portfolio complies with SB 1020 requirements.
RPS Level. Requires adequate renewable generation to ensure the resultant portfolio complies
with the RPS mandates of SB 350, SB 100, and SB 1020.
Energy Generation. Requires VPU to have adequate resources to meet at least 80 percent of
their load which reduces their reliance on market purchases.
Outputs from ARS provide the timing and quantity of resources to procure over the long-term
planning period that satisfies these four constraints at the lowest cost. The model considers full
resource costs including capital costs, fixed costs, and variable costs such as start-up costs, fuel,
and variable operation and maintenance (VOM) costs. Market sales revenue is treated as a
negative cost in the model.
9. Market Resource Portfolios
Input Assumptions and Portfolio Modeling
Vernon Public Utilities 2023 IRP 9-4
Candidate Resources
In addition to VPU’s existing resource portfolio, the IRP considered several candidate
resources to potentially add to a new resource portfolio. These resources included both
renewable generation
(geothermal, solar PV, BESS,
and wind) and clean energy
generation (hydrogen and CCS
(Figure 64).
These resources were included
in the modeling of all three
portfolios. The list of candidate
resources was established to
consider a range of new
resource technology types that
VPU could realistically
Figure 64. Resource Capacity Modeling Elements
procure. The following provides a brief overview of the candidate resources.
Solar. New candidate solar PV resources are assumed to be single-axis tracking with capacity
factors of approximately 32 percent. VPU is expected to have abundant opportunity to contract
for more solar in their portfolio over the next few years.
Wind. As a low risk and mature technology, wind provides carbon free energy that can also be
counted in fulfilling the RPS requirements. VPU currently has no wind in its portfolio, but the
resource is available in Southern California. New candidate wind resources are assumed to
have capacity factors approximately 30 percent.
Storage. BESS storage durations of 4-, 8-, and 10-hour durations were considered. VPU will
have an ideal location for energy storage at the MGS site. The model assumes that space and
transmission capacity is adequate to install a battery in Vernon at the same site where MGS is
currently located. The BESS candidate resource costs are based on lithium-ion chemistry, daily
BESS cycling (up to 365 cycle per year), and capacity augmentation throughout the resource
lifecycle. Battery technology will likely evolve over the next twenty years with iron-air and
flow batteries showing promise for the next generation of energy storage. In future IRPs, VPU
will consider such emerging technologies. For this IRP, however, VPU relied solely on mature
storage technologies that are commercially available.
Geothermal. Geothermal provides reliable clean power around the clock. Generation from
geothermal sourced power is firm and dependable since it does not rely on weather. California
is the national leader in geothermal energy with more than 5 percent of total generation
coming from geothermal resources. Due to high demand for renewable power around the
OV ERV IEW OF RESOURCE CA PA CITY MODELING EL EM EN TS
Can d i d at e Resour c es
(Res our c e Op t ion s f or
Ex p an sio n Por t f olio)
Co n f ig u r e Ex i s t in g
Res ou r c e s
Co n s t r ain t s
Rel iabil it y
(Reserve
Margin)
Solar
St orage
Hydro
Nuclear
Nat ural Gas
Generat ion
So lar
Wind
St orag e
Gr een
Hydrogen CT
Geot herm al Cl ean Energy
Generat ion
Emissions
Target s
RPS
Mandat es
9. Market Resource Portfolios
Input Assumptions and Portfolio Modeling
Vernon Public Utilities 2023 IRP 9-5
clock, geothermal prices have increased lately. VPU will consider geothermal as an option for
future supply acquisitions.
Green Hydrogen CT. Hydrogen can power a simple cycle CT with the fuel piped to the
resource location. The model used a projected price forecast for hydrogen fuel with heat rates
close to a new natural gas CT (10 MMBtu/MWh). A hydrogen powered generator was
modeled within VPU’s territory as a potential replacement for MGS.
Natural Gas CC+CCS. A natural gas combined-cycle unit with carbon capture and
sequestration was included in the model with an assumption that it would replace MGS.
Potential Portfolio Options Procurement Plan
The IRP considered several options to increase VPU’s renewable share to meet its RPS
requirements. Starting in 2027, the portfolios analyzed and modeled by Ascend added wind or
solar to VPU’s resource mix to meet RPS requirements in the near term. The analysis for the
long-term planning considers replacement options for MGS in 2035 to meet the 90 percent
clean energy target. The long-term considerations for MGS are Li-Ion energy storage,
hydrogen generation, and geothermal generation. Replacement resources are sized to provide
the same RA as the capacity lost from MGS.
The IRP modeling process selected a set of options for clean energy, which included wind,
solar, energy storage (4-hour and 8-hour duration), geothermal, hydrogen, and CCS. Wind
and solar provide energy and RECs with low capacity value to meet RA requirements. Energy
storage provides no energy or RECs, but can support variable resources like wind and solar to
provide needed capacity value for RA. Energy storage has over 90 percent capacity value.
Geothermal provides both energy and capacity value at a higher cost compared to wind and
solar. Finally, hydrogen and CCS provide dispatchable capacity to supply clean energy around
the clock at a higher cost than geothermal.
Three potential resource portfolios were modeled for the IRP. The added resources in each
portfolio set VPU on a path to comply with future renewable and clean energy requirements.
The cost assumptions are but one factor when evaluating the portfolios, include the levelized
cost of energy (LCOE), financial assumptions, tax credits, depreciation, and the cost of capital.
9. Market Resource Portfolios
Input Assumptions and Portfolio Modeling
Vernon Public Utilities 2023 IRP 9-6
Table 23 summarizes the average cost of potential RPS-compliant resources, clean energy
resources, and energy storage for the capacity expansion models to consider when selecting the
preferred resource portfolio (for 2025 through 2045). The analysis shows that the lowest cost
resources are southern California solar, Pacific northwest wind, and the 4-hour Li-Ion BESS.
The lowest cost zero-carbon resource is nuclear small modular reactors followed closely by
new geothermal.
Technology Resource Price Units Average Cost
Geothermal California Geothermal (new build) $/MWh $157.00
Hydrogen Hydrogen Combustion Turbine $/kW $2,156.20
CCS Carbon Capture and Sequestration $/kW $3,537.44
Solar Southern California Solar $/MWh $48.66
Northern California Solar $/MWh $54.67
Energy Storage
4-hour Li-Ion BESS $/kW-Month $15.02
8-hour Li-Ion BESS $/kW-Month $25.70
10-hour Flow BESS $/kW-Month $28.93
Wind
Pacific Northwest Wind $/MWh $46.32
New Mexico Wind $/MWh $56.21
Southern California Wind $/MWh $63.95
Northern California Wind $/MWh $68.57
Wyoming Wind $/MWh $70.59
California Offshore Wind $/MWh $114.72
Nuclear Nuclear Small Modular Reactor $/MWh $154.36
Table 23. Average Cost of RPS-Compliant, Clean Energy, and Storage Resource Portfolio Options
9. Market Resource Portfolios
Input Assumptions and Portfolio Modeling
Vernon Public Utilities 2023 IRP 9-7
Resource Cost Estimates
Ascend prepared cost estimates for candidate resources, which were based on multiple sources
of information. One source is the Annual Technology Baseline (ATB) report published by the
National Renewable Energy Laboratory (NREL). It provides projections of resource costs for
various technologies through 2050. Ascend augmented information from the ATB with data
gathered through the
administration of utility
Request for Proposals (RFPs)
to procure new resources
throughout California. If, for
example, Ascend received an
indication that southern
California solar prices are
higher than the projected ATB
values, Ascend adjusted the
projections to attain more
accurate prices for the southern
California region. All price
projections include the effects
Figure 65. Resource Costs: Wind, Solar, Geothermal
expected from the Inflation Reduction Act (IRA) on power purchase agreement costs from
renewable resources.
Figure 65 depicts the forecast
of solar PV and wind costs, in
dollars per MWh, sited in
southern and northern
California together with
geothermal costs. In general,
the cost for geothermal
generation is double that of
wind and solar. That doubling
cost gap is forecast to increase
over time.
Figure 66 depicts the cost
forecast for 4-hour, 8-hour,
Figure 66. Resource Costs: Battery Energy Storage System
9. Market Resource Portfolios
Input Assumptions and Portfolio Modeling
Vernon Public Utilities 2023 IRP 9-8
and 10-hour BESS in dollars
per kW month (the kW
consumed in an average
month). In general, the cost for
4-hour BESS is half that of
8-hour and 10-hour BESS.
Figure 67 depicts the cost
forecast for a hydrogen-fueled
CT and for the implementation
of CCS on the generation unit
in dollars per kW. These cost
forecasts are multiples of that
of other mature generation
technologies.
Figure 67. Resource Costs: Hydrogen with Carbon Capture and
Sequestration
Risk Analysis
The future can only be predicted through research and forecasts. Modeling, based on
numerous assumptions, and its incumbent analysis, comes with risk. Every effort is made to
minimize risk, nonetheless, risk must be considered when devising and implementing any
plan.
Risks inherent in resource planning include:
▪ Higher than expected environmental compliance costs
▪ Higher than expected carbon prices
▪ Higher than expected resource generation costs
▪ Higher than expected transmission and distribution costs
▪ Direct and indirect environmental costs
▪ Transportation costs
Additional risks include increased demand and energy requirements, regulatory energy policy
changes, and financial liquidity risks. Resource planning attempts to mitigate these risks as
much as possible so that resultant actions remain viable for the foreseeable future.
9. Market Resource Portfolios
Analyzing VPU’s Current Resource Portfolio
Vernon Public Utilities 2023 IRP 9-9
ANALYZING VPU’S CURRENT RESOURCE PORTFOLIO
VPU’s resource portfolio consists of a balanced mix of energy generation consisting of natural
gas, nuclear, hydroelectric, landfill gas, and solar. The largest generator, MGS, provides
139 MW of accredited capacity toward VPU’s RA requirement. As a local resource in the city
of Vernon, MGS can be counted on to reliably serve load even in the face of transmission
outages and line congestion. Due to this advantage, VPU plans to continue to run MGS as
long as possible to maintain low-cost, reliable service for the residents of Vernon. By 2030,
however, the GHG emissions emitted by MGS must be reduced in a manner that will satisfy
more stringent emission regulations.
The core scenarios revolve around the status of MGS. Modeling shows that VPU must reduce
MGS emissions by 2030. The most favorable option for accomplishing this emission reduction
is to stop operating one of MGS’s CTs and run the unit less frequently outside the summer
months. Thus, the models assume that, starting in 2030, MGS will operate in a 1x1
configuration (one CT and one ST) with limited dispatch in the off-peak months. Changing to
a 1x1 configuration will likely cut MGS GHG emissions by two-thirds in 2030 compared to
today.
In 2035, the model assumes that MGS will stop generating after 30 years of operation, which
helps VPU meet the renewable and clean energy requirements of SB 32, SB 100, and SB 1020.
In 2035, VPU is expected to meet 90 percent of its load with carbon-free resources.
The GHG Emissions Accounting Table (GEAT) projects annual GHG emissions attributed to
MGS generation, VPU’s only eligible GHG emitting resource, for all modeled portfolio
scenarios. Figure 68 shows VPU’s annual emission for its current 2x1 configuration, then
GHG emissions, first through 2029 with MGS running in its current 2x1 configuration, then
9. Market Resource Portfolios
Analyzing VPU’s Current Resource Portfolio
Vernon Public Utilities 2023 IRP 9-10
through 2035 when
MGS converts to a 1x1
configuration. After
2035, the IRP assumes
MGS stops operating
and is replaced with
zero-carbon energy
that can meet RA
requirements.
Figure 68 demonstrates
that the IRP complies
with the GHG
emission requirements
set forth in SB 32 and
SB 350.
Figure 68. Greenhouse Gas Emissions Accounting Table (GEAT) for All Portfolios
The CO2 emissions limit shown is based on the California carbon allowances provided to
utilities.
When MGS stops operating, VPU’s emissions will drop to nearly zero. This will not only
make VPU a leader among utilities in clean energy procurement, but also reduce local GHG
emissions from the natural gas combustion at MGS.
9. Market Resource Portfolios
Three Portfolio Scenarios
Vernon Public Utilities 2023 IRP 9-11
THREE PORTFOLIO SCENARIOS
For the IRP, in conjunction with VPU staff, Ascend modeled and analyzed three portfolio
scenarios. Figure 69 summarizes these portfolios. The three portfolios contain several
similarities.
Figure 69. Summary of Modeled Portfolio Scenarios
Portfolio 1: Solar, Wind, Storage
A first portfolio, titled Portfolio 1, includes solar PV, wind, and BESS with the following
assumptions:
▪ MGS is kept running at its current 139 MW capacity in a 2x1 configuration until the end of
2029. Beginning in 2030, MGS reverts to 67 MW capacity in a 1x1 configuration. Due to
GHG emission reduction requirements, the model assumes no MGS generation beyond
2035.
▪ Solar PV resources from southern and northern California are chosen to diversify VPU’s
RPS generation portfolio.
▪ The ARS model selects the most cost-effective wind resources from southern California.
▪ The ARS model selects the most cost effective a 4-hour BESS capacity resource based on
costs provided in the new resource cost slide.
9. Market Resource Portfolios
Three Portfolio Scenarios
Vernon Public Utilities 2023 IRP 9-12
Portfolio 2: Geothermal, Solar, Wind, Storage
A second portfolio, titled Portfolio 2, includes geothermal, solar PV, wind, and BESS with the
following assumptions:
▪ MGS is kept running at its current 139 MW capacity in a 2x1 configuration until the end of
2029. Beginning in 2030, MGS reverts to 67 MW capacity in a 1x1 configuration. Due to
GHG emission reduction requirements, the model does not account for MGS generation
beyond 2035.
▪ Up to 70 MW of a geothermal resource is added by January 2035.
▪ Solar PV resources from southern and northern California are chosen to diversify VPU’s
RPS generation portfolio.
▪ The ARS model selects the most cost-effective wind resources from southern California.
▪ The ARS model selects the most cost effective a 4-hour BESS capacity resource based on
costs provided in the new resource cost slide.
Portfolio 3: Green Hydrogen CT, Solar, Wind, Storage
A third portfolio, titled Portfolio 3, includes green hydrogen CTs, solar PV, wind, and BESS
with the following assumptions:
▪ MGS is kept running at its current 139 MW capacity in a 2x1 configuration until the end of
2029. Beginning in 2030, MGS reverts to 67 MW capacity in a 1x1 configuration. Due to
GHG emission reduction requirements, the model does not account for MGS generation
beyond 2035.
▪ In January 2036, two 45 MW CTs burning green hydrogen are installed at MGS to replace
the existing gas-fired CTs.
▪ Solar PV resources from southern and northern California are chosen to diversify VPU’s
RPS generation portfolio.
▪ The ARS model selects the most cost-effective wind resources from southern California.
▪ The ARS model selects the most cost effective a 4-hour BESS capacity resource based on
costs provided in the new resource cost slide.
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-13
CAPACITY EXPANSION RESULTS
Ascend utilized their capacity expansion model to determine the most cost-effective portfolio
that will provide adequacy capacity to replace MGS and serve VPU’s anticipated load growth
over the span of the long-term planning period.
Preferred Portfolio Selection
The production cost model selected Portfolio 1, a combination of wind, solar, and energy
storage. Solar and wind provide renewable diversity to the portfolio, while 4-hour energy
storage provides capacity. Results align with cost projections for future resources: wind, solar
and a 4-hour BESS are the least cost options. (See Figure 65, Figure 66, and Figure 67 for
projected cost comparisons of the various resource options.)
The capacity and
energy balance charts
for Portfolio 1 are
depicted in the
following four figures.
Figure 70 shows the
Capacity Resource
Accounting Table
(CRAT) for Portfolio 1.
It depicts the annual
peak capacity
requirements (in MW)
and contributions of
existing and future
resources to meet
them. The CRAT
Figure 70. Capacity Resource Accounting Table (CRAT): Portfolio 1
depicts MGS transitioning to a 1x1 configuration in 2030 and no natural gas generation in
2035. H. Gonzales 1 and 2 will continue to provide minimal natural gas generation during
peak hours.
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-14
Figure 71 shows the Energy Balance Table (EBT) for Portfolio 1. It depicts the annual energy
needs (in GWh) and
the amount procured
from each resource in
the portfolio. The
capacity expansion
model selects new
energy storage to come
online in 2030 to cover
the capacity drop from
the MGS transition
from a 2x1 operation
to a 1x1 operation and
again in 2035 when
MGS stops operating
in the model.
H. Gonzales 1 and 2
will continue to
Figure 71. Energy Balance Table (EBT): Portfolio 1
provide minimal natural gas generation during peak hours.
Chapter 6 addressed the renewable procurement by portfolio, but it is worth noting that once
MGS stops operating, VPU’s portfolio will essentially be carbon free. The only carbon
emitting resources in VPU’s portfolio after 2035 will be H. Gonzales 1 and 2 which run very
little due to strict operational limits (which is depicted in Figure 72 showing the renewable
energy contribution
and Figure 73 showing
the clean energy
contributions.)
Figure 72 shows the
RPS Procurement
Table (RPT) for
Portfolio 1, which
depicts the renewable
energy contribution of
the portfolio. It depicts
how this portfolio
meets the SB 350 and
SB 100 requirement of
a 60 percent RPS by
2030.
Figure 72. Renewable Procurement Table (RPT): Portfolio 1
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-15
Portfolio 1 fully meets the RPS requirement with contracted resources starting in 2027, after
Sapphire is online. In Portfolio 1, VPU would contract for more solar generation before 2030
to maintain RPS
compliance without
the need to purchase
additional RECs. After
2035, the model selects
additional solar
significantly surpassing
the SB 1020 RPS
minimum.
Figure 73 shows that
this is driven by the
clean energy
requirement in
SB 1020 starting in
2035.
Figure 73. Clean Energy Contribution: Portfolio 1
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-16
Alternative Portfolio 2
The capacity expansion model was utilized to select resources to procure to replace
diminishing capacity from MGS. The second portfolio scenario, Portfolio 2, assumed MGS
would be replaced by a geothermal plant that grew in capacity over the long-term planning
period. Portfolio 2 also included a diverse mix of solar PV, wind and 4-hour energy storage.
Portfolio 2 meets the CAISO RA requirements and provides nearly 100 percent clean energy
after MGS stops operating.
The capacity and
energy for Portfolio 2
are depicted in the
following three figures.
Figure 74 shows the
Capacity Resource
Accounting Table
(CRAT) for
Portfolio 2, depicting
the annual peak
capacity requirements
(in MW) and
contributions of
existing and future
resources. The CRAT
for Portfolio 2 depicts
Figure 74. Capacity Resource Accounting Table (CRAT): Portfolio 2
MGS transitioning to a 1x1 configuration in 2030. H. Gonzales 1 and 2 continue to provide
minimal natural gas generation during peak hours.
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-17
Figure 75 shows the
Energy Balance Table
(EBT) for Portfolio 2.
It depicts the annual
energy needs (in
GWh) and the amount
procured from each
resource in the
portfolio.
Figure 75. Energy Balance Table (EBT): Portfolio 2
Figure 76 shows the
RPS Procurement
Table (RPT) for
Portfolio 2, which
depicts the renewable
energy contribution of
the portfolio. It depicts
how this portfolio
meets the SB 350 and
SB 100 requirement of
a 60 percent RPS by
2030.
Figure 76. Renewable Procurement Table (RPT): Portfolio 2
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-18
Alternative Portfolio 3
The capacity expansion model was utilized to select resources for portfolio 3 to replace the
diminishing capacity from MGS. Portfolio 3 assumed MGS would be retrofitted with two CTs
fueled by green hydrogen. As in the other two portfolios under consideration, Portfolio 3
included a diverse mix of solar PV, wind and 4-hour energy storage. Portfolio 3 meets the
CAISO RA requirements and provides nearly 100 percent clean energy after MGS stops
operating.
The capacity and
energy for Portfolio 3
are depicted in the
following three figures.
Figure 77 shows the
Capacity Resource
Accounting Table
(CRAT) for
Portfolio 3, depicting
the annual peak
capacity requirements
(in MW) and
contributions of
existing and future
resources. The CRAT
for Portfolio 3 depicts
Figure 77. Capacity Resource Accounting Table (CRAT): Portfolio 3
MGS transitioning to a 1x1 configuration in 2030. H. Gonzales 1 and 2 continue to provide
minimal natural gas generation during peak hours.
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-19
Figure 78 shows the
Energy Balance Table
(EBT) for Portfolio 3.
It depicts the annual
energy needs (in
GWh) and the amount
procured from each
resource in the
portfolio.
Figure 78. Energy Balance Table (EBT): Portfolio 3
Figure 79 shows the
RPS Procurement
Table (RPT) for
Portfolio 3, which
depicts the renewable
energy contribution of
the portfolio. It depicts
how this portfolio
meets the SB 350 and
SB 100 requirement of
a 60 percent RPS by
2030.
Figure 79. Renewable Procurement Table (RPT): Portfolio 3
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-20
Modeled Portfolios and RA Requirements
VPU meets the RA requirement through the entire long-term planning period for all portfolios
under consideration. Satisfying the RA requirements will result in reliable service to VPU
customers. The actual capacity values for all resources are determined by CAISO in its annual
study. Therefore, the RA values shown in the CRATs for the three portfolios (Figure 70 on
page 9-13, Figure 74 on page 9-16, and Figure 77 on page 9-18) are based on capacity
accreditation projections from Ascend that may be different than the values experienced over
time.
Geothermal and hydrogen generation are assumed to be much more expensive than 4-hour
storage and solar in the future. As a result, total supply costs for Portfolio 2 and Portfolio 3 are
higher than the total supply cost for Portfolio 1. These costs are a function of the expected
resource costs ten to fifteen years from now, which include a significant amount of uncertainty
and risk.
Capacity Expansion Resource Mix
Figure 80 and Figure 81 compare VPU resource capacity in 2030 to 2045. While the
percentage of solar PV and wind has remained nearly constant between 2030 and 2045, the
percent of thermal generation is minimal while the percent of energy storage has doubled.
Figure 80. 2030 Resource Capacity Mix Figure 81. 2045 Resource Capacity Mix
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-21
Portfolio Cost Comparison
The preferred portfolio identifies the lowest cost resource portfolio. The IRP is based upon
nominal cost estimates and forecasts, which represent current year costs not adjusted for
inflation. Many factors contribute to the overall cost; generation costs represent only one
factor. These overall costs also include bond payments, reserve requirements, electric system
capital improvement costs, operating and maintenance cost, and administrative and general
expenses, among others.
The financial cost of money is also factored into overall costs. These costs include the cost of
capital, financial assumptions, tax credits, depreciation, and the LCOE. While all these costs
directly affect electric rates, they are only an estimate of, and not a direct impact on, their effect
on customer rates.
Figure 82 estimates the
twenty-year net present
value (NPV) cost (per
MWh) of the three
modeled portfolio
scenarios compared
with the current total
portfolio cost.
Figure 82 indicates
that replacing MGS
with wind, solar PV,
and energy storage
through Portfolio 1,
the preferred portfolio,
only result in a modest
Figure 82. Total Net Present Value Cost of Load for Each Portfolio
increase in estimated supply costs. The cost of the geothermal and green hydrogen in the other
two portfolios likely results in much higher costs.
VPU’s near-term action plan will focus on procuring additional RPS sources, most likely from
solar PV but also from wind and energy storage. VPU will continue to monitor the economics
and viability of solar, wind, and energy storage versus geothermal and hydrogen generation to
assess its viability in future IRPs.
9. Market Resource Portfolios
Capacity Expansion Results
Vernon Public Utilities 2023 IRP 9-22
The Preferred Plan and Disadvantaged Communities
The planned reduction in generation from MGS combined with increases in renewable and
zero-carbon generation will contribute to significant reductions in local GHG emissions. This
cleaner air will benefit all businesses, customers, and residents across varying socio-economic
demographics. VPU’s transition to a clean energy resource portfolio will improve the quality of
life in the City of Vernon and its local and neighboring DACs.
Successfully implementing this clean energy transition requires the collaboration of VPU and
its customers.
Vernon Public Utilities 2023 IRP 10-1
10. Action Plans
VPU looks to strengthen reliability, reduce cost, advance environmental stewardship, and
improve the lives of its customers during its transition to clean energy. This IRP outlines the
actions necessary to complete the transition to comply with state and RPS requirements for
renewable generation by 2030 and zero-carbon energy by 2045, while maintaining reliability
and keeping competitive and stable rates. The steps outlined in this action plan identify
investment strategies and the most prudent approach to meet forecasted load.
VPU’s action plan incorporates its commitment to educate its customers on energy efficiency
measures, develop new incentive structures, transition to electric vehicles, and electrify their
buildings.
Some action plan steps are already being implemented, while others are planned for the
immediate future, and still others are planned for the longer term. It is important to note that
this action plan was developed from both known and anticipated information.
Through VPU’s stakeholder outreach efforts, customers have made it clear that reliable service
and affordable rates are paramount. Complementing stakeholder mandates will need to be in
tandem with state requirements for reduced GHG emissions, increased RPS compliant
generation, and a zero-carbon grid.
As the future unfolds, VPU will adjust these action plan steps as necessary when circumstances
that alter the underlying assumptions impact the basis of the 2023 IRP. Ultimately,
implementing this IRP will be based on a sound operating and business principles that
considers technical, regulatory, and financial aspects to best balance reliability, environmental
stewardship, and rates.
10. Action Plans
Initial Steps
Vernon Public Utilities 2023 IRP 10-2
INITIAL STEPS
The preferred portfolio in this plan proposes adding wind and solar starting in 2027, and
energy storage in 2030. This timeline is based on current costs for supply resources, expected
future supply costs, and power market trends. VPU will continue to monitor markets and
technology and adapt as new information emerges. For example, hydrogen generation could
emerge as a cost-effective replacement for MGS. If that occurs, VPU will adjust its current plan
which relies on energy storage to firm new wind and solar.
VPU has already begun adding renewable resources to its portfolio. The first step in VPU’s
action plan is to ensure that Daggett comes online in late 2023 and Sapphire comes online in
2026, as expected. These new resources are an important step in VPU’s carbon reduction
strategy and will keep VPU on track to meet its future RPS requirements.
Beyond Daggett Solar PV and Sapphire Solar PV, VPU must procure additional RPS-eligible
resources. The preferred portfolio selected wind and solar to increase VPU’s RPS position
before the 60% requirements in 2030. To accomplish this, VPU plans to issue a request for
proposal (RFP) in the next year for resources to satisfy the RPS requirements.
Aside from the RPS mandates, VPU needs resources to cover RA requirements in CAISO.
Currently, MGS provides 139 MW of RA accredited capacity (76 percent of VPU’s RA
requirement). Starting in 2030, VPU must adjust its use of MGS to meet carbon emissions
limits. To accomplish this, VPU intends to convert MGS from a 2x1 facility to a 1x1 facility,
thus retiring one combustion turbine but also reducing the RA value of MGS from 139 MW to
67 MW. In addition, the 1x1 facility will run less frequently outside of summer months to
maintain a low number of unit starts.
Converting MGS to a 1x1 facility means VPU must procure replacement RA capacity by
2030. VPU also expects to stop operating MGS by 2035, creating another gap in RA that must
be filled with new resources.
10. Action Plans
Bulk Power System Action Plan
Vernon Public Utilities 2023 IRP 10-3
BULK POWER SYSTEM ACTION PLAN
This action plan’s first priority is to ensure that the Daggett Solar PV and the Sapphire Solar
PV PPAs meet their respective CODs. The action plan’s next step is to replace 72 MW of
MGS generation with renewable resources by 2030 and the remaining 67 MW by 2035 when
MGS is planned to stop operating. During those years, the PPAs for Puente Hills Landfill Gas
(10 MW), Astoria II Solar PV (30 MW), and Antelope DSR 1 Solar PV (25 MW) are
scheduled to expire.
Figure 83 shows the
required capacity
additions of solar PV,
wind, and storage to
the VPU portfolio in
the preferred scenario.
VPU’s preferred
portfolio consists of
adding, in the
aggregate, a
combination of
360 MW of solar PV,
80 MW of wind, and
380 MW of energy
storage over the
Figure 83. New Nameplate Annual Capacity Expansion for Portfolio 1
long-term planning period. VPU will monitor technology improvements and markets prices
with the reduced operation of MGS. VPU plans to be flexible in selecting future resources
based on updated information gathered in the future.
Table 24 lists the capacity amounts to be added to the portfolio in 2035 to meet the state’s RPS
and clean energy requirements. Capacity additions include 110 MW of energy storage,
180 MW of solar PV, and 50 MW of wind.
Capacity Expansion Action Plan (MW)
Resource 2027 2028 2029 2030 2031 2032 2033 2034 2035
Storage 0 0 0 60 10 10 10 20 0
Solar 20 10 0 10 40 0 0 0 100
Wind 40 0 0 10 0 0 0 0 0
Table 24. Capacity Expansion Action Plan until 2035
10. Action Plans
Bulk Power System Action Plan
Vernon Public Utilities 2023 IRP 10-4
Table 25 lists the capacity amounts to be added to the VPU portfolio in 2035 until 2045 to
meet the state’s RPS and clean energy requirements. Capacity additions include 270 MW of
energy storage, 180 MW of solar PV, and 30 MW of wind.
Capacity Expansion Action Plan (MW)
Resource 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Storage 220 0 10 0 0 0 0 10 30 0
Solar 30 50 0 0 0 10 0 0 70 20
Wind 0 10 0 0 10 10 0 0 0 0
Table 25. Capacity Expansion Action Plan from 2035 until 2045
Successfully implementing these actions begins with VPU staff starting the process to procure
utility scale solar, wind and storage.
Utility-Scale Resource Procurement
The preferred plan adds utility-scale wind and solar renewable resources coupled with battery
storage to provide resource adequacy. As a result, VPU plans to issue a renewable resource
RFP to evaluate utility-scale solar and solar plus storage PPAs for delivery between 2025 and
2027. VPU plans to work with SCPPA to identify solar, wind, and storage projects for
potential acquisition.
While VPU monitors potential procurement projects, VPU will also continue to reevaluate
projects in its system via production cost modeling. As part of the evaluation, VPU will follow
developments in CAISO’s RA construct to determine how new resources will provide RA
benefits to VPU customers.
Malburg Generating Station
In conjunction with added renewables and storage, VPU plans to change MGS operation by
2030 to meet carbon emission targets. The current plan is to convert MGS from a 2x1
combined cycle plant to a 1x1 plant. However, VPU will continue to evaluate reduced
generation levels and options to reconfigure MGS to allow for more operational flexibility.
VPU will also continue to evaluate alternative resource options to replace MGS. Given the
2030 target, VPU will work to ensure MGS or an alternative firm generation resource is in
place by 2029 to maintain reliable operations while meeting state renewable targets.
10. Action Plans
Distributed Energy Resources Action Plan
Vernon Public Utilities 2023 IRP 10-5
DISTRIBUTED ENERGY RESOURCES ACTION PLAN
Pursuant to SB 656,34 VPU’s original NEM tariff has been available to eligible customers on a
first-come, first-served basis with the passage of City Resolution 9472. VPU is evaluating the
details of a new NEM tariff that will incorporate wholesale rates based on excess energy
generated by behind-the-meter solar PV systems.
VPU also plans to continue and evaluate the installation of cost-effective solar-PV systems at
city-owned facilities where appropriate.
ENERGY EFFICIENCY ACTION PLAN
The 2020 CMUA Energy Efficiency Potential Forecast currently serves as the blueprint for
VPU’s current and future energy efficiency action plans. The study analyzes VPU’s service
territory to account for the unique characteristics of its customer base, climate zone, economic
conditions, and other relevant factors to develop annual and cumulative savings.
VPU’s 10-year cumulative energy efficiency market potential from 2022 to 2031 (Table 26) is
set at 25,665 MWh, which translates to an average annual savings target of approximately
2,566 MWh.
Year Annual Market Potential
(MWh)
Annual Demand Reduction Potential
(Incremental kW)
2022 5,247 749
2023 5,504 765
2024 5,069 694
2025 4,489 604
2026 2,575 356
2027 876 103
2028 564 40
2029 447 16
2030 445 17
2031 449 18
Table 26. Energy Efficiency Potential Forecast
VPU achieved approximately 3,480 MWh of net annual savings through its energy efficiency
programs in fiscal year 2022, which exceeds the forecasted market potential set by the CMUA
study. Based on a five-year period from fiscal year 2018 through fiscal year 2022, VPU has
34 http://www.leginfo.ca.gov/pub/95-96/bill/sen/sb_0651-0700/sb_656_bill_950804_chaptered.pdf
10. Action Plans
Transportation Electrification Action Plan
Vernon Public Utilities 2023 IRP 10-6
achieved a cumulative net energy savings of 28.13 GWh and is well positioned to continue to
meet or exceed future energy efficiency targets through the implementation of various
customer-facing programs and services.
VPU plans to build upon its longstanding energy efficiency programs and introduce new
offerings to meet the evolving needs of the customer base through the following initiatives:
▪ Educate customers on the benefits of “deep energy retrofits” and identify those
opportunities through VPU’s complimentary on-site energy audit services. The process
requires a shift from focusing on individual technologies in isolation to combining certain
energy efficiency measures to leverage the interactive effects to achieve additional savings.
▪ Increase customer awareness on the energy efficiency opportunities associated with the
implementation of energy-management hardware or software that can be combined with
traditional technologies, such as LED lighting or individual smart devices.
▪ Develop new incentive structures and new customer programs to incorporate building
decarbonization components that better align with the state’s climate goals.
On the city level, VPU will continue to provide incentives and collaborate with other City
departments to implement cost-effective energy efficiency measures throughout municipal
facilities as various equipment reaches its end of useful life.
TRANSPORTATION ELECTRIFICATION ACTION PLAN
VPU’s 2030 forecast has a target of approximately 2,000 EVs in its service territory with a load
impact of an estimated 9 GWh and a peak demand of about 2 MW. As a result, VPU is
actively doing its part to expand EV charging infrastructure to support the future growth of
transportation electrification through the following efforts:
▪ VPU officially opened its first, public EV charging depot in the summer of 2023, with two
additional public DCFC sites currently under development and scheduled to open by late
2024.
▪ VPU is proactively in discussions with numerous commercial and industrial customers to
create incentives for deploying EV charging stations on private property to support fleet and
workplace charging. As part of this effort, VPU plans to welcome the first commercial EV
fleet charging depot in its service territory by the start of 2024. The site is anticipated to host
several Level 3 DCFCs and over 30 Level 2 EV chargers to support an electrified medium-
and heavy-duty fleet.
10. Action Plans
Customer Engagement Action Plan
Vernon Public Utilities 2023 IRP 10-7
As for customer-facing incentive programs that will help accelerate the transition of
transportation electrification, VPU will:
▪ Continue to implement its existing transportation electrification programs that include the
Commercial EV Charger Incentive Program, Commercial Electric Forklift Incentive
Program, and the Residential EV Charger Rebate Program.
▪ Continue to promote the various incentives offered by local air quality, state, and federal
agencies.
▪ Consider creative solutions to be able to support its customers with large scale fleet
electrification efforts. This includes possibly offering pilot incentive programs to help offset
the upfront costs of infrastructure upgrades that must take place before EV charging stations
can be installed.
VPU has continued to collaborate with other City departments to increase the number of EVs
in operation within the municipal fleet. In particular, the City of Vernon currently has nine
EVs in its fleet, with plans for approximately 10 additional EVs. Out of these 10 estimated
EVs, three are scheduled to be delivered in the near future; the remaining seven will be
incorporated gradually as existing ICE vehicles are taken out of operation.
CUSTOMER ENGAGEMENT ACTION PLAN
Action plans for customer engagement include collecting and prioritizing customer feedback
on the IRP, increasing the frequency of customer outreach and educational events, and
offering more utility products and services to customers.
DISTRIBUTION SYSTEM ACTION PLAN
The Five-Year CIP includes actions for continuing to replace and upgrade VPU’s aging
distribution infrastructure to maintain system reliability. While replacing equipment, VPU
plans to upgrade line conductors and transformers to complete voltage conversions at electric
substations where necessary. In addition, VPU will continue positioning part of the VPU
distribution system underground as part of the City’s development projects to enhance system
reliability. Moving the distribution system underground during City development projects
provides a cost-effective method to relocate distribution infrastructure.
Increasing levels of DERs are challenging VPU’s distribution systems. To allow more DER
interconnection, VPU intends to replace all 7 kW circuit breakers at the Leonis substation with
10. Action Plans
Distribution System Action Plan
Vernon Public Utilities 2023 IRP 10-8
higher interrupting current rating. This will allow for DER connection on 7 kV circuits and
allow higher levels of DER resources.
VPU also anticipates implementing new distribution system automation with intelligent line
switches and automatic reclosers to improve VPU’s smart grid. These improvements will allow
VPU’s system to quickly recover from line outages or other problems. VPU will capitalize on
advances in smart grid technology to continue reliable operations for the foreseeable future.
Table 27 details the action items for the distribution system action plan.
Action Item 2024 2025 2026 2027 2028
Atlantic Bridge √
Frontage improvements √
SCADA upgrades √
Data Center Substations √ √ √ √
66 kV line extensions and upgrades for future data centers √ √ √ √
Customer related projects for improved system reliability √ √ √ √ √
Deteriorated wood pole replacements √ √ √ √ √
Reconductoring (includes 7 kV to 16 kV conversion) √ √ √ √ √
SF6 removal; breaker and switch replacements √ √ √ √ √
Dumont 16 kV circuit - Leonis, Alcoa OH √
Yauk 16 kV circuit - OH and UG routes √
Vernon Substation #2 bank removal and reconfiguration √
Ybarra Substation 27 kV indoor vacuum breakers √
Smart Grid automation √ √ √ √
System reliability improvements √ √ √ √
System undergrounding √ √ √ √
Relay replacement project √ √ √ √
Leonis Substation additional 16 kV positions √ √
Vernon Substation #2 bank removal and reconfiguration √
New circuit extensions √ √ √
McCormick Substation upgrade √ √ √
Table 27. Distribution System Action Plan Items
Vernon Public Utilities 2023 IRP 11-1
11. Appendices
The IRP contains several appendices:
A. IRP Guidelines Cross-Reference (page A-1)
B. Glossary and Definitions (page B-1)
C. PowerSIMM Planner (page C-1)
D. Annual Energy Forecast Data (page D-1)
E. Stakeholder Outreach(page E-1)
Vernon Public Utilities 2023 IRP A-1
A. IRP Guidelines Cross-Reference
In August 2022, the CEC published its Publicly Owned Utility Integrated Resource Plan Submission
and Review Guidelines, Revised Third Edition, as draft Commission Guidelines. Chapter Two of
these guidelines dictate the contents of all IRPs submitted to the CEC. This appendix contains
a cross-reference between the numerous sections specified in Chapter Two and the relevant
sections of the VPU 2023 IRP.
Section Requirement VPU 2023 IRP Reference Page
A Planning Horizon Planning Horizon 2-4
B Scenarios and Sensitivity Analysis Three Portfolio Scenarios
Capacity Expansion Results
9-11
9-13
C Standardized Tables No response required.
C1 Capacity Resource Accounting Table (CRAT)
Preferred Portfolio Selection: Figure 70. Capacity Resource
Accounting Table (CRAT): Portfolio 1
Alternative Portfolio 2: Figure 74. Capacity Resource
Accounting Table (CRAT): Portfolio 2
Alternative Portfolio 3: Figure 77. Capacity Resource
Accounting Table (CRAT): Portfolio 3
9-13
9-16
9-18
C2 Energy Balance Table (EBT)
Preferred Portfolio Selection: Figure 71. Energy Balance Table
(EBT): Portfolio 1
Alternative Portfolio 2: Figure 75. Energy Balance Table
(EBT): Portfolio 2
Alternative Portfolio 3: Figure 78. Energy Balance Table
(EBT): Portfolio 3
9-14
9-17
9-19
C3 RPS Procurement Table (RPT)
Preferred Portfolio Selection: Figure 72. Renewable
Procurement Table (RPT): Portfolio 1
Alternative Portfolio 2: Figure 76.Renewable Procurement
Table (RPT): Portfolio 2
Alternative Portfolio 3: Figure 79. Renewable Procurement
Table (RPT): Portfolio 3
9-14
9-17
9-19
C4 GHG Emissions Accounting Table (GEAT)
Analyzing VPU’s Current Resource Portfolio: Figure 68.
Greenhouse Gas Emissions Accounting Table (GEAT) for All
Portfolios
9-10
D Supporting Information No response required. –
D1 Analyses, Studies, Data, Work Papers, or Others Refer to supplemental material. –
D2 Additional Information Refer to supplemental material. –
E Additional Supporting Information No response required. –
E1 Analyses, Studies, Data, Work Papers, or Others Refer to supplemental material. –
E2 Additional Information Refer to supplemental material. –
F Demand Forecast Annual Energy and Demand Forecasts 4-6
A. IRP Guidelines Cross-Reference
Vernon Public Utilities 2023 IRP A-2
Section Requirement VPU 2023 IRP Reference Page
F1.1 Reporting Requirements
Annual Peak Demand Forecast
Annual Energy Forecast
Rooftop Solar PV Installations
Energy Efficiency Impacts
Price Forecasts
Transportation Electrification Impacts
Appendix D. Annual Energy Forecast Data
4-7
4-8
4-9
4-10
4-11
4-13
D-1
F2.2 Demand Forecast Methodology and Assumptions Long-Term Energy Forecast Methodology 4-1
F3.3 Demand Forecast—Other Regions
This requirement does not apply to VPU as it does not forecast
regions outside its jurisdiction because such forecasting is
irrelevant to its IRP.
G Resource Procurement Plan
Input Assumptions and Portfolio Modeling
Capacity Expansion Results
Appendix C. PowerSIMM Planner
9-3
9-13
C-1
G1.1 Diversified Procurement Portfolio Input Assumptions and Portfolio Modeling
Analyzing VPU’s Current Resource Portfolio
9-3
9-9
G2.2 RPS Planning Requirements Chapter 8. Renewable Energy and RPS Compliance 8-1
G2.2a Forecasted RPS Procurement Targets Chapter 8. Renewable Energy and RPS Compliance
Input Assumptions and Portfolio Modeling
8-1
9-3
G2.2b Renewable Procurement
Chapter 8. Renewable Energy and RPS Compliance
Input Assumptions and Portfolio Modeling
Capacity Expansion Results
8-1
9-3
9-13
G2.2c RPS Procurement Plan Chapter 8. Renewable Energy and RPS Compliance
Bulk Power System Action Plan
8-1
10-3
G2.2d Recommended RPS Information Chapter 8. Renewable Energy and RPS Compliance
Bulk Power System Action Plan
8-1
10-3
G2.2e Recommended Zero-Carbon Resource Information Chapter 8. Renewable Energy and RPS Compliance
Bulk Power System Action Plan
8-1
10-3
G3.3 Energy Efficiency, Fuel Substitution, and Demand Response
Resources
Energy Efficiency Targets
Energy Efficiency Programs
Energy Efficiency Program Impacts
Energy Efficiency Potential Forecasts
5-1
5-2
5-4
5-5
G3.3a Recommendations for Energy Efficiency and Demand
Response Analysis
Energy Efficiency Targets
Energy Efficiency Programs
Energy Efficiency Program Impacts
Energy Efficiency Potential Forecasts
Building Electrification Impacts
5-1
5-2
5-4
5-5
3-21
G3.3b Calculating and Reporting Energy Efficiency Impacts Energy Efficiency Impacts
Energy Efficiency Targets
4-10
5-11
G3.3c Calculating and Reporting Demand Response Impacts
Energy Efficiency Program Impacts
Energy Efficiency Potential Forecasts
Energy Efficiency Action Plan
5-4
5-5
10-5
G4.4 Energy Storage Energy Storage Resources 3-11
A. IRP Guidelines Cross-Reference
Vernon Public Utilities 2023 IRP A-3
Section Requirement VPU 2023 IRP Reference Page
G4.4a Recommendations for Energy Storage Analysis
The Foundation of This IRP
Modeling and Analysis Framework
Input Assumptions and Portfolio Modeling
9-1
9-2
9-3
G5.5 Transportation Electrification Analysis Transportation Electrification Analysis
Transportation Electrification Impacts
3-22
4-13
G5.5a Transportation Electrification Rate Design Electric Vehicle Charging Rates 5-10
G5.5b Recommendations for Transportation Electrification Analysis Transportation Electrification 5-8
G5.5c Calculating and Reporting Transportation Electrification
Impacts
Transportation Electrification
Transportation Electrification Action Plan
5-8
10-6
H System and Local Reliability System Reliability 6-8
H1.1 Reliability Criteria Figure 70. Capacity Resource Accounting Table (CRAT):
Portfolio 1 9-13
H2.2 Local Reliability Area Modeling and Analysis Framework 9-2
H3.3 Addressing Net Demand in Peak Hours The Foundation of This IRP
9-1
I Greenhouse Gas Emissions
Analyzing VPU’s Current Resource Portfolio
Figure 68. Greenhouse Gas Emissions Accounting Table
(GEAT) for All Portfolios
9-9
9-10
J Retail Rates Cost of Service and Rate Impacts
Portfolio Cost Comparison
3-33
9-21
K Transmission and Distribution Systems Chapter 6. Transmission and Distribution 6-1
K1.1 Bulk Transmission System Bulk Transmission System 6-1
K2 Distribution System Distribution System
Distribution System Action Plan
6-3
10-7
L Localized Air Pollutants and Disadvantaged Communities Underserved and Disadvantaged Community Initiatives 5-11
L2.1 Reporting Requirements EV Chargers in DACs 5-12
L3.2 Other Recommended Topics Environmental Sustainability
The Preferred Plan and Disadvantaged Communities
5-12
5-22
Table 28. IRP Guidelines Cross-Reference
Vernon Public Utilities 2023 IRP B-1
B. Glossary and Definitions
AAEE
Additional Achievable Energy Efficiency:
Defined by the CEC as incremental savings
from the future market potential identified in
utility potential studies not included in the
baseline demand forecast, but reasonably
expected to occur, including future updates of
building codes, appliance regulations, and new
or expanded investor-owned utility or publicly
owned utility efficiency programs.
AAFS
Additional Achievable Fuel Substitution:
Defined by the CEC as a load modifier to the
baseline demand forecast achieved by
substituting an end-use fuel type with another,
such as changing out gas appliances in
buildings for cleaner more efficient electric end
uses.
AATE
Additional Achievable Transportation
Electrification:
Defined by the CEC as the estimated
incremental transition to electric vehicles over
the baseline transportation electrification
forecasts.
AB
Assembly Bill:
Legislation that originates or is modified by the
entire California State Assembly.
ACC II
Advanced Clean Cars II:
The rule that requires all car sales in California
to be 100 percent zero emission by 2035
ACCC
Aluminum Conductor Composite Core:
High capacity transmission wire capable of
carrying approximately twice the current of
traditional transmission wire.
ACF
Advanced Clean Fleets:
The requirement for medium- and heavy-duty
fleets to purchase an increasing percentage of
zero-emission trucks.
ACT
Advanced Clean Trucks:
The regulation requiring manufacturers to sell
ZEV trucks and school buses.
APPA
American Public Power Association:
National service organization representing the
nation’s more than 2,000 publicly owned
electric utilities.
ARS
Automated Resource Selection:
A component of Ascend’s PowerSIMM
modeling software that chooses resources for a
least-cost portfolio expansion plan.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-2
ATB
Annual Technology Baseline:
A database that provides a publicly available
source of the forward curves for capital costs
and operations and maintenance expenses for
several different power generation
technologies; published by the National
Renewable Energy Laboratory.
BA
Balancing Authority:
The responsible entity that integrates resource
plans ahead of time, balances supply with
demand, and supports interconnection
frequency in real-time.
BES
Bulk Electric System:
All transmission elements operating at 100 kV
or higher and the real power and reactive
power resources connected at 100 kV or
higher. The Western Interconnection is one of
four bulk electric systems in the United States.
BESS
Battery Energy Storage System:
Rechargeable batteries that store energy that
can be discharged when needed. Types include
lithium-ion, lead-acid, and flow batteries, and
flywheels. Common capacities include 4-hour,
8-hour, and 10-hour batteries, designating the
length of time the battery can discharge energy.
BTM
Behind the Meter:
Refers to the amount of generation captured in
customer meters that impacts demand.
CAISO
California Independent System Operator:
A nonprofit independent system operator that
oversees the operation of bulk electric power
system, transmission lines, and electricity
market generated and transmitted by its
participants. CAISO is the largest balancing
authority in California.
CARB
California Air Resources Board:
Responsible for promoting and protecting
public health, welfare, and ecological resources
through the effective and efficient reduction of
air pollutants while recognizing and
considering the effects on California’s
economy.
Carbon-Free Percent
Similar to the RPS calculation, attained by
dividing the total non-carbon emitting
resources (including the non-RPS eligible
resources nuclear and large hydroelectric) by
the total retail sales.
CC
Combined Cycle:
A combination of combustion turbines (CTs)
and one steam turbine (ST). The CT exhaust is
passed through a heat recovery waste heat
boiler which produces steam to drive the ST.
Possible configurations include three CTs
(3x1), two CTs (2x1), and one CT (1x1) paired
with one ST.
CCA
Community Choice Aggregator:
Communities formerly served by the IOUs that
have formed a separate organization to
aggregate the buying power to procure energy.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-3
CCI
California Compliance Instrument:
A permit created and issued by CARB that
allows the holder to legally emit one metric ton
of GHG measured in carbon dioxide
equivalents.
CCS
Carbon Capture and Sequestration:
A process that captures, separates, and treats
CO2 emissions from a power plant, then
transports it for long-term storage so that it
doesn’t enter the atmosphere.
CEC
California Energy Commission:
California’s primary energy policy and energy
planning agency. Responsible for ensuring
publicly owned utilities’ compliance with the
state’s Renewables Portfolio Standard and Title
20 data reporting requirements.
CEDU
California Energy Demand Update:
The biennial update to various statewide
energy-related forecasts, included in the CEC
IEPR.
CF
Capacity Factor:
The percentage a time a resource generates
electricity compared to its maximum
generation output.
CIP
Capital Improvement Plan:
A plan that described the future infrastructure
investments and estimated costs for Vernon
Public Utilities.
CMUA
California Municipal Utilities Association:
An association incorporated in 1933 to
represent the interests of California’s publicly
owned electric utilities before the California
Legislature and other regulatory bodies.
CO2
Carbon Dioxide:
A colorless, odorless gas found in the
atmosphere that is associated with global
warming. It is released into the atmosphere
through the burning of fossil fuels such as coal,
oil, and natural gas.
CO2-e
Carbon Dioxide Equivalent:
The standard measurement that expresses the
impact of different greenhouse gases as an
equivalent of the amount of CO2 that would
create the same amount of warming.
COD
Commercial Operation Date:
The date when a capacity resource begins to
generate power that can be sold.
Coincidence Factor
The peak of a system divided by the sum of
peak demand of its individual components. It
tells how likely the individual components are
peaking at the same time. The highest possible
coincidence factor is 1.00, when all the
individual components are simultaneously
peaking.
COS
Cost of Service:
A study performed by utilities to forecast the
cost to provide services to retail customers.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-4
CP
Compliance Period:
There are six compliance periods for attaining
Renewables Portfolio Standard goals as defined
in Public Utilities Code section 399.30 (c):
Compliance Period 1:
January 1, 2011 to December 31, 2013.
Compliance Period 2:
January 1, 2014 to December 31, 2016.
Compliance Period 3:
January 1, 2017 to December 31, 2020.
Compliance Period 4:
January 1, 2021 to December 31, 2024.
Compliance Period 5:
January 1, 2025 to December 31, 2027.
Compliance Period 6:
January 1, 2028 to December 31, 2030.
CPUC
California Public Utilities Commission:
Regulates California’s investor‐owned electric
utilities, telecommunications, natural gas,
water, and passenger transportation
companies, in addition to household goods
movers and the safety of rail transit.
CRAT
Capacity Resource Accounting Table:
Defined by the CEC as the annual peak
capacity demand in each year and the
contribution of each energy resource (capacity)
in a POU’s portfolio to meet that demand.
CT
Combustion Turbine:
Any of several types of high-speed generators
using principles and designs of jet engines to
produce low cost, high efficiency power; also
commonly referred to as a gas turbine (GT).
CTG
Combustion Turbine Generator:
An electric generator, commonly powered by a
natural gas burning turbine, producing hot
combustion gases that pass directly through the
turbine, spinning the blades of the turbine to
generate electricity.
CUP
Conditional Use Permit:
A zoning exception that allows the permit
holder to use the property in a way that doesn’t
conform with the zoning requirements.
DAC
Disadvantaged Community:
Disadvantaged communities are designated by
CalEPA pursuant to Senate Bill 535 using the
California Communities Environmental
Health Screening Tool; identified by census
tract, they score at or above the 75th percentile.
DCFC
Direct Current Fast Charger:
Fastest available EV chargers, designed to fill a
battery to 80 percent in 20–40 minutes, and
100 percent in 60–90 minutes.
Demand
The rate at which electricity is used at any one
given time (or averaged over any designated
interval of time). Demand differs from energy
use, which reflects the total amount of
electricity consumed over a period of time.
Demand is measured in kilowatts (kW) or
megawatts (MW). Load is considered
synonymous with demand. (See also Load on
page A-8.)
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-5
DER
Distributed Energy Resource:
Any resource (such as solar and wind power,
energy efficiency, demand response, fuel cells,
energy storage, electric vehicles, and building
electrification) on the distribution system that
produces electricity.
DR
Demand Response:
An electricity tariff or program established to
motivate changes in electric use by end-use
customers, designed to induce lower electricity
use typically at times of high market prices or
when grid reliability is jeopardized.
DSM
Demand-Side Management:
The planning, implementing, and monitoring
programs that encourage consumers to manage
their electricity usage patterns to shift or reduce
demand.
EBT
Energy Balance Table:
Defined by the CEC as the annual total energy
demand and annual estimates for energy
supply from various resources.
EDAM
Extended Day Ahead Market:
A voluntary day-ahead electricity market
designed to deliver significant economic,
environmental, and reliability benefits to
balancing areas and utilities throughout the
West.
EE
Energy Efficiency:
Practices or programs designed to reduce the
amount of energy required to provide the same
level and quality of output.
ELCC
Effective Load Carrying Capacity:
The ability to effectively increase the
generating capacity available to a utility
without increasing the utility’s loss of load risk,
quantified as the amount of new load that can
be added to a system after capacity is added by
a generator without increasing the loss of load
probability or expectation.
Energy
The amount of electricity a generation resource
produces, or an end user consumes, in any
given period of time, measured in kWh, MWh,
or GWh. Energy is computed as capacity or
demand multiplied by time (hours). A
one MW power plant running at full output for
one hour produces one megawatt-hour
(1 MWh) of electrical energy.
ERCOT
Electric Reliability Council of Texas:
One of the main North American electricity
interconnections.
ESP
Electric Service Provider:
A non-utility entity that offers electric service
to customers within the service territory of an
electric utility.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-6
EV
Electric Vehicle:
A vehicle that uses one or more electric motors
for propulsion.
EVSE
Electric Vehicle Supply (Service) Equipment:
Equipment that provides electric power to the
vehicle and uses that to recharge the vehicle’s
batteries.
FERC
Federal Energy Regulatory Commission:
An independent regulatory agency within the
Department of Energy that regulates the
transmission and sale of natural gas, regulates
the transmission of oil, regulates the
transmission and wholesale sale of electricity,
as well as many other energy-related
commercial activities.
GEAT
GHG Emissions Accounting Table:
Defined by the CEC as the annual GHG
emissions associated with each resource in a
POU’s portfolio to demonstrate compliance
with the GHG emissions reduction targets
established by the CARB.
GHG
Greenhouse Gas:
A gas that contributes to the greenhouse effect
by absorbing infrared radiation, including
carbon dioxide, methane, and fluorocarbons.
GIS
Geographic Information System:
A system consisting of integrated computer
hardware and software that stores, manages,
analyzes, edits, outputs, and visualizes
geographic data.
GMC
Grid Management Charge:
A tariff that reimburses CAISO for the cost of
operating its electric power grid.
GO
General Order:
Rules established by CPUC for operations
within its areas of authority.
GW
Gigawatt:
A unit of power, capacity, or demand equal to
one billion watts, one million kilowatts, or one
thousand megawatts.
GWh
Gigawatt-Hour:
A unit of electric energy equal to one billion
watt-hours, one million kilowatt-hours, or one
thousand megawatt-hours.
Heavy-Duty Vehicle
A vehicle with a gross weight greater than five
tons, including the vehicle, fuel, occupants,
and cargo (such as large transit buses, common
tractor-trailer trucks, and refuse trucks).
IEPR
Integrated Energy Policy Report:
A report adopted by the California Energy
Commission and transmitted to the Governor
and Legislature every two years. It includes
trends and issues concerning electricity and
natural gas, transportation, energy efficiency,
renewables, and public interest energy
research.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-7
IOU
Investor-Owned Utility:
A for-profit utility owned by either public or
private shareholders that serve 72 percent of
United States electricity customers.
IRA
Inflation Reduction Act of 2022:
Offers funding, programs, and incentives to
accelerate the transition to a clean energy
economy, among many other provisions.
IRP
Integrated Resource Plan:
A long‐term comprehensive plan that balances
the mix of demand and supply resources over a
long‐term planning horizon to meet specified
policy goals.
ISO
Independent System Operator:
An agency created to operate, control, and
ensure the integrity of the integrated
transmission grid independent of any
generation, wholesale, or retail market.
kW
Kilowatt:
A unit of power, capacity, or demand equal to
one thousand watts. The demand of an
individual electric customer or the capacity of a
distributed generator is often expressed in
kilowatts.
kWh
Kilowatt-hour:
A unit of electric energy equal to one thousand
watt-hours. The standard billing unit for
electric energy sold to retail consumers is the
kilowatt-hour.
L1
Level 1:
A private, residential EV battery charger,
taking approximately 24 hours to fully charge
an empty battery.
L2
Level 2:
A public EV battery charger designed to fully
charge an empty battery in eight hours or less.
L3
Level 3:
A public EV battery charger (also known as a
DCFC), the fastest EV charger available, uses a
480-volt direct current capable of producing a
100-mile charge per hour.
LADPW
Los Angeles Department of Power and Water:
A publicly owned utility that supplies electric
and water to residents and businesses in Los
Angeles and surrounding communities.
LCFS Credit
Low Carbon Fuel Standard credit:
A CARB program that aims to reduce
emissions in the transportation sector by
providing incentives to install EV charging
equipment.
LCOE
Levelized Cost of Energy:
The price per kilowatt-hour for an energy
project to break even; it does not include risk or
return on investment.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-8
LCR
Local Capacity Requirement:
The minimum resource capacity required by
CAISO in each local area to meet established
reliability criteria. CAISO performs annual
studies to identify the local capacity
requirement for the following calendar year.
Light-Duty Vehicle
A vehicle with a gross weight less than five
tons including the vehicle, fuel, occupants, and
cargo (such as passenger cars and light- and
medium-sized pickup trucks).
Load
The moment-to-moment measurement of
power that an end-use device or an end-use
customer consumes. The total of this
consumption plus planning margins and
operating reserves is the entire system load.
Load is often used synonymously with
demand. (See also Demand on page A-4.)
LSE
Load-Serving Entity:
An energy-related company that serves end
users and has been granted authority by
California to sell electric energy to the same.
Medium-Duty Vehicle
A vehicle with a gross weight greater than five
tons, including the vehicle, fuel, occupants,
and cargo (such as moving trucks, large step
vans, and some heavy-duty pickups).
MGS
Malburg Generating Station:
VPU’s largest local natural gas fired
combined-cycle generator.
MMBtu
One Million British Thermal Units:
One million of the units of energy equal to
about 1,055 joules that describes the energy
content of fuels.
MMT
Million Metric Tons:
A weight measurement used to determine the
quantity of greenhouse gases emitted into the
atmosphere.
MSS
Meter Subsystem:
A geographically contiguous single zone that
has been acting as an electric utility before the
formation of the CAISO.
MSSA
Metered Subsystem Agreement:
The terms and conditions under which VPU
operates its generating units, submits bids, and
self-schedules into the CAISO BA and
markets.
MT
Metric Tons:
A weight measurement used to determine the
quantity of greenhouse gases emitted into the
atmosphere.
MW
Megawatt:
A unit of power, capacity, or demand equal to
one million watts or one thousand kilowatts.
Generating capacities of power plants and
system demand are typically expressed in
megawatts.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-9
MWh
Megawatt-Hour:
A unit of electric energy equal to one million
watt-hours or one thousand kilowatt-hours,
used to specify the amount of energy
consumed by customers over time.
N-1 Contingency
The unexpected loss of a single system
component (such as a generator, transmission
line, circuit breaker, switch, or other electrical
element).
N-1-1 Contingency
An initial unexpected loss of a single system
component (such as a generator, transmission
line, circuit breaker, switch, or other electrical
element), followed by system adjustments,
followed by the loss of another single system
component.
N-2 Contingency
The unexpected simultaneous loss of two
major system components (such as a generator
or a transmission line).
NEM
Net Energy Metering:
A billing arrangement that credits a customer
with an eligible renewable distributed generator
(mostly for solar photovoltaic rooftop systems)
for electricity added to the grid. The customer
only pays for the net amount of electricity
taken from the grid.
NERC
North American Electric Reliability
Corporation:
An international not-for-profit regulatory
authority with a statutory responsibility to
ensure the reliability and security of the North
American electric grid by regulating bulk
power system users, owners, and operators
through the adoption and enforcement of
standards for fair, ethical, and efficient
practices.
Net Load
The remaining load after non-dispatchable
resources (such as renewable energy) have been
accounted for.
NOx
Nitrogen Oxide:
A pollutant and strong greenhouse gas emitted
by combusting fuels.
NPV
Net Present Value:
The difference between the present value of all
future benefits, less the present value of all
future costs.
NQC
Net Qualifying Capacity:
The capacity that is available to meet the peak
demand per CAISO.
NREL
National Renewable Energy Laboratory:
The Federal laboratory dedicated to
researching, developing, commercializing, and
using renewable energy and energy efficiency
technologies relied on by utilities across the
country for integrated resource planning.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-10
O&M
Operations and Maintenance:
The recurring costs of operating, supporting,
and maintaining authorized programs,
including costs for labor, fuel, materials,
supplies, and other current expenses.
OTC
Once-Through Cooling:
The process of pulling in water from a body of
water to run through a cooling loop in a
generator and discharging it back to the source.
OTEC
Ocean Thermal Energy Conversion:
A process that produces electricity by using the
temperature difference between deep cold
ocean water and warm tropical surface waters.
PCC
Portfolio Content Category:
A category of electricity products procured
from an eligible renewable energy resource (as
specified by the CEC) for meeting RPS
requirements.
PCC-0: A renewable resource that meets the
criteria of PCC-1 but was signed or went online
before June 1, 2010.
PCC-1: A renewable resource located within
the state of California or, a renewable resource
that is directly delivered to California without
energy substitution from another resource.
PCC-2: A renewable resource that is out-of-
state and delivering to California, where the
RECs are paired with a substitute energy
resource imported into the state.
PCC-3: A tradable or unbundled REC from a
resource, delivered without the energy
component.
PCL
Power Content Label:
Regulatory reporting requirements to the CEC
regarding percentages of energy sources sold by
resource type.
PEV
Plug-in Electric Vehicle:
A vehicle that operates using a battery
recharged by plugging into an external source
of electric power.
PG&E
Pacific Gas & Electric:
An investor-owned utility that provides natural
gas and electric services to northern and central
California.
PHES
Pumped Hydroelectric Energy Storage:
Uses off-peak electricity to pump water from a
lower reservoir into one at a higher elevation
storing potential energy to be released to pass
through hydraulic turbines to generate
electricity. A modern pumped-storage facility
can provide a number of ancillary services,
such as frequency regulation, voltage support
(dynamic reactive power), spinning and non-
spinning reserve, load following, and black
start as well as energy services such as peak
shaving and energy arbitrage.
PHEV
Plug-In Hybrid Electric Vehicle:
A vehicle that operates using a battery
recharged by plugging it into an external source
of electric power or by using an on-board gas
engine.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-11
POU
Publicly-Owned Utility:
Not-for-profit utilities owned by customers and
subject to local public control and regulation.
PPA
Power Purchase Agreement:
A contract to purchase energy and or capacity
from a commercial source at a predetermined
price or on pre-determined pricing formulas.
PRM
Planning Reserve Margin:
A percent of total capacity above projected
annual peak load to meet expected demand
and maintain adequacy of supply.
PSD
Power Source Disclosure:
Regulatory reporting requirements to the CEC
regarding products and energy sources.
PTO
Participating Transmission Owner:
A utility eligible to receive generation through
the CAISO transmission network.
PUC
Public Utilities Code:
A directive issues by the CPUC.
PV
Photovoltaic:
The technology that converts light into
electricity using semiconducting materials that
exhibit the photovoltaic effect by absorbing
photons and then emitting electrons.
PVNGS
Palo Verde Nuclear Generating Station:
Nuclear power plant in Arizona that provides
11 MW of power to VPU’s portfolio mix.
RA
Resource Adequacy:
The CAISO requirements that ensures
sufficient capacity exists for grid‐wide
reliability, including system, local, and flexible
capacity requirements.
REC
Renewable Energy Credit:
Tradable commodities that represent proof that
1 MWh of electricity was generated from an
eligible renewable source.
RFP
Request for Proposal:
A competitive solicitation for suppliers to
submit a proposal on a specific commodity or
service, often through a bidding process.
RP3
Reliable Public Power Provider:
A designation that lasts three years and
recognizes utilities that demonstrate high
proficiency in reliability, safety, work force
development, and system improvement.
RPS
Renewable Portfolio Standard:
The program that, by law, requires all
California-sanctioned electric utilities to
increase the production and procurement of
energy from renewable energy resources.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-12
RPT
RPS Procurement Table:
Defined by the CEC as a detailed summary of
a POU’s resource plan to meet the RPS
requirements.
RTO
Regional Transmission Organization:
An independent, member-based, nonprofit
organization that coordinates, controls, and
monitors the electric grid over multiple states
while promoting economic efficiency,
reliability, and non-discriminatory practices.
An RTO is essentially similar to an ISO, albeit
with greater responsibility for the transmission
network.
SAIDI
System Average Interruption Duration Index:
Electric reliability indicator that measures how
long the average customer is interrupted.
SAIFI
System Average Interruption Frequency Index:
Electric reliability indicator that measures the
average number of interruptions that a utility
customer experience.
SB
Senate Bill:
Legislation that is either proposed or modified
in the California State Senate.
SCAQMD
South Coast Air Quality Management District:
A control agency responsible for regulating
sources of air pollution covering Orange
County and the urban portions of Los Angeles,
Riverside, and San Bernardino County.
SCE
Southern California Edison:
The largest investor-owned electric utilities
serving Central and Southern California.
SCPPA
Southern California Public Power Authority:
A joint powers agency comprised of eleven
publicly owned utilities and one irrigation
district located in Southern California.
SF6
Sulfur Hexafluoride (also SF 6):
A synthetic fluorinated compound with an
extremely stable molecular structure that
utilities rely on for voltage electrical insulation,
current interruption, and arc quenching in the
transmission and distribution of electricity.
SIP
State Implementation Plan:
A CARB document that governs the
implementation of building electrification
initiatives.
SMR
Small Modular Reactor:
Advanced nuclear fission reactors capable of
generating up to 300 MW that can be built in
one location, then shipped, commissioned, and
operated at a separate site.
Spinning Reserves
Available generating capacity that is
synchronously connected to the electric grid
and capable of automatically responding to
frequency deviations on the system.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-13
SPP
Southwest Power Pool:
An RTO that ensures reliable supplies of
power, adequate transmission infrastructure,
and competitive wholesale electricity prices for
the central United States electric grid
ST
Steam Turbine:
A turbine that extracts thermal energy from
pressurized steam and uses it to rotate an
output shaft.
STG
Steam Turbine Generator:
A generator attached to a steam turbine that
generates power when activated.
Substation
Electric system equipment that contains
switches, transformers, and other equipment
that steps down voltages for customer use,
monitors transmission and distribution circuits,
and performs other service functions.
TAC
Transmission Access Charge:
The cost recovery mechanism issued by the
CAISO to recover transmission system
investments.
TCA
Transmission Control Agreement:
A set of rules agreed to by a utility that govern
its participation in the CAISO transmission
network.
TOU
Time-of-Use:
A rate structure for on-peak, off-peak, and
mid-day times designed to encourage
customers to shift energy use to lower rate
periods.
VOM
Variable Operation & Maintenance:
A function of the hours of operation of a power
plant, and include yearly maintenance and
overhaul, repairs, consumables, water supply,
and environmental costs.
WAPA
Western Area Power Administration:
One of four power marketing administration, it
markets wholesale hydropower generated at 57
hydroelectric federal dams operated by the
Bureau of Reclamation, United States Army
Corps of Engineers, and the International
Boundary and Water Commission.
WECC
Western Electric Coordination Council:
Ensures bulk electric system reliability for the
entire Western Interconnection.
WEIM
Western Energy Imbalance Market:
An energy market that automatically finds
low-cost energy to serve demand close to the
time the electricity is consumed, improving the
balance of supply and demand.
WEIS
Western Energy Imbalance Service:
A market that will balance actual generation
with demand and in real-time for participants
in the Western Interconnection when fully
implemented.
B. Glossary and Definitions
Vernon Public Utilities 2023 IRP B-14
WPP
Western Power Pool:
A group of ISOs and utilities dedicated to
ensuring adequate supply and reliability
throughout the Western Interconnection.
WRAP
Western Resource Adequacy Program:
A program that better addresses resource
adequacy needs supplied through variable
renewable generation by taking advantage of
operating efficiencies, diversity, and sharing
pooled resources.
ZEV
Zero-Emission Vehicle:
A vehicle that emits no exhaust gas from its
source of power, such as plug‐in electric
vehicles and hydrogen electric vehicles.
Vernon Public Utilities 2023 IRP C-1
C. PowerSIMM Planner
POWERSIMM OVERVIEW
PowerSIMM is a software program used for simulating the performance of an electric power
system with high spatial and temporal granularity. This section provides an overview of the
key features and capabilities of this simulation software. In the IRP analysis, PowerSIMM was
used for the following applications:
▪ Production Cost Modeling: Simulates power system operations, inclusive of transmission
constraints, on an hourly or sub-hourly timestep for use in decision making for portfolio
management or resource planning.
▪ Capacity Expansion Optimization: Provides a roadmap of future resource procurements
to meet policy or reliability needs at the lowest cost.
▪ Resource Adequacy Analysis: Determines how well a portfolio of resources can serve
customer load over a defined period of time on an hourly basis.
All applications start with simulations of weather, load, renewables, forced outages, and
market prices. The only exception is in resource adequacy models where prices are not used.
Simulations in PowerSIMM
PowerSIMM simulations start with weather as the fundamental driver of load, renewable
generation, and market prices. Weather simulations consist of daily maximum and minimum
temperatures. PowerSIMM uses historical temperatures to construct future simulations of
weather with a time-series model that includes seasonal inputs.
Renewable items require hourly historical generation data coupled with weather data from a
nearby station to determine the structural relationship between daily min and max
temperatures and renewable generation. PowerSIMM constructs a model for each renewable
item using inputs that include daily min and max temperatures, month, and hour. Future
simulations are generated with the model using weather simulations as an input. Generation
output is scaled to meet future expectations for monthly energy generation and capacity limits.
C. PowerSIMM Planner
PowerSIMM Overview
Vernon Public Utilities 2023 IRP C-2
For load, PowerSIMM creates a structural model using hourly load data, daily min and max
temperatures, hour, day of the week, and month. Load simulations are based on weather
simulations and scaled to match load forecasts for monthly energy and peak demand.
The simulation of market prices follows a similar construct, but there are more structural
variables observed in both historic and forecast values. There are also more parameters used as
inputs. For market price simulations, PowerSIMM adheres to market expectations (that is,
forward prices and option quotes for volatility in prices) by scaling simulations such that the
average price exactly meets the forward curves for monthly average prices for natural gas,
on-peak power, off-peak power, and carbon. The stochastic price ranges hold to future
expectations of price volatility, correlations across time and commodities, and daily price
shapes.
Additional details on the model simulations can be found in “Simulation Details” (page B-7).
Dispatch in PowerSIMM
Simulations of weather, load, renewables, and spot prices roll into the dispatch module.
PowerSIMM models dispatch by optimizing supply resource options in a “dispatch to load” or
“dispatch to price” model. In a dispatch to load model, PowerSIMM calculates dispatch
decisions to serve load at the least cost, while accounting for transmission system congestion.
Market purchases are generally, but not always, included as an option for serving load. The
dispatch to price model calculates dispatch decisions to maximize market revenue from
generation.
Dispatch calculations rely on inputs to define the physical and economic characteristics of
supply resources, including thermal resources, energy storage, hydro resources, or demand-side
options. Users can also define transmission lines to represent constraints, such as import or
export limits, or line losses. Ancillary services can be included in dispatch models where
PowerSIMM will co-optimize supply resources to serve load and fulfill ancillary requirements.
PowerSIMM ancillary product dispatch can include regulation up, regulation down, spinning
reserves, and non-spinning reserves. PowerSIMM can also perform multiphase dispatch.
PowerSIMM uses a mix-integer linear programming algorithm in the dispatch calculations.
The objective function in the algorithm is the minimization of cost to supply energy and
ancillary requirements. Included in the total cost are startup costs, variable operations and
maintenance (VOM) costs, fixed O&M costs, fuel costs and fuel delivery costs, electric power
purchases and power sales. Power sales are treated as negative costs.
C. PowerSIMM Planner
Resource Planning Modeling
Vernon Public Utilities 2023 IRP C-3
The decision variables for the dispatch algorithm include the online state of dispatchable
generators, the generation setting for all dispatchable generators, the assignment of ancillary
services for units capable of providing ancillary services, the charge or discharge state of energy
storage resources, and the amount of market purchases. PowerSIMM iterates over a range of
possible values to settle on the decision variables that provide the lowest possible cost within
the model constraints.
Dispatch constraints are set for all units in the model such as economic max generation,
economic min generation, ramp rates, must run requirements, minimum generation, etc.
There are also constraints attributable to transmission limits and the requirement to meet load.
Variable generation from wind, solar and geothermal items are not considered dispatchable,
but PowerSIMM may elect to curtail variable resources if system conditions require it. For
example, wind generation may be curtailed due to transmission limits.
RESOURCE PLANNING MODELING
PowerSIMM was used to run a variety of models for this resource plan. This section describes
the types of models used for the plan.
Production Cost Modeling
The most common application of PowerSIMM in resource planning is as a production cost
model, which shows many detailed aspects of system operations over a future time period.
Production cost models can run with dispatch modeled across a range of simulated future
conditions.
Outputs from production cost models include generation costs, fuel consumption, renewable
generation, carbon emissions, and a long list of additional variables used to make investment
and operational decisions. Example uses for PowerSIMM include analyzing options to hedge
fuel price risk, evaluating new generation resource options, or conducting a study to determine
renewable additions for RPS mandates.
Production cost model outputs allow users to understand how the system will operate with the
assumed inputs. Figure 84 shows hourly dispatch outputs over a three-day period from a
production cost model plotted against load. Comparing outputs from two or more production
C. PowerSIMM Planner
Resource Planning Modeling
Vernon Public Utilities 2023 IRP C-4
cost models allows a user to understand how changes in resource mix, price forecast,
operational constraints, or other aspects of the system will affect future outcomes.
Figure 84. Three-Day Dispatch Outputs Plotted against Load
Key inputs for production cost models include the simulated system conditions35 and supply
resource operating parameters. The operating parameters of dispatchable generation assets in
the portfolio—such as ramp rates or start-up times for thermal assets, leakage rates and round-
trip efficiencies for battery storage, or spill requirements for hydro—guide dispatch
optimization to ensure the model adheres to the actual physical capabilities and attributes of
the resources in the portfolio.
Capacity Expansion Optimization
A second common application of PowerSIMM in resource planning is for capacity expansion
optimization, which provides the least-cost selection of future resources over time, subject to
user-specified constraints. Such constraints may include resource adequacy requirements,
annual energy positions, renewable portfolio standards, or carbon emission limits. The
Automatic Resource Selection (ARS) module contains the PowerSIMM capacity expansion
model. ARS evaluates the performance of a portfolio of existing resources and candidate
resources across a range of future operating conditions to assess their likely revenues, costs,
and other characteristics (for example, carbon emissions). Based on the user inputs and
constraints, the model determines the optimal resource additions (or retirements) for
minimizing total costs while ensuring the generation portfolio can serve load without violating
loss-of-load standards or emissions constraints.
35 Weather, load, renewables, and market prices for fuel and power, when not a dispatch to load without intertie purchases.
C. PowerSIMM Planner
Resource Planning Modeling
Vernon Public Utilities 2023 IRP C-5
Figure 85 illustrates an ARS model that adds candidate resources to a portfolio to serve load at
the lowest cost. The portfolio of existing resources and customer load are evaluated with
candidate resources across a range of future conditions to select the optimal portfolio
composition under input constraints.
Figure 85. ARS Schematic of Candidate Resource Expansion
The input data requirements for ARS are generally the same as for production cost modeling
except for additional project cost information (for example, new candidate resources),
accredited capacity (for example, existing and new resources), and project specific constraints
such as annual build limits for new resources. Users must also define model constraints to
apply in the resource selection process, such as requirements for capacity, energy, or renewable
generation.
Resource Adequacy Analysis
The third main application of PowerSIMM in resource planning is for resource adequacy
analysis, which is used to assess the probability that a system will have adequate generation
resources to meet load over a wide range of conditions. Common metrics for this assessment
include loss-of-load probabilities (LOLP), expected unserved energy (EUE), and capacity
deficit (the amount of additional capacity needed to meet reliability targets), among others.
PowerSIMM’s resource adequacy module can also be used to assess the capacity contribution
from specific resources or technology types, which is typically measured with the effective
load-carrying capability (ELCC) metric.
C. PowerSIMM Planner
Resource Planning Modeling
Vernon Public Utilities 2023 IRP C-6
As shown in Figure 86, PowerSIMM’s simulation engine provides simulations of load,
renewables, and forced outages used to analyze the ability of a portfolio of resources to serve
load. Resource adequacy models may also include transmission constraints.
Figure 86. PowerSIMM Simulation Engine
The PowerSIMM resource adequacy model considers weather variability as a key driver to
renewable and load simulation. These simulations are coupled with stochastically imposed
forced outage in the dispatch module to measure common metrics, including LOLP,
loss-of-load expectations (LOLE), or loss-of-load hours (LOLH), EUE, and capacity deficit
(MW Short).
The dispatch algorithm in a resource adequacy model differs from that used in production cost
or capacity expansion models. Resource adequacy models evaluate systems based on how well
they can meet system needs, so the ability to import power is typically eliminated (or
significantly restricted). The model dispatches resources to minimize load shedding without
regard to dispatch cost. Market prices also have no bearing on the dispatch decision in a
resource adequacy model. Instead, the important inputs driving resource adequacy results
include forced outage rates, correlation between load and renewables, and operational
constraints. In each simulated hour of a resource adequacy study, the model calculates hourly
load requirements and compares this to the sum of total renewable generation, available
thermal capacity (that is, not on forced or scheduled outage), and available energy in storage
(which is charged with excess energy when it is available). The model then dispatches thermal
and energy storage resources chronologically (hour-by-hour) to determine how much (if any)
load cannot be met in each hour.
Resource adequacy models provide metrics to evaluate the reliability of a system. In addition,
resource adequacy models provide a useful means of determining the capacity contribution of
a specific resource, known as the ELCC. The standard approach for an ELCC analysis
involves three model runs. The reliability contribution of the ELCC resource is compared to
the reliability contribution from a “perfect” generator to determine the capacity value of the
ELCC resource.
C. PowerSIMM Planner
Simulation Details
Vernon Public Utilities 2023 IRP C-7
SIMULATION DETAILS
Weather Simulation
PowerSIMM has the ability to simulate weather across dozens of weather variables. Weather
simulations in PowerSIMM typically include daily maximum and minimum dry bulb
temperatures. These temperatures are then used as fundamental drivers for the load and for
alignment with renewable simulations. The weather simulation engine requires historical daily
maximum and minimum temperatures from weather stations in proximity to the weather-
related resources in the model. PowerSIMM stores historical data for hundreds of weather
stations via automated data pulls from the National Climate Data Center. PowerSIMM users
select weather stations to create weather zones for use in their specific studies.
PowerSIMM creates weather simulations by decomposing historical daily maximum and
minimum temperature data into seasonal and irregular components. The seasonal component
represents a smooth function showing how temperature changes over the year. The irregular
component captures fluctuations around the seasonal component and represents the day-to-
day variability in weather, which is the stochastic part of the weather simulations. The model
structure for the irregular component includes 30-day, 60-day, and 90-day moving averages
combined in a linear fashion with autoregression and random error terms. Annual patterns
drive most of the temperature simulations, but the irregular component of the model allows for
deviations from annual and seasonal norms, enabling potential periods of cooler weather in the
summer and warmer days in the winter.
PowerSIMM’s default method for creating temperature simulations does not use a temperature
forecast or include trends in temperature. The result is a set of simulations that resemble
historical weather conditions. However, the models can be configured to account for changes
in future temperatures to reflect predictions of a changing climate.
C. PowerSIMM Planner
Simulation Details
Vernon Public Utilities 2023 IRP C-8
The resulting simulations should reasonably match historical data. Figure 87 shows an
example of daily maximum dry bulb temperature simulations across a single year.
Figure 87. Multiple Simulations of Daily Maximum Dry Bulb Temperatures
The stochastic framework captures variations in weather conditions and extreme events.
PowerSIMM has the capability to modify the statistical parameters of the temperature
distribution to capture extreme events. Ascend runs validations to ensure that simulated
temperatures align with historical values at the mean level along with the fifth percentile and
ninety-fifth percentile.
Load Simulation
PowerSIMM creates realistic simulations of load that maintain a strong non-linear relationship
between load and temperature. The load simulations capture the range of uncertainty exhibited
in historical load data. After fitting historical load data to a time series model, PowerSIMM
scales the load simulations to match future expectations for energy consumption, peak demand
growth, and daily load shapes.
0
20
40
60
80
100
120
Temperature (°F)Month
Max Dry Bulb Simulations
C. PowerSIMM Planner
Simulation Details
Vernon Public Utilities 2023 IRP C-9
Simulations of load rely on past data to create accurate representation of the utility load that
matches historical statistics in the near term while matching the load forecast inputs through
the simulation time frame. By scaling load simulations to forecast values, PowerSIMM
produces accurate simulations of load that provide a realistic range of future load values
around the expected mean.
Figure 88 shows a time series of multiple load simulations.
Figure 88. Multiple Simulations of Load Over a Single Week
Figure 89 shows the load versus temperature relationship maintained in the load simulations—
when temperatures are at their highest load is at its highest, driven by the need to cool.
Figure 89. Load versus Temperature Relationships
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
1 2 3 4 5 6 7Load (MWh)Day
Load Simulations for First Week in January
C. PowerSIMM Planner
Simulation Details
Vernon Public Utilities 2023 IRP C-10
Wind and Solar Simulation
PowerSIMM generates simulations of renewables with time series models fit to hourly
historical data. Accurate wind and solar generation simulations are an essential part of power
system modeling for determining cost of service, loss of load risks, resource valuation, and
many other modeling outputs used in utility decision making.
Wind and solar simulation models use a structure that assumes generation is a function of
maximum and minimum temperature inputs from the weather simulations. The model also
allows structural variables, like time of day and month of year, to affect generation. For
example, if generation is typically highest on afternoons in spring, even apart from the
influence of temperature, then the model will be able to capture that. Finally, the model
includes autoregressive terms to capture the influence of generation in the previous hour to the
current hour’s generation. In addition to daily temperatures, hour, and month, solar
simulations include the solar irradiance calculated at the location of the solar resource. Solar
irradiance is a function of the time of day, day of the year, and the longitude and latitude of a
project.
PowerSIMM scales monthly wind and solar simulations to match monthly forecasts. Realistic
simulations of variable renewable energy generation lead to accurate analysis of the value of
renewable assets and the effect of renewables in production cost studies, resource adequacy, or
capacity expansion.
Figure 90 provides an example of solar simulations over a week.
Figure 90. Multiple Simulations of Solar Generation Over a Single Week
C. PowerSIMM Planner
Simulation Details
Vernon Public Utilities 2023 IRP C-11
Figure 91 provides an example of wind simulations over a week.
Figure 91. Multiple Simulations of Wind Generation Over a Single Week
C. PowerSIMM Planner
Simulation Details
Vernon Public Utilities 2023 IRP C-12
Small Hydro Simulation
PowerSIMM models small hydro resources as run-of-the-river hydro. Dispatchable hydro
resources are set up as a hydro project in PowerSIMM. Like other variable renewable
resources in PowerSIMM, hydro simulations use a time series model fit to historical hourly
generation data. The outcome is a set of simulations that capture the full range of potential
hydro generation to provide accurate results for utility decision making.
While the structural details of the hydro simulation model differ from the wind and solar
simulation models, the general inputs are similar. Hydro simulation models also assume
generation is a function of maximum and minimum temperature inputs from the weather
simulations. Like wind and solar simulations, the model used for hydro simulations also
allows structural variables, like time of day and month of year, to affect the generation. The
hydro model also includes autocorrelation terms.
Hydro simulations are scaled to match future expectations for monthly generation and
capacity. PowerSIMM ensures that average monthly hydro simulations match the hydro
forecast values. Figure 92 shows hydro simulations over a one-week period.
Figure 92. Multiple Simulations of Hydro Generation Over a Single Week
C. PowerSIMM Planner
Simulation Details
Vernon Public Utilities 2023 IRP C-13
Forward Price Simulation
PowerSIMM simulates forward curves using a stochastic model with parameters derived from
recent historical transaction dates and defined user inputs (as applicable). PowerSIMM
constructs a system of equations for forward contracts that includes the stochastic component
of the forward price, as well as the correlation with neighboring contract months, and other
commodities. This framework produces price simulations that are realistic, benchmark well to
historical data, and produce a payoff of cash flows consistent with market option quotes at
multiple strike prices.
Forward contract prices are modeled with an autoregression, or AR, model with volatilities
and correlations maintained in accordance with historical data or with inputs provided in the
forward price constraints. PowerSIMM uses an AR lag of one while limiting the coefficient to
a value of less than 1. An AR coefficient less than 1 is equivalent to a Geometric Brownian
Motion (GBM) model with mean reversion. Thus, the forward prices tend to do a random
walk with a constant pull back to the monthly mean values.
Figure 93 shows multiple simulations of forward prices. The mean across all simulations
equals to the input forecast.
Figure 93. Multiple Simulations of Forward Prices
0
20
40
60
80
100
120
140
2023 2024 2025 2026 2027 2028Price ($/MWh)Year
Forward Price Simulations
C. PowerSIMM Planner
Simulation Details
Vernon Public Utilities 2023 IRP C-14
Spot Price Simulation
PowerSIMM simulates spot prices beginning with the market expectations of monthly blocks
of energy represented as the average forward or forecast price over the monthly block.
Following the forward price simulations, spot prices are simulated with a hybrid approach that
captures the uncertainty in price risk in power markets and trading hubs, including variability
in weather, load, renewable output, congestion risk, and locational marginal prices (LMPs),
while maintaining consistency with forward price simulations.
A sample of hourly spot price simulations are shown in Figure 94 over the course of a week.
Figure 94. Simulations for Spot Prices Over a Single Week
Basis Price Simulation
Basis price items in PowerSIMM allow for models to contain multiple pricing nodes. The
main market configuration in PowerSIMM must select a primary forward price and spot price
for use in the price simulations. PowerSIMM derives basis prices as “structural” (regression-
based model) or “basic” (random noise) items from the main spot price configured in the
model. Basis prices are an important feature of PowerSIMM because they allow for market
interactions and simulate locational marginal prices of different nodes.
Scalars applied in the Basis model allow users to set up expected deviations in prices between
the basis price (node) and the reference spot price (hub). Users may set up scalars as a constant
value across all hours or as random variables where the parameters are a function of time. The
Basis module can also be used to produce sub-hourly simulations and ancillary services prices.
0
20
40
60
80
100
120
1 2 3 4 5 6 7Price ($/MWh)Day
Spot Price Simulations for First Week in June
Vernon Public Utilities 2023 IRP D-1
D. Annual Energy Forecast Data
Table 29 lists the energy forecasts (in MWh) for the entire planning period, including all the individual factors that modifying the base
energy forecast. The energy modifiers include the solar impact, load loss impact, two data centers, hydrogen fuel, public and fleet
electric vehicle impacts, and energy efficiency impacts.
Year
Base Energy
Forecast Solar Impact
Load Loss
Impact Data Center 1 Data Center 2 Hydrogen
Electric
Vehicles-Public
Electric
Vehicles-Fleet
Energy
Efficiency
Total Energy
Forecast
2023 1,206,173 (217) (65,741) — — — 4,376 414 (5,496) 1,139,509
2024 1,209,911 (703) (104,712) 61,506 — 15,460 8,769 652 (10,592) 1,180,292
2025 1,206,671 (1,191) (106,928) 67,015 43,664 61,217 13,125 886 (15,071) 1,269,388
2026 1,206,554 (1,410) (106,959) 67,009 74,453 61,217 17,496 1,122 (17,635) 1,301,848
2027 1,206,331 (1,410) (106,791) 67,008 74,461 61,320 21,877 1,318 (18,500) 1,305,613
2028 1,209,919 (1,410) (106,997) 67,198 74,664 61,457 26,341 1,421 (19,097) 1,313,494
2029 1,206,551 (1,410) (106,728) 67,015 74,463 61,217 30,613 1,416 (19,500) 1,313,636
2030 1,206,194 (1,410) (106,782) 67,016 74,463 61,217 34,994 1,416 (19,955) 1,317,152
2031 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 39,375 1,416 (20,430) 1,320,096
2032 1,209,992 (1,411) (107,923) 67,199 74,664 60,732 43,882 1,419 (20,482) 1,328,073
2033 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 48,131 1,416 (20,430) 1,328,852
2034 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 52,507 1,416 (20,430) 1,333,228
2035 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 56,883 1,416 (20,430) 1,337,603
2036 1,209,992 (1,411) (107,923) 67,199 74,664 60,732 61,434 1,419 (20,482) 1,345,625
2037 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 65,634 1,416 (20,430) 1,346,355
2038 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 70,009 1,416 (20,430) 1,350,730
D. Annual Energy Forecast Data
Vernon Public Utilities 2023 IRP D-2
Year
Base Energy
Forecast Solar Impact
Load Loss
Impact Data Center 1 Data Center 2 Hydrogen
Electric
Vehicles-Public
Electric
Vehicles-Fleet
Energy
Efficiency
Total Energy
Forecast
2039 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 74,385 1,416 (20,430) 1,355,106
2040 1,209,992 (1,411) (107,923) 67,199 74,664 60,732 78,987 1,419 (20,482) 1,363,178
2041 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 83,136 1,416 (20,430) 1,363,857
2042 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 87,512 1,416 (20,430) 1,368,233
2043 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 91,887 1,416 (20,430) 1,372,608
2044 1,209,992 (1,411) (107,923) 67,199 74,664 60,732 96,540 1,419 (20,482) 1,380,731
2045 1,206,671 (1,410) (107,600) 67,016 74,462 60,596 100,639 1,416 (20,430) 1,381,359
Table 29. Annual Energy Forecast with Modifiers (MWh)
Vernon Public Utilities 2023 IRP E-1
E. Stakeholder Outreach
VPU held three in-person meetings to inform its stakeholders about the IRP process and
conducted a 12-question survey to gather their input. The purpose of VPU’s stakeholder
outreach was to inform its stakeholders about the IRP process and the inherent issues
necessary to be addressed in the IRP development, and to garner input as to their preferences
and ideas. Discussions from the three meetings and responses to the survey enabled VPU to
better understand and appreciate diverse viewpoints. This information was incorporated into
the development of the IRP.
STAKEHOLDER MEETINGS
To engage its stakeholders directly, VPU held three in-person stakeholder meetings in the
Council Chambers in Vernon City Hall. The Green Vernon Commission, Business and
Industry Commission, and community members attended these meetings. At each meeting,
attendees were afforded the opportunity to comment and impart their thoughts on the IRP
process. VPU incorporated their feedback into the IRP analysis and employed their insights
into selecting the preferred capacity expansion portfolio.
First Stakeholder Meeting, March 15, 2023. Attendees were appraised of the overall IRP
process. This overview described the content of the IRP, the requirements proscribed by Public
Utilities Code (PUC) 9621, how VPU selected Ascend Analytics, Ascend’s task for creating
the IRP, purpose of the IRP, and concluded that VPU is engaging its stakeholders for their
guidance and input of the IRP goals and direction.
VPU gave a presentation that discussed the purpose of the IRP; the California Public Utilities
Code requirements; IRP policy and regulation compliance focusing on SB 350, SB 100, and
SB 1020; VPU’s current resource mix; renewable requirements and resources; information
about the City of Vernon, and the IRP timeline. The presentation asked for input from
attendees and promoted the online stakeholder survey, encouraging attendees to take it.
Second Stakeholder Meeting, May 11, 2023. Attendees were appraised of the same
information as with the first stakeholder meeting and that the results of the survey would be
presented.
E. Stakeholder Outreach
Stakeholder Meetings
Vernon Public Utilities 2023 IRP E-2
VPU gave a presentation that mainly focused on the survey results. The presentation began by
updating attendees on the progress of the IRP and giving an overview of VPU’s diverse
stakeholders, then presented the results of several survey questions and summarized the key
insights gained from the survey responses. VPU representatives described the various resource
categories in its current and future portfolio (solar, wind, geothermal, battery, CCS, and MGS)
and the resources that are being used to meet the state’s renewable energy and zero-emission
goals. The presentation concluded with an updated IRP timeline.
Third Stakeholder Meeting, June 21, 2023. VPU and Ascend gave an in-depth presentation
about the IRP. The presentation began by laying a foundation of the IRP’s progress and
repeated the key insights from the survey. It continued by describing the IRP’s goals and
objectives, the long-term resource sustainability strategy, and the planned GHG footprint
(especially concerning MGS) for complying with state regulations.
The presentation then focused on the modeling process used for developing a preferred
portfolio for meeting VPU obligations. First was a series of slides discussing the optimal supply
portfolio (encompassing high reliability and affordable rates, key stakeholder preferences, and
the sustainable resources necessary to meet those targets), an overview of the capacities of the
modeled resources, the estimated costs of each modeled resource, and the current VPU
generation portfolio.
Next was three sets of slides about each of the three potential portfolios that were modeled and
analyzed:
▪ Portfolio 1: solar, wind, and storage
▪ Portfolio 2: geothermal, solar, wind, and storage
▪ Portfolio 3: green hydrogen combustion turbine, solar, wind, and storage
Each set of slides first described the generation technology types of each portfolio: their energy
contribution (in MWh), their RA contribution (in MW), their RPS contribution (in MWh),
and zero-carbon clean energy contribution (in MWh); and concluded with the annualized net
present value (NPV) cost of load and the current average cost by MWh. A concluding slide
compared the annualized NPV costs of each portfolio with the cost of current day operations.
A final slide updated the IRP timeline.
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-3
STAKEHOLDER SURVEY AND RESULTS
VPU conducted a 12 question survey to better understand its customers’ thoughts regarding
their priorities about reliable power, affordable rates, renewable generation, EV charging,
DERs, and MGS. The survey was available from March 16, 2023 through May 4, 2023.
VPU made a significant effort to encourage stakeholders to complete the survey. VPU
publicized the survey in myriad ways:
▪ Discussing it and passing out survey flyers at stakeholder meetings, community and city
events, Business Breakfasts, and joint commission meeting.
▪ Advertising it through various social media channels, the City of Vernon’s website, the City
of Vernon’s newsletter, and VPU’s newsletter.
▪ Mailing survey flyers to every residential and commercial customer.
▪ Emailing all residential and commercial customers whose email addresses are in its
database.
▪ Phoning commercial customers.
▪ Partnering with the Business and Industry Commission and the Green Vernon Commission
to spread the word about the survey.
▪ Distributing flyers at numerous community events, especially the city’s Spring
Egg-stravaganza on March 23, 2023; the Vernon Job Fair on June 23, 2023; the Business
Breakfast on May 3, and the Wellness Equity Alliance Health event.
▪ Posting and leaving surveys at every public counter and at the entrance to City Hall.
▪ Distributing surveys through the Chamber of Commerce to notify current and prospective
property and business owners, realtors, and developers.
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-4
Figure 95 is an exact replica of the survey flyer.
Figure 95. Stakeholder Survey Flyer with QR Code
Survey Results
The 12-question survey touched on issues about VPU’s service, reliability, and rates as well as
stakeholder preferences and knowledge regarding key issues facing VPU today and over the
next two decades. Here is a summary of each survey question and its results.
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-5
Question 1: Stakeholder Demographics
The first question identified who responded to the survey. This information enabled VPU to
better apply the remaining survey responses.
Figure 96. Question 1: Stakeholder Demographic Responses
The predominant survey taker was employed in Vernon, followed by business and property
owners.
Question 2: Electric Services Satisfaction
VPU focuses on customer satisfaction. The second question considered how customers
thought about VPU’s service. Almost 82 percent were very satisfied or satisfied, with less than
5 percent being dissatisfied.
Figure 97. Question 2: Electric Services Satisfaction Responses
While VPU is proud of the results to this question, there remains work to be done. Customer
satisfaction is an area that VPU continues to pursue.
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-6
Question 3: Electric Service Ranking
Understanding how stakeholders feel about a variety of VPU’s services goes to the core of
customer satisfaction. The third question sought information about how respondents ranked
reliability, affordable rates, general customer service topics, and the environmental impact of
VPU’s generation portfolio.
Figure 98. Question 3: Electric Service Ranking Responses
As has been the case in the past, affordable rates and reliability remains a core focus, far greater
than considerations for the quality and responsiveness VPU’s related services and
environmental stewardship.
Question 4: Rates or Reliability Priority
When pitted head to head, respondents chose reliability over affordable rates.
Figure 99. Question 4: Rates or Reliability Priority Responses
While these findings are the reverse of responses to question 3, VPU plans to give dual priority
to rates and reliability.
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-7
Question 5: RPS Compliance
VPU must meet the mandated target of 60 percent of its generation portfolio to come from
renewable generation. By an overwhelming margin, respondents expect VPU to attain, and
not exceed, that target.
Figure 100. Question 5: RPS Compliance Responses
These responses directly inform the process of creating a preferred portfolio mix for 2030.
Question 6: RPS Increase Rate Impact
The sixth question informs the responses to the previous question. Two out of every three
respondents think that increased renewable generation penetration causes a corresponding
increase in rates, a factor that respondents want minimized.
Figure 101. Question 6: RPS Increase Rate Impact Responses
As a result, VPU plans to focus on adding renewable generation at the lowest possible cost.
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-8
Question 7: Green Efforts Ranking
About 45 percent of respondents are very interested or interested in having more public EV
charging stations installed in the City of Vernon. That percentage increases to 65 percent when
incentives are offered. Installing DERs and energy storage are also important to respondents.
Figure 102. Question 7: Green Efforts Ranking Responses
VPU already has installed a number of EV charging stations in the city and intends to install
more. To comply with state statutes, VPU is also easing the permitting process for EV charging
station installations.
Question 8: DER Penetration Impacts
Responses to increases in DER penetration show that their impact is largely unknown. For
example, the perception that DERs cause rates to increase, drop, or remain the same is about
equally divided, as is the perception that DER penetration affects reliability.
Figure 103. Question 8: DER Penetration Impacts Responses
As has been its focus, VPU ensures that increases in DERs have little to no effect on rates or
reliability.
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-9
Question 9: MGS Energy Supply
Two-thirds of respondents didn’t understand the impact that MGS has on reliability nor on
meeting the CPUC’s RA requirements.
Figure 104. Question 9: MGS Energy Supply Responses
VPU fully understands and appreciates the impact that MGS supply has on reliable service,
dispatchable generation, and state mandated compliance, and is fully considering the impact of
transitioning to a zero-carbon resource portfolio.
Question 10: MGS Investment Ranking
How to handle MGS’s future is an important transition topic at VPU. The tenth question was
an effort to understand how stakeholders felt about various transition paths. Of note,
44 percent of respondents feel that VPU should be independent from the state’s power grid.
Figure 105. Question 10: MGS Investment Ranking Responses
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-10
Switching from burning natural gas to hydrogen is currently an expensive option.
Complementing MGS with battery storage has the potential to minimize its thermal impact.
Over time, other options will undoubtedly present themselves. MGS’s generation currently is
about 39 percent of VPU’s entire generation, so the short-term impact to MGS portends to be
minimal. Replacing MGS’s baseload generation is a planning priority. This long-term picture
could present a thorny issue, one that VPU will carefully consider as state mandates approach.
Question 11: MGS Investment Rate Impact
The eleventh question goes to the rate increases that stakeholders will accept when investments
in MGS are made. Clearly, this response affects how VPU plans for the future of MGS.
Figure 106. Question 11: MGS Investment Rate Impact Responses
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-11
Question 12: Comments Solicited
The survey results contained 14 comments in response a solicitation for comments. Each
comment is listed here. Most comments pertained to reliability, rates, and investments in
renewable generation.
Small edits were made to correct spelling, capitalization, grammatical, and punctation
inconsistencies; words in parentheses were added for clarity. The original intent of the
comments has not been altered.
▪ If a rate increase went through to fund an [MGS] investment, would rates drop after the
project was completed? We support projects that keep power reliable. What good is low
rates and unreliable service; what am I paying for? That said, don’t take advantage and say
all rate increases are for [MGS] or for reliability.
▪ I love Vernon.
▪ No more rate increases.
▪ Rate increase should explain (which) MGS investment (is made) or what the increase
would be used for and why.
▪ We need stable rates.
▪ Need more incentive programs for installing the green energy equipment.
▪ Decrease rates and get back to being the lowest price(d) power provider in California.
▪ As a business owner in the community, the electricity isn’t broken, why attempt to “fix it”
and increase the cost when the cost of living has significantly increased within these 2 past
years. Get a grant or a loan the way that we do to run our businesses. Sincerely, Business
owner who pays their own bills.
▪ Nuclear power plants, as well as not banning or shutting down current energy production
methods, but instead a gradual transition.
▪ The earlier investment is made into renewable infrastructure. As it stands today, the lower
the cost of investment to enter the market.
▪ The extra charges recently have been out of line and outrageous. It questions why we are in
Vernon.
▪ We are manufacturing bags and compete with Chinese manufacturers. In China, they use
fossil fuel more than green resources to produce electricity. In order (to) survive in business,
the price of our electricity should stay competitive with its price in China.
▪ Need good incentive program to install solar panel and battery at our location.
▪ Grid reliability is the upmost important to our business. Manufacturing downtime & loss of
perishable stored product outweigh additional utility cost increases.
E. Stakeholder Outreach
Stakeholder Survey and Results
Vernon Public Utilities 2023 IRP E-12
Key Insights
VPU gained several key insights from the survey responses. Among them are the following:
▪ Over 80 percent are either satisfied or very satisfied with the services VPU provides.
▪ Over 80 percent ranked reliability and low rates as their top two priorities; 57 percent
selected reliability as their top priority.
▪ Over 70 percent do not believe VPU should exceed state mandated RPS targets.
▪ Over three-quarters are very interested in more EV charging station, electrification
incentives, DERs, and energy storage; over 37 percent are very interested in greater
electrification.
▪ Over 60 percent were not aware of Malburg Generating Station’s capability.
VPU presented these findings during the second stakeholder meeting.