AR 5 ATTACHMENT B Preliminary Official Statement — Pasadena City Council, May 13, 2024

PRELIMINARY OFFICIAL STATEMENT DATED _____________, 2024 NEW ISSUE – FULL BOOK-ENTRY ONLY Ratings:

Fitch: “___”
S&P: “___”
(See “RATINGS” herein)
In the opinion of Best Best & Krieger LLP, Los Angeles, California, Bond Counsel, subject to certain qualifications described herein, under existing statutes, regulations, rules and court decisions, and assuming certain representations and compliance with certain covenants and requirements described herein, the interest on the 2024A Bonds is excluded from gross income for federal income tax purposes and is not an item of tax preference for purposes of the federal alternative minimum tax imposed on individuals and corporations, however, interest is taken into account in determining the annual adjusted financial statement income of certain corporations for the purpose of computing the alternative minimum tax imposed on certain corporations. In the further opinion of Bond Counsel, such interest is exempt from California personal income taxes. See “TAX MATTERS” herein. [INSERT CITY LOGO]
$__________∗

CITY OF PASADENA, CALIFORNIA

ELECTRIC REVENUE/REFUNDING BONDS,
2024A SERIES
Dated: Date of Delivery Due: August 1, as shown on inside front cover This cover page contains certain information for general reference only. It is not intended to be a summary of the security or terms of this issue.

Investors are advised to read the entire Official Statement to obtain information essential to the making of an informed investment decision. Capitalized terms used on this cover page not otherwise defined shall have the meanings set forth herein.

The City of Pasade na, California Electric Revenue/Refunding Bonds, 2024A Series (the “2024A Bonds”) are being iss ued for the purpose of providing moneys to (i) refund all of the City’s outstanding Electric Revenue/Refunding Bonds, 2013A Series (the “2013A Bonds”), (ii) finance the costs of acquisition and construction of certain capital improvements to the Electric System of the City of Pasadena (the “City”), (iii) [make an additional deposit to the Parity Reserve Fund], and (iv) pay the costs of issuance of the 2024A Bonds. See “PLAN OF FINANCE” herein.

The 2024A Bonds are being issued pursuant to an Electric Revenue Bond Fiscal Agent Agreement, dated as of August 1, 1998, by and between the City and The Bank of New York Mellon Trust Company, N.A., as successor fiscal agent (the “Fiscal Agent”), as amended and supplemented, including as amended and supplemented by an Eleventh Supplement to Electric Revenue Bond Fiscal Agent Agreement, dated as of __________ 1, 2024, by and between the City and the Fiscal Agent (collectively, the “Fiscal Agent Agreement”). The 2024A Bonds are being issued in fully registered form, and, when issued, will be registered in the name of Cede & Co., as nominee of The Depository Trust Company, New York, New York ( “DTC”). DTC will act as securities depository of the 2024A Bonds. Beneficial ownership interests in the 2024A Bonds may be purchased in book-entry form only in denominations of $5,000 principal amount or any integral multiple thereof. Interest on the 2024A Bonds will be payable semiannually on February 1 and August 1 of each year, commencing February 1, 2025. Payments of principal of, premium, if any, and interest on, the 2024A Bonds will be paid by the Fiscal Agent to DTC, which is obligated in turn to remit such principal, premium, if any, and interest to its participants for subsequent disbursement to the beneficial owners of the 2024A Bonds.

The 2024A Bonds are subject to optional and mandatory sinking fund redemption prior to maturity as described herein.

The 2024A Bonds are an obligation payable only from the Net Income of the Electric System in the Light and Power Fund of the City and certain other funds as provided in the Fiscal Agent Agreement. The 2024A Bonds are secured by a pledge of and lien upon Net Income of the Electric System on a parity with other obligations of the Electric System payable from Net Income of the Electric System and issued from time to time pursuant to the terms of the Fiscal Agent Agreement. Upon the issuance of the 2024A Bonds and refunding of the 2013A Bonds, in addition to t he 2024A Bonds, the City will have $104,810,000 principal amount of parity obligations outstanding payable from Net Income of the Electric System pursuant to the terms of the Fiscal Agent Agreement.

The general fund of the City is not liable for the payment of any 2024A Bonds, any premium thereon upon redemption prior to maturity or their interest, nor is the credit or taxing power of the City pledged for the payment of any 2024A Bonds, any premium thereon upon redemption prior to maturity or their interest. The Owner of any 2024A Bond shall not compel the exercise of the taxing power by the City or the forfeiture of any of its property. The principal of and interest on any 2024A Bonds and any premiums upon the redemption of any thereof prior to maturity are not a debt of the City nor a legal or equitable pledge, charge, lien or encumbrance upon any of its property or upon any of its income, receipts or revenues, except the Net Income and other funds, security or assets which are pledged to the payment of t he 2024A Bonds, interest thereon and any premiums upon redemption pursuant to the Fiscal Agent Agreement.

The 2024A Bonds will be sold by competitive sale on or about __________, 202 4 pursuant to the Notice Inviting Bids dated __________, 202 4.

The 2024A Bonds will be offered when, as and if issued, sold and received by the Initial Purchaser, subject to the approval of Best Best & Krieger LLP, Los Angeles, California, Bond Counsel, and certain other conditions. PFM Financial Advisors LLC, Los Angeles, California, is serving as Municipal Advisor to the City in connection with the issuance of the 2024A Bonds. Certain legal matters will be passed upon for the City by Michele Beal Bagneris, City Attorney of the City, and by Best Best & Krieger LLP, Los Angeles, California, Disclosure Counsel. It is anticipated that the 2024A Bonds in definitive form will be available for delivery to DTC in New York, New York by Fast Automated Securities Transfer (FAST) on or about _________, 2024.

Dated: __________, 2024 ∗ Preliminary, subject to change.

This Preliminary Official Statement and the information contained herein are subject to completion or amendment. These secur ities may not be sold nor may offers to buy be accepted prior to the time the Official Statement is delivered in final form. Under no circumstances shall this Preliminary Official Statement constitute an offer to sell or a solicitation of an offer to buy, nor shall there be any sale of these securities in any jurisdiction in which such offer, solicitation, or sale would be unlawful prior to registration or qualification under the securities laws of such jurisdiction.

Attachment B

$__________∗

CITY OF PASADENA, CALIFORNIA

ELECTRIC REVENUE/REFUNDING BONDS,
2024A SERIES

MATURITY SCHEDULES
$__________ Serial 2024A Bonds
Maturity Date
(August 1)
Principal
Amount
Interest
Rate Yield

CUSIP No.†
(702248)

$__________ _____% Term 2024A Bonds due August 1, ______ - Yield _____% CUSIP †: __________

∗ Preliminary, subject to change.
† CUSIP is a registered trademark of The American Bankers Association. CUSIP data herein is provided by CUSIP Global Services, managed by S&P Capital IQ Financial Services LLC on behalf of The American Bankers Association. CUSIP numbers have been assigned by an independent company not affiliated with the City, Pasadena Water and Power (“PWP”) or the Initial Purchaser and are included solely for the convenience of the holders of the 2024A Bonds. This data is not intended to create a database and does not serve in any way as a substitute for the CUSIP Services. None of the City, PWP or the Initial Purc haser shall be responsible for the selection or correctness of the CUSIP numbers set forth herein. The CUSIP number for a specific maturity is subject to being changed after the delivery of the 2024A Bonds as a result of various subsequent actions including, but not limited to, a refunding in whole or in part of such maturity or as a result of the procurement of secondary market portfolio insurance or other similar enhancement by investors that is applicable to all or a portion of the 2024A Bonds.

CITY OF PASADENA

CITY COUNCIL
Victor M. Gordo, Mayor
Steve Madison, Vice-Mayor
Tyron Hampton, Council Member
Justin Jones, Council Member
Jason Lyon, Council Member
Gene Masuda, Council Member
Jessica Rivas, Council Member
Felicia Williams, Council Member

CITY STAFF
Miguel Márquez, City Manager
Matthew Hawkesworth, Director of Finance
Vicken Erganian, Treasurer and Deputy Director of Finance

CITY ATTORNEY
Michele Beal Bagneris

PASADENA WATER AND POWER STAFF
David Reyes, Acting General Manager
Lynne Chaimowitz, Assistant General Manager - Finance and Administration Kelly Nguyen, Assistant General Manager - Power Supply
Varoojan Avedian, Acting Assistant General Manager - Power Delivery Stacie Takeguchi, Assistant General Manager – Water
Jeremy Marquette, Assistant General Manager – Customer Service and Technology Jennifer Guess Mayo, Division Head- Customer Relations & Legislation

SPECIAL SERVICES

MUNICIPAL ADVISOR
PFM Financial Advisors LLC
Los Angeles, California

BOND AND DISCLOSURE COUNSEL
Best Best & Krieger LLP
Los Angeles, California

FISCAL AGENT
The Bank of New York Mellon Trust Company, N.A.

Los Angeles, California

INDEPENDENT ACCOUNTANTS
Lance, Soll & Lunghard, LLP
Brea, California

No dealer, broker, salesperson or other person has been authorized by the City to give any information or to make any representations, other than those contained herein, and if given or made, such other information or representations must not be relied upon as having been authorized by any of the foregoing. This Official Statement does not constitute an offer to sell or the solicitation of an offer to buy, nor shall there be any sale of the 2024A Bonds in any jurisdiction in which such offer, solicitation or sale would be unlawful.

This Official Statement is not to be construed as a contract with the purchasers of the 2024A Bonds.

Statements contained in this Official Statement involving any estimates, forecasts or matters of opinion, whether or not expressly so stated, are intended solely as such and not as a representation of fact.

The information set forth herein has been furnished by the City and other sources which are believed to be reliable, but is not guaranteed as to accuracy or completeness. The information and expressions of opinions herein are subject to change without notice and neither the delivery of this Official Statement nor any sale made hereunder shall, under any circumstances, create any implication that there has been no change in the affairs of the City or the Electric System since the date hereof.

IN CONNECTION WITH THE OFFERING OF THE 2024A BONDS, THE INITIAL PURCHASER

MAY OVER -ALLOT OR EFFECT TRANSACTIONS THAT MAY STABILIZE OR MAINTAIN THE MARKET PRICE OF SUCH 2024A BONDS AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. THE INITIAL PURCHASER IN CONNECTION WITH ANY REOFFERING MAY OFFER AND SELL THE 2024A BONDS TO CERTAIN DEALERS, INSTITUTIONAL INVESTORS AND OTHERS

AT PRICES LOWER THAN THE PUBLIC OFFERING PRICES STATED ON THE INSIDE COVER PAGE

HEREOF AND SUCH PUBLIC OFFERING PRICES MAY BE CHANGED FROM TIME TO TIME BY THE INITIAL PURCHASER.

This Official Statement, including any supplement or amendment hereto, is intended to be filed with the Municipal Securities Rulemaking Board through the Electronic Municipal Market Access (EMMA) website. The City maintains a website. However, the information presented therein is not part of this Official Statement and should not be relied upon in making investment decisions with respect to the 2024A Bonds.

References to website addresses presented herein are for informational purposes only and may be in the form of a hyperlink solely for the reader ’s convenience. Unless specified otherwise, such websites and the information or links contained therein are not incorporated into, and are not part of, this Official Statement for purposes of, and as that term is defined in, Securities and Exchange Commission Rule 15c2-12. ___________________________________

CAUTIONARY STATEMENTS REGARDING

FORWARD-LOOKING STATEMENTS IN THIS OFFICIAL STATEMENT
Certain statements included or incorporated by reference in this Official Statement constitute “forward- looking statements.” Such statements are generally identifiable by the terminology used such as “plan,” “expect,” “estimate,” “budget” or other similar words. The achievement of certain results or other expectations contained in such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements described to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. The City does not plan to issue any updates or revisions to those forward- looking statements if or when its expectations or events, conditions or circumstances on which such statements are based occur.

TABLE OF CONTENTS

Page

-i-

INTRODUCTION ............................................................... 1 Purpose ........................................................................ 1 Authority for Issuance ................................................. 1 The City ....................................................................... 1 Security and Sources of Payment for the
2024A Bonds ...................................................... 2 Parity Reserve Fund ..................................................... 2 Rate Covenant .............................................................. 2 Other Matters ............................................................... 3 PLAN OF FINANCE .......................................................... 3 Funding of Capital Improvements ............................... 3 Refunding of 2013A Bonds ......................................... 3

ESTIMATED SOURCES AND USES OF
FUNDS................................................................. 5 THE 2024A BONDS ........................................................... 5 General ........................................................................ 5 Redemption .................................................................. 5 Debt Service Schedule ................................................. 7

SECURITY AND SOURCES OF PAYMENT
FOR THE 2024A BONDS ................................... 7 General ........................................................................ 7 Rate Covenant .............................................................. 8 The Light and Power Fund .......................................... 8 Parity Reserve Fund ................................................... 10 Additional Bonds ....................................................... 11 Limitations on Remedies ........................................... 13 PASADENA WATER AND POWER .............................. 13 Organization .............................................................. 13 Management .............................................................. 14 Employees ................................................................. 15 THE ELECTRIC SYSTEM OF PWP ............................... 17 General ...................................................................... 17 Energy Integrated Resource Plan ............................... 18 Insurance .................................................................... 18 Power Supply Resources ........................................... 18 City-Owned Generating Facilities ............................. 20 Joint Powers Agency Generation and Fuel
Resources/Remote Ownership Interests ........... 21
Purchased Power ........................................................ 26 Renewable Resources ................................................ 27 Solar Initiative and Photovoltaic Program ................. 29 Energy Efficiency Goals and Programs ..................... 29 Future Power Supply Resources ................................ 29 Fuel Supply ................................................................ 29 Transmission Resources ............................................ 30 Existing Transmission Resources .............................. 31 Future Transmission Resources ................................. 33 Inter-Utility Sales Transactions ................................. 33 Interconnections and Distribution Facilities .............. 33 Electric Rates and Charges ........................................ 33 Billing and Collection Procedures ............................. 34 Impact of Economic Conditions of the
Development in the District.............................. 35 Customers, Energy Sales and Revenues .................... 35 Indebtedness and Joint Agency Obligations .............. 36 Reserve Policies ......................................................... 37 Funding of Capital Improvements ............................. 39 Historical Operating Results and Debt Service
Coverage .......................................................... 40 Condensed Balance Sheet .......................................... 42 RATE REGULATION ...................................................... 42

DEVELOPMENTS IN THE CALIFORNIA
ENERGY MARKETS ........................................ 43 State Legislation ........................................................ 43 Future Regulation ...................................................... 50 Impact of Developments on the City ......................... 50

OTHER FACTORS AFFECTING THE
ELECTRIC UTILITY INDUSTRY ................... 50
Federal Policy on Cybersecurity ................................ 50 Federal Energy Legislation ........................................ 51 Federal Regulation of Transmission Access .............. 52 Other Federal Legislation .......................................... 53 Environmental Issues ................................................. 53 Global Health Emergencies; COVID-19
Pandemic .......................................................... 57 Other Factors ............................................................. 57

CONSTITUTIONAL LIMITATIONS IN

CALIFORNIA AFFECTING FEES

AND CHARGES IMPOSED BY THE
CITY .................................................................. 58 Proposition 218 and Proposition 26 ........................... 58 Future Initiatives ........................................................ 59 RATINGS ......................................................................... 60 TAX MATTERS ............................................................... 60 Federal Income Taxes ................................................ 60 LITIGATION .................................................................... 61 AUDITED FINANCIAL STATEMENTS ........................ 61 FORWARD-LOOKING STATEMENTS ......................... 62 MUNICIPAL ADVISOR .................................................. 62 CERTAIN LEGAL MATTERS ........................................ 62 PURCHASE AND REOFFERING ................................... 62 CONTINUING DISCLOSURE ........................................ 63 EXECUTION AND DELIVERY...................................... 64

APPENDIX A – THE CITY OF PASADENA ............... A-1
APPENDIX B – AUDITED FINANCIAL STATEMENTS

OF PASADENA WATER AND POWER

ENTERPRISE FUNDS FOR THE FISCAL YEAR
ENDED JUNE 30, 2023 ........................................ B-1 APPENDIX C – BOOK-ENTRY SYSTEM ................... C-1
APPENDIX D – SUMMARY OF CERTAIN

PROVISIONS OF THE FISCAL AGENT
AGREEMENT ....................................................... D-1 APPENDIX E – FORM OF CONTINUING DISCLOSURE
AGREEMENT ....................................................... E-1 APPENDIX F – PROPOSED FORM OF OPINION OF
BOND COUNSEL .................................................. F-1

1 PRELIMINARY OFFICIAL STATEMENT
$________

CITY OF PASADENA, CALIFORNIA

ELECTRIC REVENUE/REFUNDING BONDS,
2024A SERIES

INTRODUCTION
This Introduction is subject in all respects to the more complete information contained elsewhere in this Official Statement and the offering of the City of Pasadena, California Electric Revenue/Refunding Bonds, 2024A Series to potential investors is made only by means of the entire Official Statement. Capitalized terms used in this Official Statement and not otherwise defined herein shall have the respective meanings assigned to them in the Fiscal Agent Agreement.

Purpose
The purpose of this Official Statement, which includes the cover page and Appendices hereto, is to set forth certain information in connection with the issuance and sale by the City of Pasadena, California (the “City”) of $_______ aggregate principal amount of its Electric Revenue/ Refunding Bonds, 2024A Series (the “ 2024A Bonds”). The 2024A Bonds are being issued for the purpose of providing moneys to (i) refund all of the City’ s outstanding Electric Revenue/Refunding Bonds, 2013A Series (the “ 2013A Bonds”), (ii) finance the costs of acquisition and construction of certain capital improvements to the Electric System of the City, (iii) [ make an additional deposit to the Parity Reserve Fund], and (iv) pay the costs of issuance of the 2024A Bonds. See “PLAN OF FINANCE.”
Authority for Issuance
The 2024A Bonds are authorized and will be issued pursuant to Article XIV of the Charter of the City, as amended (the “Charter”), an Ordinance adopted by the City Council of the City (the “City Council”) on September 19, 2016, and an Electric Revenue Bond Fiscal Agent Agreement, dated as of August 1, 1998, by and between the City and The Bank of New York Mellon Trust Company, N.A. (successor to BNY Western Trust Company), as fiscal agent (the “Fiscal Agent”), as amended and supplemented, including as amended and supplemented by an Eleventh Supplement to Electric Revenue Bond Fiscal Agent Agreement, dated as of __________ 1, 2024 (the “Eleventh Supplement ”), by and between the City and the Fiscal Agent (collectively, the “Fiscal Agent Agreement”). All Electric Revenue Bonds issued pursuant to the Fiscal Agent Agreement are collectively referred to herein as the “Bonds.”
The City
The City is a charter city of the State of California (the “State”), comprising approximately 23 square miles, located in Los Angeles County (the “County”) in the northwestern portion of the San Gabriel Valley. See APPENDIX A – “THE CITY OF PASADENA” herein. The City owns and operates a municipal electric public utility (the “Electric System”), established by the Charter. The Electric System is managed and controlled by Pasadena Water and Power ( “PWP”) and supplies electricity to virtually all of the electric customers within the City limits. For the f iscal year (“Fiscal Year”) ended June 30, 2023, the City estimates there were 66,355 customers of the Electric System, comprised of 57,769 residential customers, 8,575 commercial and industrial customers, 5 street lighting and traffic signals customers and 6 wholesale customers. The total quantity of energy generated and purchased was 1,104,604 megawatt hours ( “MWh”), and the peak demand was 319 megawatts (“MW”).

2 Security and Sources of Payment for the 2024A Bonds
The 2024A Bonds are an obligation payable only from the Net Income of the Electric System in the Light and Power Fund of PWP (t he “Light and Power Fund”) and amounts in the Parity Reserve Fund as provided in the Fiscal Agent Agreement. The 2024A Bonds are secured by a pledge of and lien upon Net Income of the Electric System on a parity with other obligations of the Electric System issued from time to time pursuant to the terms of the Fiscal Agent Agreement payable from Net Income of the Electric System and a pledge of amounts in the Parity Reserve Fund. Upon the issuance of the 2024A Bonds and the refunding of the 2013A Bonds, i n addition to the 2024A Bonds, the City will have outstanding $102,565,000 principal amount of its Electric Revenue/Refunding Bonds, 2016A Series (the “2016A Bonds”) and $2,245,000 principal amount of its Electric Revenue/Refunding Bonds, 2019A Series (the “2019A Bonds,” together with the 2016A Bonds, the “Outstanding Bonds”). See “SECURITY AND SOURCES OF PAYMENT FOR THE 2024A BONDS – Parity Reserve Fund” and “– Additional Bonds.”
The 2024A Bonds are limited obligations of the City and are not secured by a legal or equitable pledge of, or charge or lien upon, any property of the City or any of its income or receipts, except the Net Income of the Electric System. Neither the full faith and credit nor the taxing power of the City is pledged to the payment of the principal of, premium, if any, or interest on the 2024A Bonds. No tax or other source of funds, other than the Net Income of the Electric System, is pledged to pay the principal of, premium, if any, or interest on the 2024A Bonds.

Neither the paymen t of the principal of, nor the interest on, the 2024A Bonds constitutes a debt, liability or obligation of the City for which the City is obligated to levy or pledge any form of taxation or for which it has levied or pledged any form of taxation.

The general fund of the City (the “General Fund”) is not liable for the payment of any 2024A Bonds, any premium thereon upon redemption prior to maturity or their interest, nor is the credit or taxing power of the City pledged for the payment of any 2024A Bonds, any premium thereon upon redemption prior to maturity or their interest. No Owner of any 2024A Bond shall compel the exercise of the taxing power by the City or the forfeiture of any of its property. The principal of and interest on any 2024A Bonds and any premiums upon the redemption of any thereof prior to maturity are not a debt of the City nor a legal or equitable pledge, charge, lien or encumbrance upon any of its property or upon any of its income, receipts or revenues, except the Net Income and other funds, security or assets which are pledged to the payment of the 2024A Bonds, interest thereon and any premiums upon redemption pursuant to the Fiscal Agent Agreement.

Parity Reserve Fund
Pursuant to Section 1413 of Article XIV of the Charter, the City has established the Parity Reserve Fund.

The Parity Reserve Fund is required to be maintained in an amount equal to the Reserve Fund Requirement so long as any Bonds or Parity Obligations secured by the Parity Reserve Fund remain Outstanding. Amounts held in or credited to the Parity Reserve Fund are pledged to and may be used solely for payment of debt service on the Bonds or Parity Obligations secured thereby in the event that money in the Parity Obligation Payment Fund or any comparable fund established for the payment of principal and interest on the Parity Obligations secured thereby is insufficient therefor.

On such date the 2016A Bonds and the 2019A Bonds are defeased, paid or discharged in accordance with their terms and are no longer Outstanding for purposes of the Fiscal Agent Agreement, the Reserve Fund Requirement shall be zero dollars and accordingly, all of the amounts held in the Parity Reserve Fund shall be released to the City to be used for lawful purposes. See “SECURITY AND SOURCES OF PAYMENT FOR THE 2024A BONDS – Parity Reserve Fund.”
Rate Covenant
The City has covenanted in the Fiscal Agent Agreement to fix the rates for services furnished by the Electric System so as to provide Gross Revenues at least sufficient to pay, as the same become due, the principal

3 of and interest on the Bonds, any Parity Obligations and all other obli gations and indebtedness payable from the Light and Power Fund or from any fund derived therefrom, and also the necessary Maintenance and Operating Expenses, so that the Net Income of the Electric System will be at least equal to 1.10 times the amount necessary to pay principal and interest as the same become due on all Outstanding Bonds and Parity Obligations. See “SECURITY AND SOURCES OF PAYMENT FOR THE 2024A BONDS – Rate Covenant.” Other Matters
This Official Statement speaks only as of its date, and th e information and expressions of opinions contained herein are subject to change without notice, and neither delivery of this Official Statement nor any sale made hereunder shall, under any circumstances, create any implication that there has been no change in the affairs of the City or the Electric System since the date hereof. This Official Statement, including any supplement or amendment hereto, is intended to be filed with the Municipal Securities Rulemaking Board (“MSRB”) through the Electronic Munici pal Market Access ( “EMMA”) website. Forward looking statements in this Official Statement are subject to risks and uncertainties, including particularly those relating to competition and electric industry restructuring, and the economy of the City’s service area.

This Official Statement includes summaries of the terms of the 2024A Bonds, the Fiscal Agent Agreement, the Continuing Disclosure Agreement and certain contracts and other arrangements for the supply of capacity and energy. The summaries of and r eferences to all documents, statutes, reports and other instruments referred to herein do not purport to be complete, comprehensive or definitive, and each such summary and reference is qualified in its entirety by reference to each document, statute, repo rt or instrument. Copies of the Fiscal Agent Agreement and the Continuing Disclosure Agreement are available for inspection at the offices of the City, and will be available upon request and payment of duplication costs from the Fiscal Agent. Additional information regarding this Official Statement may be obtained by contacting the Fiscal Agent or the City . The City’s address and telephone number for such purpose are as follows: City of Pasadena, 100 North Garfield Avenue, 3rd Floor, Pasadena, California 91101-1726, (626) 744-4350, Attention: Director of Finance.

PLAN OF FINANCE
General
SECTION 1. The 2024A Bonds are being issued to provide funds to (i) refund all of the City’s outstanding Electric Revenue/Refunding Bonds, 2013A Series (the “2013A Bonds”), (ii) fi nance the costs of acquisition and construction of certain capital improvements to the Electric System of the City, (iii) [make an additional deposit to the Parity Reserve Fund], and (iv) pay the costs of issuance of the 2024A Bonds.

Funding of Capital Improvements
The proceeds of the 2024A Bonds are expected to be used to finance various capital projects of the Electric System. The use of the 2024A Bond proceeds will support the capital improvement plan outlined in the Power Delivery Master Plan to support the ongoing modernization and reliability of the Electric System. See “THE ELECTRIC SYSTEM OF PWP - Funding of Capital Improvements” for a description of the Power Delivery Master Plan. The projects to be funded by the 2024A Bonds include: (i) distribution voltage conversion projects, (ii) multiple substation modernization and upgrades to meet reliability needs, (iii) sub -transmission system upgrades, (iv) distribution system expansion and replacements, and (v) pole and transformer replacements.

Refunding of 2013A Bonds
The City has mailed to the owners of the 2013A Bonds a conditional notice of redemption stating that the 2013A Bonds will be redeemed on the date of delivery of the 2024A Bonds. Accordingly, on the date of delivery of the 2024A Bonds, proceeds of the 2024A Bonds will be used to redeem $65,445,000 principal amount of the 2013A Bonds at a redemption price equal to 100% of the principal amount thereof, together with accru ed and unpaid interest thereon.

4 [Remainder of page intentionally left blank.]

5 ESTIMATED SOURCES AND USES OF FUNDS
The estimated sources and uses of funds in connection with the 2024A Bonds are as follows:

Sources:

Principal Amount of 2024A Bonds
Plus Original Issue Premium
Total Sources

Uses:

Redemption of the 2013A Bonds
Deposit to 2024A Electric Bond Construction Fund
[Deposit to Parity Reserve Fund]
Deposit to Costs of Issuance Account (1)
Initial Purchaser’s Discount
Total Uses
_________________________
(1) Includes fees of Bond Counsel and Disclosure Counsel, the Fiscal Agent, Municipal Advisor, rating agencies, printing costs and other miscellaneous expenses.

THE 2024A BONDS
General
The 2024A Bonds will be dated their date of delivery and will bear interest from that date at the rates per annum and will mature on August 1 in the years set forth on the inside cover page of this Official Statement.

Interest on the 2024A Bonds will be payable semiannually on February 1 and August 1, commencing February 1, 2025, and will be calculated on the basis of a 360-day year comprised of twelve 30-day months. The 2024A Bonds are being issued in fully registered form, and when issued, will be registered in the name of Cede & Co., as nominee of The Depository Trust Company, New York, New York ( “DTC”). So long as Cede & Co. is the registered owner of the 2024A Bonds, references herein to the owners or registered owners shall mean Cede & Co., and not the benef icial owners of the 2024A Bonds. See APPENDIX C – “ BOOK-ENTRY SYSTEM” herein.

Redemption
Optional Redemption. The 2024A Bonds maturing prior to August 1, 20___ are not subject to call and redemption prior to maturity. The 2024A Bonds maturing on or after August 1, 20___ are subject to call and redemption prior to maturity, at the option of the City, as a whole or in part, on August 1, 20___ or on any date thereafter, in any order of maturity and by lot within a single maturity, from funds derived by the City from any legal source, at a redemption price equal to the principal amount of the 2024A Bonds called for redemption, together with interest accrued thereon to the date of redemption, without premium. [Remainder of page intentionally left blank.]

6 Mandatory Sinking Fund Redemption. The 2024A Bonds maturing on August 1, 20___ shall be subject to mandatory sinking fund redemption in part at par, and by lot, from mandatory sinking account payments set aside in the Parity Obligation Payment Fund for such purpose, on August 1 of the years and in the amounts set forth below:

Term 2024A Bonds Due August 1, 20___
Year Principal Amount

†
_______________________
† Final Maturity.

Upon any purchase or optional redemption of the 2024A Bonds designated to be term bonds, an amount equal to the aggregate principal amount of 2024A Bonds so purchased or redeemed shall be credited towards a part or all of any one or more yearly mandatory sinking account payments required by the Fiscal Agent Agreement, as directed in writing by a certificate of the Director of Finance. The portion of any such mandatory sinking account payments remaining after the deduction of any such amounts credited towar d the same (or the original amount of any such mandatory sinking account payments if no such amounts shall have been credited toward the same) shall constitute the unsatisfied balance of such mandatory sinking account payments for the purpose of the calculation of principal payments due on any future principal payment date. In such event, the City shall provide the Fiscal Agent with a revised sinking fund payment schedule.

Notice of Redemption. Notice of redemption shall be given by the Fiscal Agent, not less than thirty (30) nor more than sixty (60) days prior to the redemption date, (i) by mail to each Owner and the Securities Depositories and (ii) electronically to one or more of the EMMA database designated by the MSRB at www.emma.msrb.org, or, in accordance with then current guidelines of the Securities and Exchange Commission (“SEC”), such other addresses and/or such other services providing information with respect to called bonds as the City may designate ( “Information Services”). Notice of redemption to the Securities Depositories shall be given by telecopy, certified, registered or overnight mail or by such other method as may be requested by the Securities Depositories. Each notice of redemption shall state the date of such notice, the date of issue of the 2024A Bonds to which such notice relates, the redemption date, the Redemption Price, the place or places of redemption (including the name and appropriate address or addresses of the Fiscal Agent), the CUSIP number (if any) of the maturity or maturities, and, if less than all of any such maturity, the distinctive certificate numbers of the 2024A Bonds of such maturity to be redeemed and, in the case of 2024A Bonds to be redeemed in part only, the respective portions of the principal amount thereof to be redeemed. Each such notice shall also state that on said date there will become due and payable on each of said 2024A Bonds the Redemption Price thereof or of said specified portion of the principal amount thereof in the case of a 2024A Bond to be redeemed in part only, together with interest accrued thereon to the date fixed for redemption, and that from and after such redemption date interest thereon shall cease to accrue, and shall require that such 2024A Bonds be then surrendered at the address or addresses of the Fiscal Agent specified in the redemption notice. Neither the City nor the Fiscal Agent shall have any responsibility for any defect in the CUSIP number that appears on any 2024A Bond or in any redemp tion notice with respect thereto, and any such redemption notice may contain a statement to the effect that CUSIP numbers have been assigned by an independent service for convenience of reference and that neither the City nor the Fiscal Agent shall be liable for any inaccuracy in such numbers.

In the event of an optional redemption of 2024A Bonds, if the City shall not have deposited or otherwise made available to the Fiscal Agent the money required for the payment of the redemption price of the 2024A Bonds to be redeemed at the time of the mailing of notice of redemption, such notice of redemption shall state that the redemption is expressly conditioned upon the timely deposit of sufficient funds therefor with the Fiscal Agent.

7 Failure by the Fiscal Agent t o give notice to any one or more of the Information Services or Securities Depositories or failure of any Owner to receive notice or any defect in any such notice shall not affect the sufficiency of the proceedings for redemption.

Effect of Redemption. When notice of redemption has been given, and when the amount necessary for the redemption of the 2024A Bonds called for redemption (principal and premium) is set aside for that purpose, the 2024A Bonds designated for redemption shall become due and payable on the redemption date, and upon presentation and surrender of said 2024A Bonds, at the place specified in the notice of redemption, such 2024A Bonds shall be redeemed and paid at said redemption price, and no interest shall accrue on such 2024A Bonds called for redemption after the redemption date.

Debt Service Schedule
The table below sets forth the annualized debt service payments on the 2024A Bonds.

Year Ending
(August 1) Principal Interest Total

Total

SECURITY AND SOURCES OF PAYMENT FOR THE 2024A BONDS
General
The Bonds are an obligation payable only from the Net Income of the Electric System in the Light and Power Fund and amounts in the Parity Reserve Fund as provided in the Fiscal Agent Agreement. The 2024A Bonds are secured by a pledge of and lien upon Net Income of the Electric System on a parity with other obligations of the Electric System payable from Net Income of the Electric System and issued from time to time pursuant to the Fiscal Agent Agreement, including the Outstanding Bonds, and a pledge of amounts in the Parity Reserve Fund. See “– Parity Reserve Fund” and “– Additional Bonds” below. “Net Income ” is defined in the Fiscal Agent Agreement as Gross Revenues less Maintenance and Operating Expenses. “Gross Revenues” means all revenues (as defined in Section 54315 of the Government Code of California, which include all charges received for and all other income and receipts derived by PWP from the operation of the Electric System or arising from the Electric System) received by PWP from the services, facilities, energy and distribution of electric energy by PWP, including (i) income from investments, and (ii) for the purposes of determining compliance with the rate covenant in the Fiscal Agent Agreement only, the amounts on deposit in the Stranded Investment Reserve or in any other unrestricted funds of the Electric System designated by the City Council by resolution (or by approval of a budget of the Light and Power Fund providing for such transfer) and

8 available for the purpose of paying Maintenance and Operating Expenses and/or debt service on the Bonds and/or any Parity Obligations, but excepting therefrom (a) all reimbursement charges and deposits to secure service and (b) any charges collected by any person to amortize or otherwise relating to the payment of the uneconomic portion of costs associated with assets and obligations ( “stranded costs”) of the Electric System or of any joint powers agency in which the City participates which the City has dedicated to the payment of obligations other than the Bonds or any Parity Obligations then outstanding, the payments of which obligations will be applied to or pledged to or otherwise set aside for the reduction or retirement of outstanding obligations of the City or any joint powers agency in which the City participates relating to such “stranded costs” of the City or of any such joint powers agency to the extent such “stranded costs” are attributable to, or the responsibility of, the City. “Maintenance and Operating Expenses ” is defined in the Fiscal Agent Agreement to mean the amount required to pay the reasonable expenses of management, repair and other costs, of the nature of costs which have historically and customarily been accounted for as such, necessary to operate, maintain and preserve the Electric System in good repair and working order, including but not limited to, the cost of supply and tra nsmission of electric energy under long- term contracts or otherwise and the expenses of conducting the Electric System, but excluding depreciation. “Maintenance and Operating Expenses” includes all amounts required to be paid by the City under contract with a joint powers agency for purchase of capacity, energy, transmission capability or any other commodities or services in connection with the foregoing, which contract requires payments by the City to be made thereunder to be treated as Maintenance and Operating Expenses.

Certain of the City ’s obligations to joint powers agencies, including obligations with respect to bonds issued by such joint powers agencies, are payable by the City from the Light and Power Fund, prior to the Bonds and all Parity Obligations, as Maintenance and Operating Expenses. See TABLE 7 – “OUTSTANDING DEBT OF JOINT POWERS AGENCIES” herein.

The General Fund of the City is not liable for the payment of any Bonds, any premium thereon upon redemption prior to maturity or their interest, nor is the credit or taxing power of the City pledged for the payment of any Bonds, any premium thereon upon redemption prior to maturity or their interest. The Owner of any Bond shall not compel the exercise of the taxing power by the City or the forfeiture of any of its property. The principal of and interest on any Bonds and any premiums upon the redemption of any thereof prior to maturity are not a debt of the City nor a legal or equitable pledge, charge, lien or encumbrance upon any of its property or upon any of its income, receipts or revenues, except the Net Income and other funds, security or assets which are pledged to the payment of the Bonds, interest thereon and any premiums upon redemption pursuant to the Fiscal Agent Agreement.

Rate Covenant
The City has covenanted in the Fiscal Agent Agreement to fix the rates for services furnished by the Electric System so as to provide Gross Revenues at least sufficient to pay, as the same become due, the principal of and interest on the Bonds, including the Outstanding Bonds and Parity Obligations and all other obligations and indebtedness payable from the Light and Power Fund (including the payment of any amounts owing to any provider of any surety bond, insurance policy or letter of credit with respect to the Bonds or any Parity Obligations, which amounts are payable from the Light and Power Fund) or from any fund derived therefrom, and also the necessary Maintenance and Operating Expenses, and shall be so fixed that the Net Income of the Electric System will be at least equal to 1.10 times the amount necessary to pay principal and interest (including mandatory sinking account redemption payments) as the same become due on all Bonds, including the Outstanding Bonds and Parity Obligations.

The Light and Power Fund
The Charter establishes the Light and Power Fund and permits the establishment by ordinance of such funds as the City Council may deem necessary to facilitate the issuance and sale of the bonds or for the protection or security of the owners of the bonds.

9 Under the provisions of the Charter, all moneys and property received by the City in payment for electrical energy and for any service rendered in connection therewith, or from the sale, lease and other disposition of any property acquired with funds or property of the Electric System must be deposited in the Light and Power Fund.

The Charter further provides that disbursement may be made directly from the Light and Power Fund for the following purposes:
(a) the necessary or proper expenses of conducting the Electric System, the operation and maintenance of its works, plants and distributing systems; the acquisition and improvement of facilities; and the publishing of reports;
(b) the payment of interest and principal on bonds issued for the purposes of the Electric System; (c) the formation of surplus or reserves for the future needs of the Electric System and for unforeseen emergencies; and
(d) the repayment of advances made from other funds of the City.

In November 2020, voters in the City passed Measure P, which amended the Charter by confirming the General Fund Transfer (“GFT”) from the Light and Power Fund, limiting the maximum GFT, and simplifying the restrictions on the transfer. The maximum GFT was reduced from 16 percent to 12 percent of the electric utility’s gross income. Section 1408 of the Charter establishes the transfer amount at 12 percent of gross income, and provided that, “the amount to be transferred shall not exceed the net income of the electric works shown on the books of account of the power utility, after payment of the maintenance and operating expenses of such works, the expenses of conducting the power utility, depreciation, and the principal, interest, and premiums, if any, upon the redemption thereof, of electric works revenue bonds.” In March 2024, as certified in April 2024, voters in the City passed Measure R, updating the accounting method used to calculate the GFT in accordance with Generally Accepted Accounting Principles. Section 1408 was amended to rem ove the net income requirement with the following language remaining: "Notwithstanding anything herein contained, if the City Council at the time of or before the adoption of the budget shall determine that the transfer of such amount from the Light and Power Fund would be detrimental to the proper functioning and administration of the power utility during the budget year under consideration, the City Council may so find by resolution, and, in such event, no transfer of such amount shall be made within that fiscal year. If the City Council shall determine that the transfer of an amount less than twelve percent (12%) from the Light and Power Fund would not be detrimental to the proper functioning and administration of the power utility during the budget year under consideration, the City Council may so declare by resolution, and shall transfer a smaller amount.” The following table sets out the transfers from the Light and Power Fund to the City’s General Fund for the Fiscal Years 2018-19 through 2022-23 and the amount forecasted for the Fiscal Year 2023-24.

TABLE 1

TRANSFERS TO THE GENERAL FUND
(Dollar Amounts in Thousands)
Fiscal Year Transfer Amount
% of Prior Fiscal Year
Gross Income
2018-19 $17,609 10.00%
2019-20 17,315 10.00
2020-21 18,000 9.73
2021-22 18,000 10.03
2022-23 18,000 9.82
2023-24 (forecasted) 18,000 8.72
_______________________
Source: Finance and Administration Business Unit of PWP

10 In addition to the transfers authorized pursuant to Section 1408, the Charter provides that whenever the City Council determines that the surplus or reserve in the Light and Power Fund is in excess of reasonable future needs of the power utility, such excess may be appropriated for other municipal purposes, but only by ordinance approved by a two-thirds vote of the electors.

The Charter also provides that any surplus or reserves in the Light and Power Fund may be temporarily used for other municipal purposes if there are insufficient funds in the City Treasury to pay the current expenses of the general government of the City before the collection of taxes levied in any Fiscal Year. Should moneys from said fund be used pending the receipt of taxes, the amount so used shall be repaid not later than February 15 of the same Fiscal Year. However, the City has yet to exercise its rights under the above Charter provisions.

Parity Reserve Fund
The Fiscal Agent Agreement establishes the Parity Reserve Fund to be held by the City pursuant to the Charter. The Parity Reserve Fund is required to be maintained in an amount equal to the Reserve Fund Requirement so long as any Bonds or Parity Obligations secured by the Parity Reserve Fund remain Outstanding.

Upon the issuance of the 2024A Bonds, there will be on deposit in or credited to the Parity Reserve Fund an amount equal to the Reserve Fund Requirement ($_________ upon delivery of the 2024A Bonds).

The term “Reserve Fund Requirement” is defined in the Fiscal Agent Agreement to mean, as of any date of determination and excluding therefrom any Parity Obligations for which no reserve fund is to be maintained or for which a separate reserve fund is to be maintained, the least of (a) ten percent (10%) of the initial offering price to the public of each Series of Bonds and Parity Obligations to be secured by the Parity Reserve Fund as determined under the Code, or (b) the maximum Annual Debt Service on all Bonds and Parity Obligations to be secured by the Parity Reserve Fund, or (c) one hundred twenty-five percent (125%) of the Average Annual Debt Service on all Bonds and Parity Obligations to be secured by the Parity Reserve Fund, all as computed and determined by the City; provided, that such requirement (or any portion thereof) may be provided by the City delivering to the Fiscal Agent for credit to the Parity Reserve Fund one or more policies of municipal bond insurance or surety bonds issued by a municipal bond insurer if the obligations insured by such insurer have ratings at the time of issuance of such policy is in one of the two highest rating categories of Moody’s, Standard & Poor’s or Fitch or by a letter or credit issued by a bank or other institution if the obligations issued by such bank or other institution have ratings at the time of issuance of such letter of credit in one of the two highest rating categories of Moody’s, Standard & Poor’s or Fitch.

Currently, the Parity Reserve Fund is funded with cash or investments.

Amounts on deposit in or credited to the Parity Reserve Fund is pledged to, and shall be used solely for, the purpose of paying the principal of and interest on the Bonds, including the Outstanding Bonds, and Parity Obligations secured by the Parity Reserve Fund in the event that money in the Parity Obligation Payment Fund is insufficient therefor, and for that purpose money shall be transferred from the Parity Reserve Fund to the Parity Obligation Payment Fund. If and to the extent that the Parity Reserve Fund has been funded with a combination of cash and one or more surety bonds, insurance policies or letters of credit, except as provided below, all cash shall be used (including any investments purchased with such cash, which shall be liquidated and the proceeds thereof applied as required under the Fiscal Agent Agreement) prior to any drawing under a surety bond, insurance policy or letter of credit, and repayment of any amounts owing to any provider of such surety bond, insurance policy or letter of credit shall be made in accordance with the terms thereof prior to any replenishment of any such cash amounts. After first applying all cash and Investment Securities held in the Parity Reserve Fund to pay the principal of and interest on the Bonds and Parity Obligations secured by the Parity Reserve Fund when required, the City or the Fiscal Agent, as applicable shall, on a pro rata basis with respect to the portion of the Parity Reserve Fund held in the form of surety bonds, ins urance policies and letters of credit (calculated by reference to the maximum amounts of such surety bonds, insurance policies and letters of credit), draw under each surety bond, insurance policy or letter of credit issued with respect to the Parity Reserve Fund, in a timely manner and pursuant to the terms of such surety bonds, insurance policy or letter of credit to the extent necessary in order to obtain

11 sufficient funds on or prior to the date such funds are needed to pay the Bonds and Parity Obligations secured by the Parity Reserve Fund when due. Notwithstanding anything in the Fiscal Agent Agreement to the contrary, in the event a surety bond, insurance policy, letter of credit or cash deposit has been provided with respect to a specified Series of Bonds only, the Fiscal Agent shall draw on such insurance policy, surety bond or letter of credit in the amount equal to the pro rata amount of deficiency in the Parity Obligation Payment Fund allocable to such Series of Bonds at the same time that the Fiscal Agent applies any cash or Investment Securities held in the Parity Reserve Fund to the payment of the principal of and interest on any Bonds or Parity Obligations not so secured by such insurance policy, surety bond or letter of credit or with respect to which such cash deposit was not made.

All amounts due and owing any provider of any such surety bond, insurance policy or letter of credit shall be paid in accordance therewith prior to any discharge of the Fiscal Agent Agreement pursuant to the defeas ance of the Bonds. Amounts on deposit in the Parity Reserve Fund in excess of the Reserve Fund Requirement shall be withdrawn from the Parity Reserve Fund and transferred to the Light and Power Fund. Whenever money is transferred from the Parity Reserve Fund an equal amount of money shall be transferred to the Parity Reserve Fund from the first available money in the Light and Power Fund if required to bring the balance on deposit in the Parity Reserve Fund up to the Reserve Fund Requirement.

Additional Bonds
Upon the issuance of the 2024A Bonds, in addition to the 2024A Bonds, the City will have $104,810,000 of parity indebtedness outstanding, consisting of the Outstanding Bonds.

The Fiscal Agent Agreement provides that (except for bonds issued under Article XIV of the Charter, or otherwise, to refund Bonds or Parity Obligations, payable from the Light and Power Fund issued under Article XIV of t he Charter which may be issued at any time without meeting the test set forth below) no additional indebtedness of the City payable out of the Light and Power Fund on a parity with the Bonds and any Parity Obligations (collectively referred to in the Fiscal Agent Agreement as “parity indebtedness”) shall be created or incurred unless:
(1) The Net Income during any twelve (12) consecutive calendar months out of the immediately preceding eighteen (18) calendar month period, plus, at the option of the City, an y or all of the items designated in paragraphs (a) and (b) below, shall have amounted to at least equal to one hundred ten percent (110%) of the aggregate of the (i) amount of interest to accrue and (ii) payments of principal required to be made in that one of the Fiscal Years ending thereafter in which such aggregate will be the greatest on all Bonds and such Parity Obligations to be Outstanding immediately subsequent to the incurring of such additional parity indebtedness, as certified by a Certificate of the City; or
(2) The projected Net Income during the first complete Fiscal Year following issuance of such parity indebtedness when the improvements to the Electric System financed with the proceeds of the parity indebtedness shall be in operation, plus, at the option of the City, any or all of the items designated in paragraphs (a) and (b) below, shall have amounted to at least one hundred ten percent (110%) of the aggregate of the (i) amount of interest to accrue and (ii) payments of principal required t o be made in that one of the Fiscal Years ending thereafter in which such aggregate will be the greatest on all Bonds and such Parity Obligations to be Outstanding immediately subsequent to the incurring of such additional parity indebtedness, as certified by a Certificate of the City.

The items any or all of which may be added to such Net Income for the purpose of meeting either of the requirements set forth in clauses (1) or (2) above are the following:

12 (a) An allowance for any increase in Net Income (inc luding, without limitation, a reduction in Maintenance and Operating Expenses) which may arise from any additions to and extensions and improvements of the Electric System to be made or acquired with the proceeds of such additional parity indebtedness or with the proceeds of bonds previously issued, and also for Net Income from any such additions, extensions or improvements which have been made or acquired with moneys from any source but which, during all or any part of such Fiscal Year or such twelve consecutive calendar month period out of the immediately preceding eighteen calendar month period, were not in service, all in an amount equal to the estimated additional average annual Net Income (or estimated average annual reduction in Maintenance and Operating Expenses) to be derived from such additions, extensions or improvements for the first thirty- six month period in which each addition, extension or improvement is respectively to be in operation, all as shown by the Certificate of the City. (b) An allowance for earnings arising from any increase in the charges made for the use of the Electric System which has become effective prior to the incurring of such additional parity indebtedness but which, during all or any part of such Fiscal Year or such twelve consecutive calendar month period out of the immediately preceding eighteen calendar month period, was not in effect, in an amount equal to the amount by which the Net Income would have been increased if such increase in charges had been in effect during the whole of such Fiscal Year or such twelve consecutive calendar month period out of the immediately preceding eighteen (18) calendar month period, as shown by the Certificate of the City.

Nothing in the Fiscal Agent Agreement limits the ability of the City to issue or incur obligations which are junior or subordinate to the payment of the principal, premium, interest and reserve fund requirements for the Bonds and all Parity Obligations and which subordinated obligations are payable as to principal, premium, interest and reserve fund requirements, if any, only out of Net Income after the prior payment of all amounts then due and required to be paid or set aside under the Fiscal Agent Agreement from Net Income for principal, premium, interest and reserve fund requirements for the Bonds and all Parity Obligations, as the same become due and payable and at the times and in the manner as required in the Fiscal Agent Agreement or any documents providing for the issuance or incurrence of Parity Obligations. The C ity currently does not have any subordinate obligations outstanding.

All moneys held in the funds and accounts established pursuant to the Fiscal Agent Agreement will be invested solely in Investment Securities, which include:
(i) any permissible investments of funds of the City as stated in its current investment policy and to the extent then permitted by law;
(ii) a repurchase agreement with a state or nationally chartered bank or trust company or a national banking association or government bond dealer reporting to, trading with, and recognized as a primary dealer by the Federal Reserve Bank of New York, provided that the following conditions are satisfied:
(1) The agreement is secured by any direct obligations of the United States of America (including obligations issued or held in book-entry form on the books of the United States Department of the Treasury) and obligations, the payment and principal of and interest on which are directly or indirectly guaranteed by the United States of America;
(2) The underlying securities are required by the repurchase agreement to be held by a bank, trust company, or primary dealer having a combined capital and surplus of at least one hundred million dollars and which is independent of the issuer of the repurchase agreement; and (3) The underlying securities are maintained at a market value, as determined on a market - to-market basis calculated at least weekly, of not less than 104% of the amount so invested; and

13 (iii) an investment agreement or guaranteed investment con tract with, or guaranteed by, a financial institution the long-term unsecured obligations of which are rated in the top two rating categories by Moody’s and Standard & Poor’s at the time of initial investment.

Investment Securities purchased as an investment of moneys in the Parity Reserve Fund are currently limited to maturities not extending beyond five years. Pursuant to the Eighth Supplement, upon the earlier to occur of: (i) the first date upon which the City has filed with the Fiscal Agent the written consent of a majority of the aggregate principal amount of Bond Obligations of the Bonds Outstanding as of the effective date of the Eighth Supplement (but excluding the 2013A Bonds for the purposes of such calculation), or any consent in lieu thereof in accordance with the Fiscal Agent Agreement has been obtained, or (ii) the first date upon which all of the Outstanding 2010A Bonds and 2012A Bonds have been defeased, paid or discharged in accordance with their terms and shall no longer be Outstanding fo r purposes of the Fiscal Agent Agreement, Investment Securities purchased as an investment of moneys in the Parity Reserve Fund may not have maturities extending beyond 10 years.

Limitations on Remedies
The ability of the City to comply with its covenants under the Fiscal Agent Agreement and to generate Net Income of the Electric System sufficient to pay principal of and interest on the 2024A Bonds may be adversely affected by actions and events outside of the control of the City. Furthermore, any remedies available to the owners of the 2024A Bonds upon the occurrence of an event of default are in many respects dependent upon judicial actions which are often subject to discretion and delay and could prove both expensive and time consuming to obtain. The rights of the Owners of the 2024A Bonds are subject to the limitations on legal remedies against cities and other public agencies in the State. Additionally, enforceability of the rights and remedies of the Owners of the 2024A Bonds, and the obligations incurred by the City, may become subject to the following: the federal Bankruptcy Code and applicable bankruptcy, insolvency, reorganization, moratorium or similar laws relating to or affecting the enforcement of creditor’s rights generally, now or hereafter in effect; equity principles which may limit the specific enforcement under State law of certain remedies; the exercise by the United States of America of the powers delegated to it by the Constitution and the reasonable and necessary exercise, in certain exceptional situations, of the police powers inherent in the sovereignty of the State and its governmental bodies in the interest of serving a significant and legitimate public purpose. Bankruptcy proceedings, or the exercise of powers by the federal or State government, if initiated, could subject the Owners of the 2024A Bonds to judicial discretion and interpretation of their rights in bankruptcy or otherwise, and consequently may entail risks of delay, limitation or modification of their rights.

PASADENA WATER AND POWER
Organization
The City is a charter city of the State. Under the provisions of the California Constitution and Article XIV of the Charter, the City owns and operates both water and electric public utilities for the benefit of its residential and business community. PWP is under the management and control of the City Manager, subject to the powers and duties vested in the City Council, and is supervised by the General Manager who is responsible for design, construction, maintenance and operation of the water and electric utilities. PWP is responsible for the Electric System and the City ’s water system (the “Water System”). The 2024A Bonds are not secured by or payable from revenues of the Water System.

Within the Electric System and the Water System divisions, PWP is organized into six separate business units. This structure allows for a higher level of accountability as well as the creation of individual cost centers and profit centers. This information is used for tracking costs and supplying detailed information in rate design decisions. These business units are briefly described as follows:

14 General Manager’s Office-Customer Relations & Legislation Business Unit – This unit is part of th e General Manager’s Office and is responsible for residential and commercial energy efficiency programs, drought and water conservation awareness and outreach, state and federal legislative/regulatory advocacy and other customer relations programs. This unit is responsible for strategic planning and long-term resources.

Finance and Administration Business Unit – This unit develops and executes PWP ’s overall financial strategy and ensures its financial integrity. This unit is responsible for the financial resources of PWP and for providing relevant information to the operating units for decision making purposes. This unit plans and oversees the financial aspects, administrative support functions and all cross -functional operations and systems for PWP.

The responsibilities of this unit include the operating budget, capital budget and financing, financial analysis and planning, financial management, administration, risk management, and materials management.

Customer Service and Technology Business Unit – This unit develops a range of solutions and tools aimed at enhancing customer support and satisfaction through the integration of technology. The responsibilities of this unit include billing, call center, meter reading and customer care services, informatio n systems and technology management. This group was formed in September 2023.

Power Supply Business Unit – This unit is responsible for effectively managing PWP’s energy portfolio, including strategic long-term resource power generation, long- term power co ntracts, short-term electric energy and ancillary services transactions and natural gas procurement to provide competitively-priced energy to PWP’s electric customers. This unit is also responsible for energy scheduling to ensure reliable delivery of elec tricity and the operation of the City’s generating units.

Power Delivery Business Unit – This unit is responsible for the design, construction, operation and maintenance of the local power distribution system to provide the safe and reliable delivery of el ectricity, load dispatch operations and is responsible for implementing the Power Delivery Master Plan. See – “THE ELECTRIC SYSTEM OF PWP - Funding of Capital Improvements” for a description of the Power Delivery Master Plan.

Water Delivery Business Unit – This unit is responsible for the procurement, production and delivery of water as well as the planning, design and construction of the local water distribution system. This unit also operates and maintains the local water supply resources and distribution system.

Management
The following are biographical summaries of PWP’s senior management for the Electric System:

DAVID REYES, Acting General Manager. David Reyes joined the City in 2012 as the Planning and Community Development Department’s Zoning Administrator. In 2013, he was promoted to Deputy Director and in 2016 served as the Department Director. In 2023, Mr. Reyes was appointed Assistant City Manager after serving in that role as interim for nine months. Mr. Reyes has more than 20 years of experience in the public sector. Prior to joining the City , he worked in a range of positions for the planning departments at the cities of Malibu, Santa Monica and Beverly Hills. He holds a bachelor ’s degree in urban studies and planning from California State University, Northridge.

LYNNE CHAIMOWITZ , Assistant General Manager – Finance and Administration. Lynne Chaimowitz was most recently with the Mojave Water Agency where she served as the Chief Financial Officer (“CFO”). Prior to becoming CFO, Ms. Chaimowitz served as the Budget and Finance Supervisor for the City of Ann Arbor, Public Services where she managed a comprehensive rate study and provided leadership in financial modeling, financing reporting and capital planning. Additionally, she is a C ertified Public Finance Officer and has dedicated her professional career to organizational financial excellence with extensive experience in water utilities. She earned an Environmental Program undergraduate degree from the University of Michigan, and a graduate degree in Accounting from Eastern Michigan University.

15 KELLY NGUYEN, Assistant General Manager - Power Supply. Kelly Nguyen joined PWP in 2019 and has 26 years of industry experience, previously serving as the General Manager of Vernon Public Uti lities.

Prior to that, she worked at Southern California Public Power Authority (“SCPPA”), Anaheim Public Utilities and the California Power Exchange. She has served in various capacities with a number of committees and associations including Board Member and Vice President of SCPPA, member of Western Systems Power Pool (“WSPP”) Executive Committee , Western Electricity Coordinating Council Committees , California Utilities Emergency Association Alternate Board, California Municipal Utilities Association Board, and American Public Power Association.

Ms. Nguyen holds a Bachelor of Science in Business Administration from California State University, Los Angeles and has specialized training in energy system procedures, protocols and utility compliance policies through the Western Electric Coordinating Council, North America Energy Reliability Corporation, and training in market operations and Cap & Trade through California Independent System Operator (“CAISO”).

VAROOJAN AVEDIAN, Acting Assistant General Manager - Power Delivery. Varoojan Avedian assumed the role of Power Engineering Manager at PWP in 2016 and presently functions as the Acting Assistant General Manager for the Power Delivery Division. He previously held the position of Interim Assistant General Manager for the Power Delivery Division in 2017- 2018. With nearly two decades of experience in the public sector, Mr. Avedian served in various capacities at the City of Glendale Water & Power before joining PWP. Mr.

Avedian holds a Master ’s of Sc ience degree in electrical engineering from California State University -Los Angeles and is a State registered professional electrical engineer.

JEREMY MARQUETTE, Assistant General Manager – Customer Service and Technology. Jeremy Marquette joined PWP in April 2019 and led the department’s Information/Automation Technology group through many major projects, including the April 2022 deployment of a new Customer Information/Utility Billing System.

He has more than 20 years of experience in the utility indust ry and was recently promoted to Assistant General Manager of Customer Service and Technology at PWP after serving over 10 months in an acting capacity as Assistant General Manager for the Finance, Administration, and Customer Service Business Unit. Prior to joining PWP, Mr. Marquette worked for Long Beach Utilities, serving in various capacities in customer service, finance and information technology.

JENNIFER GUESS MAYO, Division Head – Customer Relations and Legislation. Ms. Guess Mayo joined PWP in May 2014 and has over 22 years of experience in the energy, water and sustainability sector. Prior to her tenure with PWP, Ms. Guess Mayo worked for the Upper San Gabriel Valley Municipal Water District and in the private sector. She obtained her undergraduate degree in communication, with a public relations emphasis from California State Polytechnic University, Pomona and holds a master’s degree in public administration from California State University, Northridge.

Employees
For Fiscal Year 2022-23, 419 City employees were assigned to PWP, including 280 full-time equivalent employees for the Electric System. The Electric System employees represent approximately 12% of the full-time City employees. Most Electric System employees are represented either by th e International Brotherhood of Electrical Workers, the International Union of Operating Engineers, the American Federation of State, County and Municipal Employees, the Laborers ’ International Union of North America or the Pasadena Management Association in all matters pertaining to wages, benefits and working conditions. The current agreements with these unions and/or associations, which are in the form of either a contract or a memorandum of understanding, will expire through 2027. The City has no history of work interruption by employees maintaining the Electric System. See APPENDIX A – “THE CITY OF PASADENA – Employee Relations.” The Electric System ’s permanent employees are all covered by the California Public Employees Retirement System (“CalPERS”) with respect to pension benefits. CalPERS is an agent multiple -employer plan public employee retirement system which acts as a common investment and administrative agent for participating

16 public employers within the State of California. The plan provides retirement and disability benefits, annual cost- of-living adjustments and death benefits to plan members and their beneficiaries. CalPERS issues a separate publicly available financial report that includes financial statements and required supplemental information of participating public entities within the State of California. Copies of the CalPERS annual financial report may be obtained from the CalPERS Executive Office, Lincoln Plaza Complex, 400 Q Street, Sacramento, California 95811, or at www.calpers.ca.gov.

CalPERS requires employer contribution rates for all public employers be determined on an annual basis by the actuary and shall be effective on the July 1 following notice of a change in the rate. Funding contribution for the City’s Miscellaneous Plan (“Plan”) (which include all Electric System employees) is 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 the difference between the actuarially determined rate and the contribution rate of employees.

In accordance with Governmental Accounting Standards Board (“GASB”) 68, Accounting and Financial Reporting for Pensions, the City’s net pension liability for the Plan is measured as the total pension liability, less the pension plan’s fiduciary net position. The net pension liability of the Plan is mea sured as of June 30, 2022, using an annual actuarial valuation as of June 30, 2021, rolled forward to June 30, 2022 using standard update procedures. The actuarial methods and assumptions used to determine the total pension liability include entry age normal cost method in accordance with the requirements of GASB 68, an inflation rate of 2.50%, salary increase by entry age and service, an investment rate of return (net of administrative expenses) of 7.00%, and a mortality rate table derived using CalPERS ’ membership data for all funds. The discount rate used to measure the total pension liability was 6.90%. All other actuarial assumptions used in the June 30, 2022 valuation were based on the results of the December 2017 experience study report based on CalPERS demographic data period from 1997 to 2015, including updates to salary increase, mortality and retirement rates.

Under GASB 68, gains and losses related to changes in total pension liability and fiduciary net position are recognized in pension expense systematically over time. The first amortized amounts are recognized in pension expense for the year the gain or loss occurs. The remaining amounts are categorized as deferred outflows and deferred inflows of resources related to pensions and are t o be recognized in future pension expense. The difference between projected and actual earnings on the Plan ’s investments uses a 5 -year straight -line amortization, while all other amounts use straight-line amortization over the expected average remaining service lifetime ( “EARSL”) of all members that are provided with benefits (active, inactive, and retired) as of the beginning of the measurement period. The EARSL for the measurement period ending June 30, 2022 is 3.4 years for the Plan, which was obtained by dividing the total service years of 14,755 (the sum of remaining service lifetimes of the active employees) by 4,330 (the total number of participants: active, inactive, and retired). Inactive employees and retirees have remaining service lifetimes equal to 0.

As of the start of the measurement period July 1, 2021, the net pension liability of the Plan is $178,024,859. For the measurement period ending June 30, 2022, the City has a net change of $162,650,045 for the Plan, which is the total pension liability of $64,145,723 minus the plan fiduciary net position of $98,504,322, yielding to the ending net pension liability balance of $340,674,904. The deferred outflows and deferred inflows of the resources related to the Plan as of June 30, 2022 are $122,509,780 and $10,719,484, respectively.

The Electric System’s contributions represent a pro rata share of the City ’s contribution, including the employees’ contribution that is paid by the Light and Power Fund, which is based on CalPERS ’ actuarial determination as of July 1 of the current Fiscal Year. CalPERS does not provide data to participating organizations in such a manner so as to facilitate separate disclosure for the Light and Power Fund’ s share of the actuarial computed pension benefit obligation, the plan’s net assets available for benefit obligation and the plan’s net assets available for benefits. The Electric System employees’ contribution represents approximately 17.63% of the Plan’s contribution.

17 Other than the pension benefits from the applicable retirement system, the City does not provide medical or other post-retirement benefits to its employees beyond the option to continue receiving health insurance benefits at the City’s monthly rates, paid by the retired employees.

The City provides a direct subsidy to retirees of the City who are members of CalPERS or the Pasadena Fire and Police Pension System. Benefit provisions are established and a mended through negotiations between the City and the respective unions. Two levels of subsidies, full minimum required contribution or partial, are provided to eligible retirees electing to continue medical insurance from CalPERS under the Public Employee s’ Medical and Hospital Care Act.

The City’s current contribution requirements have been established at the individual retiree levels of $151.00 or $128.35 per month depending on bargaining unit membership and policy enacted by CalPERS pursuant to State L aw. These minimum requirements are established by CalPERS and adjusted annually. The City has historically funded these post -retirement health care benefits on a “pay-as-you-go” basis. For the Fiscal Year ended June 30, 2023, the City’s payments totaled $2,996,602 for actual benefits provided. The Electric System is allocated its portion of the payments. As of June 30, 2023, the City’ s unfunded actuarial accrued other post- employment benefits (“OPEB”) liability for the citywide post-retirement healthcare benefits (including the portion allocable to Electric System employees) was approximately $75,289,782, of which approximately $8,868,474 or

11.78% represent the share of Light and Power Fund.

See APPENDIX A – “THE CITY OF PASADENA – Employee Relations” and “ – Post-Retirement Medical Benefits.” Further information regarding the City’ s participation in CalPERS and OPEB may also be found in the City’s Comprehensive Annual Financial Report.

THE ELECTRIC SYSTEM OF PWP
General
The Electric System of PWP began g enerating its own electric energy and distributing power in 1906.

Electric service was previously supplied by Edison Electric Company, predecessor to Southern California Edison Company (“SCE”). PWP has continued to expand its electric distribution system to meet the demands of its residential, commercial, industrial and public sector customers. The Electric System provides service to virtually all of the electric customers within the limits of the City. For the Fiscal Year ended June 30, 2023, the customer base was comprised of 57,769 residential customers, 8,575 commercial and industrial customers, 5 street lighting and traffic signals customers, and 6 wholesale customers. The service area is approximately 23 square miles, with a current estimated population of approximately 137,000.

The Electric System includes generation, transmission and distribution facilities. The City also purchases power and transmission service mainly from Intermountain Power Agency ( “IPA”) and SCPPA. The Electric System’s current resource mix includes local simple and combined cycle gas turbines (Glenarm Power Plant) , small hydroelectric (Azusa Hydroelectric Plant) and long- term purchase contracts (remote generation) from a variety of sources including hydroelectric, coal and nuclear generating units and a variety of renewable energy resources including wind, solar, geothermal and biogas projects. A portion of the Electric System’s energy supply is purchased when it is more economical, on the wholesale hourly, daily and month- ahead spot markets. See “– Purchased Power – Bilateral (Spot Market) Energy Purchases.” Legislation affecting the electric utility industry is routinely introduced or enacted by the federal government and the California Legislature. In recent years, the enacted bills primarily regulate greenhouse gas emissions and provide for greater investment in energy- efficiency and environmentally friendl y generation alternatives through more stringent renewable resource portfolio standards. PWP ’s generation and transmission operating and long- term plans are developed and executed in accordance with existing law and in response to pending legislation. Se e “DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS” and “OTHER FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY.”

18 Energy Integrated Resource Plan
Senate Bill (“SB”) 350 (2015) requires that publicly owned utilities ( “POU”) prepare and submit to the California Energy Commission (“CEC”) an Integrated Resource Plan (“IRP”) at least once every five years. An IRP is a power system planning document that describes how a utility plans to meet its energy and capacity resource needs, policy goals, physical and operational constraints, and other utility priorities. It is a strategic plan that provides overall direction for future policies, programs, and resource procurement decision, and is developed through a robust stakeholder and outreach effort to ensure that long- term planning is aligned with community priorities. In addition to the mandated IRPs, which PWP has published since 2009, voluntary updates are also developed, as needed, in order to incorporate relevant changes in laws, regulations, market conditions, and community preferences. Each IRP provides a foundation for, and informs, subsequent IRPs.

Assembly Bill (“AB”) 32 (2006), the Global Warming Solutions Act of 2006 (“GWSA”), initiated almost two decades of increasingly ambitious laws and regulations aimed at reducing statewide greenhouse gas (“GHG”) emissions. California’s 2022 Scoping Plan for Carbon Neutrality, which incorporates AB 1279 (2022), sets a goal to reduce overall emissions by 85% compared to 1990 levels as soon as possible, but no later than 2045. The electricity sector contributes to this goal mainly through the Renewables Portfolio Standard ( “RPS”) Program, which requires that renewable and zero-carbon resources meet 100% of retail sales of electricity to end users by 2045, as mandated by SB 100 (2018). In 2022, SB 1020 added interim targets after 2030 to drive faster progress toward achieving the 2045 target.

PWP’s 2018 IRP, one of the first SB 100- compliant IRPs in California, incorporates the City Council ’s decision to exclude fossil fuel energy resources as considerations for any new long-term contracts or acquisitions.

Accordingly, the decision was also made to terminate PWP’s interest in the Intermountain Power Project (“IPP”) coal contract, effective in 2027, and will is expected to contribute to PWP’s decarbonization efforts.

In December 2023, the City Council approved the 2023 IRP. The 2023 IRP incorporates City Resolution No. 9977, adopted in January 2023, and sets a goal to source 100% of the City ’s electricity from zero -carbon sources by 2030 while optimizing for affordability, rate equity, stability, and reliability of electricity. The 2023 IRP also incorporates formal waypoints in 2026 and 2028 in order to evaluate emerging technologies that might help achieve goals for incorpor ation in the 2028 IRP. Implementation will involve various studies and policy considerations starting with the completion of an Optimized Strategic Plan during the Fiscal Year of 2025.

Insurance
The insurable property and facilities of the Electric System are covered under the City’s general insurance policies. Additional liability coverage for the City ’s generation facilities is provided by a separate Power Plant Boiler and Machinery Policy. The City does not carry earthquake insurance on the property and facilities of the Electric System. For additional information on the City ’s insurance, see APPENDIX A – “THE CITY OF PASADENA – Insurance.”
Power Supply Resources
The Electric System’s resource mix includes local steam and gas turbines, a hydroelectric plant and long- term purchase contracts from a variety of sources including hydroelectric, gas-fired, coal and nuclear generating units and a variety of renewable energy resources including wind, solar, geothermal and biogas projects. In recent years, PWP has developed its resource mix in response to regional power shortages, energy price volatility, and environmental regulations, including stricter emissions control requirements adopted by the South Coast Air Quality Management District. The Electric System increased its power production for several consecutive years primarily as a result of increased energy sales to the CAISO when called upon to meet regional demand.

19 The following table sets forth the total power generated and purchased during the five Fiscal Years shown.

TABLE 2
TOTAL POWER GENERATED AND PURCHASED (MWh)
Fiscal Year Ended June 30
2019 2020 2021 2022 2023
Generated 67,244 51,632 31,939 25,619 51,269
Purchased 1,033,370 1,056,742 991,887 993,051 1,053,335 Total Supply 1,100,614 1,108,374 1,023,826 1,018,670 1,104,604 Wholesale Sales (26,645) (68,513) (32,496) (145) (151) Net System Load 1,073,969 1,039,861 991,330 1,018,525 1,104,453 System Peak Demand (MW) 302 275 297 258 319
_______________________
Source: Finance and Administration Business Unit of PWP. [Remainder of page intentionally left blank.]

20 The following table sets forth information concerning the City’ s power supply resources and the energy supplied by each resource during the Fiscal Year ended June 30, 2023.

TABLE 3

POWER SUPPLY RESOURCES
Source
Actual Energy
(GWh)(1)
Percent
of Total Energy
Pasadena Owned Generating Facilities:

Combustion Turbines (Glenarm Power Plant) 51.3 4.6%
Joint Power Agency/Remote Ownership Interests:

Intermountain Power Project (IPP) 260.8 23.6%
Palo Verde Nuclear Gen. Station (SCPPA) 82.0 7.4%
Magnolia Power Project (SCPPA) 89.0 8.1%
Renewable Resources 223.9 20.3%
Purchased Power(2)
Market 360.1 32.5%
Hoover Project 37.5 3.4%
Total 1,104.6 99.9%
Wholesale Sales 0.2 0.1%
Net System Load 1,104.4 100.0%

(1) Preliminary data; GWh provided during the twelve month period ended June 30, 2023. (2) Entitlements, firm allocations and contract amounts.

Source: Finance and Administration Business Unit of PWP.

City-Owned Generating Facilities
PWP owns and operates the Glenarm Power Plant, which is located in the southwest corner of the City and includes five gas- fired combustion turbines and the Azusa Hydroelectric Plant, a small hydro unit that is interconnected to the SCE power distribution system.

Glenarm Power Plant
The Glenarm Power Plant units operating under a CAISO Participating Generator Agreement provide ancillary services and energy to the CAISO market. See “ THE ELECTRIC SYSTEM OF PWP - Inter-Utility Sales Transactions – CAISO – Participating Generator Agreement” herein. When imports are limited due to tie- line outages, or when loads reach the import capacity limit of 290 MW, at least one unit is put online for reliability purposes. The average capacity factory for the Glenarm Power Plant has been less than 1% over the last five years. The value provided by these units is in their “optionality,” which refers to the ability to quickly start and adjust operating levels to changing market and load conditions.

Gas Turbines (“GT”) 1, 2, 3 and 4 are simple cycle natural gas-fired combustion turbines that operate as peaking units. GT 1 and 2, identical units built in 1975, have respective net rated CAISO output of 22.13 MW and 22.38 MW, respectively. GT 3 and 4 have net rated CAISO output of 44.83 MW and 42.42 MW, respectively.

GT 5 is a one -on-one (“1x1”) combined-cycle gas turbine that can operate in either combined -cycle or simple- cycle mode and serves as a peaking unit. The unit has a permitted gross capacity of 65.81 MW.

Azusa Hydroelectric Plant
The Azusa Hydroelectric Plant is a 3 MW hydroelectric plant located at the mouth of the Azusa Canyon in the City of Azusa that consists of one unit interconnected to the SCE power distribution system. The energy is accumulated in a bank as it is generated and delivered to PWP in blocks up to 15 MW. Due to a lack of water resulting from persistent drought conditions and a sediment removal project by the Los Angeles County Flood Control at the upstream dam, the energy produced by the plant has not been significant in the last ten years.

21 Joint Powers Agency Generation and Fuel Resources/Remote Ownership Interests General
The City purchases power from the coal -fired IPP, which is owned and operated by the I PA, a political subdivision of the State of Utah. In addition, the City and other public agencies in Southern California are members of SCPPA, a joint powers agency created for planning, financing, developing, acquiring, constructing, operating and mainta ining electric generating and transmission projects for participation by some or all of its members. The City is a participant in the SCPPA portion of the Palo Verde Nuclear Generating Station (“PVNGS”), in the SCPPA Magnolia Power Project, in the SCPPA Milford Wind Corridor Phase I Project and in connection with its fuel supply, the SCPPA Prepaid Natural Gas Project and the SCPPA Natural Gas Project. In most cases, staff unrelated to the City ’s bargaining units provide operating, maintenance, engineering, energy management and administrative services for such projects. Labor and related costs are charged to the related joint powers agency or other public agency. The City is informed that labor agreements are in place with each respective bargaining group but cannot give any assurances as to future agreements or the status of negotiations.

Each of these resources is briefly described below.

Intermountain Power Agency
Certain information under this subheading “Intermountain Power Agency” regarding the IPA, the IPP and its operations has been obtained from the IPA and sources that the City believes to be reliable, but the City takes no responsibility for the accuracy of such information obtained from sources other than the City.

IPA Intermountain Power Project Interest. The IPA has constructed and placed into commercial operation the IPP. The City has entered into certain power purchase contracts with the IPA and others to purchase certain entitlements of IPP and related facilities. The IPP consists of (a) a two unit, 1,800 MW net coal-fired, steam electric generation station and a switchyard located near Delta, Utah; (b) the Southern Transmission System (see “– Transmission Resources” below); (c) two 50- mile 345 kilovolt alternate current (“kV AC”) transmission lines from the generation station to a switchyard in the vicinity of Mona, Utah and a 144-mile 230 kV AC transmission line from the generation station to a switchyard near Ely, Nevada (collectively, the “Northern Transmission System”); (d) a railcar service center; (e) a microwave communications system; and (f) certain water rights and coal supplies. There are 36 utilities (collectively, the “IPP Purchasers”) that purchase the output of the IPP generating station, consisting of the City, and the California cities of Los Angeles, Anaheim, Burbank, Glendale and Riverside (the “ IPP California Participants”), PacifiCorp (which merged with Scottish Power), as successor to the obligations of Utah Power & Light Company, 23 Utah municipal members of IPA and six rural electric cooperatives serving loads in the States of Utah, Arizona, Colorado, Nevada and Wyoming. Pursuant to a Construction Management and Operation Agreement between IPA and Los Angeles Department of Water and Power (“LADWP”), IPA appointed LA DWP as project manager and operating agent responsible for, among other things, administering, operating and maintaining the IPP. The facilities of the IPP have been in commercial operation since May 1, 1987. The City has two separate contracts with the IPA and certain Utah participants (the power sales entitlement contract and the excess sales contract, respectively, as further described below) which currently provide the City with a 107 MW (5.9%) entitlement in the facility. Approximately 250-400 gigawatt hour (“GWh”) of energy are delivered to the City from IPP each year. See “TABLE 3 – POWER SUPPLY RESOURCES.”
Transmission of the output from IPP to the City and the other IPP California Participants is provided by the Southern Transmission System. See “– Transmission Resources” below.

IPP has been financed entirely with debt issued by IPA, of which approximately $232 million principal amount was outstanding as of June 30, 2023, with a final maturity date of June 30, 2027. Debt service, net of projected investment earnings, constitutes in excess of 50% of IPA’s total annual costs of owning, operating and maintaining IPP and is the major factor in IPP ’s power and energy costs. As of

22 June 30, 2023, PWP is responsible for approximately $13.3 million principal amount or 5.9% of the IPA IPP outstanding debt. See TABLE 7 – “ OUTSTANDING DEBT OF JOINT POWERS AGENCIES ” herein for details of the City’s share of this debt.

Details of the contracts relating to the IPP are as follows:

Power Sales Entitleme nt. The City has contracted with IPA to purchase a 79 MW (4.409%) entitlement to the power of the IPP plant. This contract obligates the City to pay its proportional share of the plant costs (including debt and other fixed expenses), regardless of the amount of energy scheduled to the City, for the life of the IPP bonds. Originally, the City had an entitlement contract with IPA and a layoff which it entered into on February 1, 1983 with Scottish Power (now PacifiCorp), whereby the City purchased a 16 MW share from Scottish Power, which allocation was subsequently increased to 18 MW.

Thereafter, in 1991, the layoff contract and the power sales entitlement contract with IPA were combined into one contract resulting in the City’s current 79 MW capacity entitlement. The term of the combined contract extends until all bonds issued by IPA to finance the IPP are retired. PacifiCorp is no longer an IPP power purchaser, its shares having been transferred to LADWP.

Excess Sales Contract. T
he City and the cities of Burbank and Glendale and LADWP contracted with 27 sellers (the “Utah Participants”) and IPA (acting as agent for the sellers) to purchase an entitlement of the IPP plant which was deemed in excess of the sellers’ needs. The City’s current share of the excess is 29 MW (1.5910%). This contract also provides for access to the Northern Transmission System, which was built with IPA funds in order to deliver power from the IPP to the Utah Participants. The term of this contract extends until the IPA bonds are defeased or the sellers’ load requirements meet certain specified conditions; however, the Utah Participants have the unilateral right to recall their original entitlements at any time.

IPP Coal Requirement. IPA possesses coal supply agreements to fulfill the supply requirement of approximately 4.0 million tons per year. The coal is purchased under a portfolio of fixed prices contracts that are of short and long- term in duration. However, as described below, supply chain issue s resulting from the loss of coal production in the region and transportation challenges have reduced coal supply beginning in the later months of 2021 and are expected to impact coal supply for the remaining life of the coal plant. The largest coal producer in Utah experienced a fire in September 2022 and was planning to return to mining in 2024. However, in November of 2023, it was announced that the mine is closing indefinitely. The loss of the largest mine, combined with the logistics challenges in Utah , has dramatically reduced supply in the region including to IPA. As a whole production remains challenging for the remaining active mines in Utah.

The recent cost of coal delivered to the Intermountain Generating Station is substantially lower than current market prices for the region. However, IPA expects that the costs to fulfill IPP’s coal demand will increase due to the scarcity of coal in the Western United States, if IPA is able to secure any additional coal as a replacement for the loss of sources under contract.

Transportation of coal to the Intermountain Generating Station is provided primarily by rail under agreements between IPA and the Union Pacific Railroad company, and the coal is transported, in part, in IPA-owned railcars. Coal is also transported to IPP, to some extent, in commercial trucks. Both rail service and trucking services have suffered greatly due to a lack of human resources. Neither network is capable of supporting industrial demand; and IPA, like all coal -fired utilities in the United States, has seen large system failures in the transportation system.

Historically, IPP was able to maintain a minimum of 60 days of coal in inventory in the event of a coal supply disruption. However, due to the recent challenges in the coal supply chain, the number of days of coal in inventory has periodically declined below that level. As of the mid- December 2023, IPP maintained 39 days of coal in inventory. LADWP has operational flexibility with respect to its use of

23 IPP; however, the supply chain issues referenced above are likely to impact the operations of IPP and may constrain LADWP’s ability to utilize such resources.

Intermountain Generating Station upon termination of the IPP Contract . The current power purchase contracts with the IPA are in effect until June 15, 2027. In order to preserve the benefits of IPP, the IPA Board of Directors issued the Second Amendatory Power Sales Contract, which would supersede the current power sales contracts and allow the plant to replace the coal units with combined cycle natural gas units by 2025. The City Council authorized PWP to enter into a renewal c ontract with IPA for a reduced share (up to 40 MW) in the new gas -fired project, with the understanding that the City would have an option to terminate its participation in the gas-fired renewal project in 2019.

On November 29, 2018, the City officially exercised its option to withdraw from the renewal contract with IPA. As a result, the City ’s entitlement under the IPP contract expires on June 15, 2027.

Decommissioning costs associated with the generating units have not been determined at this time, and the City’s potential liability is unknown. The allocation of decommissioning costs to IPP Purchasers (including the City) may vary based on the commercial operation date of the renewal project, potential financing options for decommissioning costs as part of the renewal project and the amortization schedule for the decommissioning costs.

Southern California Public Power Authority (SCPPA)
Certain of the information under this subheading “Southern California Public Power Authority” regarding SCPPA, the SCPPA projects in which the City participates and their operations has been obtained from SCPPA and sources that the City believes to be reliable, but the City takes no responsibility for the accuracy of such information obtained from sources other than the City.

SCPPA Palo Verde Nuclear Generating Station Interest . The City has contracted with SCPPA for a 9.9 MW (4.4%) entitlement of 225 MW SCPPA PVNGS Interest. This resource provides the City with approximately 75-85 GWh of baseload energy annually. The City has entered into a power sales agreement with SCPPA which obligates the City to pay the cost of its share of capacity and energy on a “take-or-pay” basis. SCPPA has issued bonds for PVNGS of which the City paid off its share of principal balance due as of December 1, 2018. SCPPA has undertaken certain actions, including collections of amounts in excess of operating and maintenance expenses and current debt service on its bonds for PVNGS to reduce the cost of power from this project. See “– Indebtedness and Joint Agency Obligations” below and TABLE 7 – “OUTSTANDING DEBT OF JOINT POWERS AGENCIES.” The City, as well as the Cities of Azusa, Banning, Burbank, Colton, Glendale, Los Angeles, Riverside and Vernon and the Imperial Irrigation District are PVNGS project participants.

The “SCPPA PVNGS Interest” consists of a 5.91% ownership interest in the PVNGS, Units 1, 2 and 3, and certain associated facilities and contractual rights relating thereto, a 5.44% ownership interest in the Arizona Nuclear Power Project High Voltage Switchyard and contractual rights relating thereto and a 6.55% share of the rights to use certain portions of the Arizona Nuclear Power Project Valley Transmission System. PVNGS is located on an approximately 4,000- acre site about 50 miles west of Phoenix, Arizona. PVNGS consists of three nuclear electric generating units (numbered 1, 2 and 3), with a design electrical rating of 1,333 MWs (unit 1), 1,336 MWs (unit 2) and 1,334 MWs (unit 3) and a dependable capacity of 1,311 MWs (unit 1), 1,314 MWs (unit 2) and 1,312 MWs (unit 3). PVNGS ’s combined design capacity is 4,003 MWs and its combined dependable capacity is 3,937 MWs. PVNGS Units 1, 2 and 3 achieved firm operation in January 1986, September 1986 and December 1987, respectively. Each PVNGS generating unit has been operating under 40- year Full -Power Operating Licenses granted by the Nuclear Regulatory Commission (the “NRC”). In April 2011, the NRC approved PVNGS’s license renewal application, allowing the three units to extend operation for an additional 20 years until 2045, 2046 and 2047, respectively. Arizona Public Service Company is the operating agent

24 for PVNGS. Transmi ssion is accomplished through agreements with Salt River Project Agricultural Improvement and Power District (“Salt River Project”), LADWP and SCE.

The owners of PVNGS have created external trusts in accordance with the PVNGS participation agreement and NRC requirements to fund the costs of decommissioning PVNGS. SCPPA’s direct share of costs is $161.9 million, of which the City’s portion is $7.1 million or 4.4%. Under the current funding plan, which was established based on the license expiration in 2047, the City estimates that its share of the decommissioning costs are fully funded. Such estimates assume 7% per annum in future investment returns and a 5% per annum cost escalation factor. No assurance or guarantee can be given that investment earnings will fully fund the City ’s remaining decommissioning obligations at current estimated costs or that the decommissioning costs will not exceed current estimates.

The NRC has broad authority under federal law to impose licensing and safety -related requirements for the operation of nuclear generation facilities. Events at nuclear facilities of other operators or impacting the industry generally may lead the NRC to impose additional requirements and regulations on existing and new facilities. As a result of t he March 2011 earthquake and tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, various industry organizations are working to analyze information from the Japan incident and develop action plans for U.S. nuclear power plants. Additionally, the NRC is performing its own independent review of the events at Fukushima Daiichi, including a review of the agency’s processes and regulations in order to determine whether the agency should promulgate additional regulations and possibly make more fundamental changes to the NRC’s system of regulation.

On March 12, 2012, the NRC issued the first regulatory requirements for all 104 operating reactors located in the United States based on the task force evaluations. The NRC issu ed three orders that modify operating licenses by requiring the following safety enhancements: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants; (2) ensuring reliable hardened containment vents; and ( 3) enhancing spent fuel pool instrumentation. The orders require prompt implementation of the safety enhancements and to complete implementation within two refueling outages or by December 31, 2016, whichever comes first. The safety enhancements were com pleted within the required timeframe. On January 4, 2013, the NRC issued guidance to enable U.S. nuclear power plant operators to perform the seismic and flooding hazard assessments. The City does not yet know the extent to which the changes in the regul ations, programs, and processes of the NRC as a result of the recommendations of the task force will affect PVNGS operations. The financial and/or operational impacts on PVNGS may be significant.

In the event of noncompliance with its requirements, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime that could ultimately result in the shut-down of a unit, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved.

Magnolia Power Project. The City is a participant in the Magnolia Power Project, a gas- fired generating facility with a nominally rated net capacity of 242 MW and auxiliary facilities located in Burbank, California. Through a contract with SCPPA, the City is entitled to a 6.4% (14.8 MW base capacity and up to about 19 MW peaking capacity) entitlement in the project through a long-term power purchase agreement with SCPPA. SCPPA has entered into power sales agreements with the City and the cities of Anaheim, Burbank, Cerritos, Colton, Glendale and Pasadena pursuant to which SCPPA has sold its entitlement to capacity and energy in the Magnolia Power Project to the applicable participants on a “take-or-pay” basis. The Magnolia Power Project commenced commer cial operation on September 22, 2005. SCPPA issued bonds to finance the construction of the Magnolia Power Project, of which $219,005,000 aggregate principal amount was outstanding as of January 1, 2024. PWP has entered into a power sales agreement with SCPPA for an approximate 6.4% participation share in the Magnolia Power Project and is therefore responsible for 6.4% of the costs of the Magnolia Power Project.

25 Milford Wind Corridor Phase I Project. In February 2009, the City entered into a 20-year power sales agreement with SCPPA for 2.5% (approximately 5 MW) of the output (including capacity, energy and associated environmental attributes) of Milford Wind Corridor Phase I Project (“Milford”), a 203.5 MW nameplate capacity wind farm comprised of 97 wind turbines located near Milford, Utah. The facility is owned by Milford Wind Corridor Phase I, LLC, a limited liability company organized and existing under the laws of the State of Delaware. The facility went into commercial operation on November 16, 2009. Energy from the facility is delivered over an approximately 88- mile, 345 kV, transmission line extending from the wind generation site to the IPP Switchyard in Delta, Utah, an ownership interest in which transmission line, together with certain structures, facilities, equipment, fixtures, improvements and associated real and personal property interests and other rights and interests necessary for the ownership and operation of the generation facility and the sale of power therefrom, comprise a part of the Milford facility. The City is able to accept the delivered facility energy utilizing its capacity rights in the IPP Switchyard that are provided under agreements relating to the IPP. The facility ener gy is then delivered over the Southern Transmission System of IPP to the Adelanto or Marketplace terminal in California utilizing the City ’s capacity rights in the Southern Transmission System and other transmission systems. See “– Transmission Resources – Existing Transmission Resources – Southern Transmission System ” below. The facility energy delivered at Adelanto or Marketplace is then transmitted to the City under certain transmission arrangements between LADWP or the CAISO and the City and certain transmission arrangements between the City and SCE. The City has entered into a power sales agreement with SCPPA that obligates the City to pay its share of capacity and energy on a “take-or-pay” basis. As of January 1, 2024, SCPPA had outstanding $75,625,000 aggregate principal amount of bonds issued primarily for the purpose of prepaying for a guaranteed annual quantity of energy from the facility for approximately 20 years. When the IPP contract terminates in 2027, the City will no longer have rights on the STS to deliver power to the City from the Milford project. The City is currently working closely with LADWP to secure rights to the STS or potentially layoff the Milford power from 2027-2029 to a third party.

In addition to being a participant in the above-described SCPPA projects, the City has acquired certain of its other renewable resources through SCPPA. See also “Renewable Resources” below.

Prepaid Natural Gas Project . In 2007, SCPPA undertook the Prepaid Natural Gas Project, in which the City is a participant. The Prepaid Natural Gas Project provides, through gas sales agreements (“Gas Sales Agreements”) with the participants in the Prepaid Natural Gas Project, for a secure and long- term supply of natural gas. The original agreement provided the City with a supply of approximately 2,000 MMBtu daily or 730,000 MMBtu annually at a discounted price below spot market price (the SoCal Index) for a 30-year term. The projected discount of approximately 90 cents per MMBtu was expected to result in savings of approximately $657,000 annually, or approximately $19.7 million over the 30-year term.

On October 22, 2009, the Gas Sales Agreement with SCPPA was restructured to provide an acceleration of a portion of the long-term savings over the succeeding three years, reduce the remaining volumes of gas to be delivered and shorten the overall duration of the agreement. The restructured agreement provided additional savings of approximately $2,700,000 to the participants through 2012 with the remainder to be realized over the new term of the transaction. Total expected savings from the project are not impacted by the restructuring. The restructured agreement will terminate in 2035 compared to the original termination year of 2038. The volumes of gas to be de livered are reduced from approximately 2,000 MMBtu to 1,340 MMBtu daily at a projected discount of approximately 98 cents per MMBtu. As a result of this restructuring, approximately $165,000,000 worth of outstanding aggregate principal bonds were retired. On September 19, 2013, SCPPA entered into a second restructuring of the Prepaid Natural Gas Project. Although the terms of certain agreements to which SCPPA is a party were amended as part of this restructuring, the terms of the City ’s Gas Sales Agreement were not amended. As part of the restructuring, SCPPA received a payment of approximately $3,400,000 from the gas supplier, of which $561,000 was remitted to the City. As of January 1, 2024, SCPPA had outstanding $247,210,000

26 aggregate principal amount of bonds issued for the Prepaid Natural Gas Project. SCPPA will bill the City for actual quantities of natural gas delivered each month. PWP expects that these costs will be recovered through the energy charge component of the electric rates as they are incurred, just as costs for natural gas purchases are currently recovered.

Natural Gas Project. The Natural Gas Project includes SCPPA’s leasehold interests in (i) certain natural gas resources, reserves, fields, wells and related facilities located near Pinedale, Wyoming and (ii) certain natural gas resources, reserves, fields, wells and related facilities in (or near) the Barnett Shale geological formation in Texas. The capital costs of the entitlement shares purchased by certain participants were financed through SCPPA by the issuance of project revenue bonds. The City and the City of Glendale contributed capital to SCPPA for the payment of their respective shares of the capital costs of the Natural Gas Project. SCPPA has sold the entire production capacity of its member -related leasehold interests, on a “take-or-pay” basis (with the City and the City of Glendale having no obligation to pay any debt service).

Purchased Power
In addition to City-owned resources and interests in the joint-venture generation projects described above, the City has long- term contractual arrangements for Electric System firm purchases, as well as enabling agreements, including WSPP membership, which allow short-term power transactions in markets throughout the Western United States, Canada and Mexico. Each of these resources is briefly described below.

Hoover Hydroelectric Project Interest . The City has two cost -based power purchase agreements with the United States Department of Energy Western Area Power Administration for a combined total of up to 20 MW capacity from the generating units at the hydroelectric power plant of the Boulder Canyon Project at Hoover Dam (the “Hoover Project”), located approximately 25 miles from Las Vegas on the Nevada/Arizona border. The previous Hoover Project contract expired in September of 2017 and was subsequently renewed until 2067. The City’s capacity entitlement is comprised of an 11 MW renewal contract and a contract for 9 MW resulting from the uprating of the Hoover Project. The actual capacity available from the Hoover Project varies, depending on hydrologic conditions, maintenance scheduling and other outages. Under normal hydrologic conditions, the City receives approximately 60 GWh of annual energy deliveries. On December 20, 2011, President Obama signed the Hoover Power Allocation Act of 2011 providing for the distribution of power from the Hoover Project from 2017 through 2067. The Hoover Power Allocation Act of 2011 also mandated that each of then current po wer users give up 5% of its Hoover Project power resource so that an allotment is set aside for new participants in the Hoover Project region. In the Fiscal Year ended June 30, 2023, the Hoover Project provided 37.5 GWh of energy to the City at an average cost for delivered power of $22.00 per MWh. The City Council has authorized the signing of the post-2017 Energy Services Agreement to preserve the benefits of the Hoover Project through 2067.

Renewable Resource Purchases. The City has also entered into certain other power purchase agreements in furtherance of its adopted renewable resource portfolio standard. See “– Renewable Resources” below.

Bilateral (Spot Market) Energy Purchases . Approximately 6- 15% of PWP’s annual energy needs are met through economic purchases of spot market power through short -term bilateral transactions. These transactions, which range in duration from one hour to one year, are made pursuant to the WSPP, of which the City has been a member since 1995. The WSPP is governed by a master enabling agreement with over 175 member utilities and power marketers. PWP ’s risk policy allows short-term transactions of one year or less for capacity, energy or both at negotiated market prices under the WSPP Agreement. In addition, the WSPP recently added a new schedule to the agreement to allow bilateral purchases of bundled or unbundled Renewable Energy Credits (“REC”).

27 Renewable Resources
In order to meet California ’s Renewables Portfolio Standard , the City continues to procure additional renewable resources through SCPPA as well as through independent negotiations with renewable resource providers.

In Se ptember 2018, California enacted SB 100, California Renewables Portfolio Standard Program:
emissions of greenhouse gases, which requires that 60% of retail electricity sales to end -use customers be met with renewable resources. The requirement increases to 100% renewable and zero-carbon resources by 2045. At the end of December 2022, PWP achieved 40% RPS, exceeding program requirements, and is forecasting to achieve 41.25% for calendar year 2023, which will be reported by July 1, 2024, in accordance with regulations.

City of Pasadena Resolution 9977 (adopted January 30, 2023) sets a goal to source 100% of the City’s electricity from carbon free resources by the end of 2030, which will likely further accelerate the acquisition of energy resources (e.g., solar, wind, and geothermal) that are both renewable and carbon- free. Also see “DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS – State Legislation.” Besides those listed below, additional contracts with proposed renewable energy facilities are being negotiated to support the RPS in future years.

Milford Wind Corridor Phase I Project. As described above, the City is a participant in SCPPA’s Milford Wind Corridor Phase I Project, a 203.5 MW wind generating facility located in Millard County, Utah that began commercial operation in November 2009. The City executed a power sales agreement with SCPPA for an approximately 5 MW (2.5%) share of the project. The project will expire in November 2029 (unles s earlier terminated).

High Winds Wind Generat ion Facility . In 2003, the City Council approved a 20- year power sales agreement with a 5 -year extension if agreed upon by both counterparties for the purchase of wind- powered electrical energy associated with a 6 MW (or approximately 17,500 MWh per year) share of the PPM Energy, Inc.’s (now Avangrid Renewables ( “Avangrid”)) High Winds W ind Generation Facility (“High Winds”). The High Winds project is a 145.6 MW wind generation facility located in Solano County, California. Avangrid is responsible for scheduling the wind energy as it is produced at the High Winds project into the CAISO. Avangrid re-delivers the associated energy on a firm 2 MW basis to a delivery point in Southern California, providing PWP with a constant, reliable source of energy. Avangrid has decided not to extend the contract and is set to terminate on December 31, 2023.

Ameresco, LLC Chiquita Canyon Landfill Gas to Electricity Generation Project . In 2004, the City Council approved a 20- year power sales agreement with SCPPA for the purchase of 8.3 MW of landfill gas - generated electrical energy from the Ameresco, LLC, Chiquita Canyon Landfill Gas to El ectricity Generation project (“Ameresco”) located in Valencia, California. The project began operation in 2010, and produced approximately 29 GWh in Fiscal Year 2022-23.

Puente Hills Landfill Gas-to-Energy Project. On June 23, 2014, the City Council approved a 14- year power sales agreement with SCPPA for approximately 30% of the output from the Puente Hills L andfill Gas-to- Energy (“Puente Hills”) project, starting January 1, 2017. The Puente Hills project is an existing 43 MW project located near Whittier, California. The project produced approximately 46 GWh in Fiscal Year 2022-23.

In early 2024, the Ameresco and Puente Hills Landfill Gas projects both reported operational challenges.

The future status of the projects continues to be monitored.

Windsor Reservoir Solar Project. On March 30, 2010, PWP issued a request for proposals (“RFP”) for a rooftop photovoltaic solar project to be installed on City facilities. Of the 24 responses received, PWP chose to proceed with a 0.564 MW project to be installed by Martifer Solar, Inc. atop the PWP Water Division’s Windsor Reservoir Solar project. Completed and operational on May 31, 2011, the project generated approximately 0.6

28 GWh of solar energy in Fiscal Year 2018- 19. Through internal agreements, the renewable energy generated is purchased by the Power Division through bill credits to the Water Division thereby reducing PWP ’s customers’ water bills. These savings benefit PWP’s water customers through reduced operating costs of the Water Division.

Columbia II Solar Project . In December 2014, the City scheduled the first MWhs of energy from the Columbia II Solar project, owned and operated by Dominion Resources, Inc. The Columbia II Solar (“Columbia II”) project is a 15 MW solar plant located in Mojave, California. This project was procured through the 2013 SCPPA open RFP process. The City purchases 17.143% (approximately 2.6 MW) of the output from Columbia II through a power sales agreement with SCPPA dated September 19, 2013. The project generated approximately 6 GWh of energy in Fiscal Year 2022-23.

Kingbird Solar Project . On September 9, 2013, the City Council approved a contra ct for 100% of the production from the 20 MW Kingbird Solar project (“Kingbird”) in Rosamond, California. The Kingbird project achieved commercial operations on April 30, 2016 and is operated by First Solar. The Kingbird project contract has a 20-year term which may be extended by the City in its sole discretion for an additional five contract years.

The contract also includes an option for the City to purchase the project at various points during the term. The Kingbird project generated approximately 57 GWh of energy in Fiscal Year 2022-23.

Summer Solar Project. The City executed a contract dated November 15, 2012 with SCPPA to purchase

32.5% of the output from the 20 MW Summer Solar (“Summer Solar”) project located near Lancaster, California.

The contract was amended on March 10, 2014. The Summer Solar project achieved commercial operation on July 25, 2016. The project generated approximately 14 GWh of energy in Fiscal Year 2022-23.

Antelope Big Sky Ranch Solar Project . The City executed a contract dated November 15, 2012, with SCPPA to purchase 32.5% of the output from th e 20 MW Antelope Big Sky Ranch S olar project located near Lancaster, California. The contract was amended on March 10, 2014. Antelope Big Sky Ranch Solar project achieved commercial operation on August 19, 2016. The project generated approximately 15 GWh of energy in Fiscal Year 2022-23.

Powerex Renewable Energy Contract . On April 9, 2018, the City Council approved an eleven- year contract with Canadian firm Powerex Corp. (“Powerex”) for the purchase of 70,000 MWh per year of Category 1 and 5,000 in calendar year 2020, 15,000 in calendar year 2021 and 40,000 in calendar year 2022MWh per year of Category 2 bundled RECs for three years beginning calendar year 2020. The produc ts will be supplied from Powerex’s existing fleet of California RPS -certified renewable resources in British Columbia, Canada and the State of Washington.

Coso Geothermal Project . The City executed a 20- year contract January 11, 2021, with SCPPA to purchase 20 MW from the 270 MW Coso Geothermal (“Coso”) project located near China Lake, California. Coso is projected to achieve commercial operation on January 1, 2027. The project should generate approximately 95 GWh of energy for PWP annually over the first 10 years of the contract, and approximately 211 GWh of energy for PWP annually over the last 10 years of the contract, Geysers Geothermal Project. The City executed a contract dated May 26, 2023, with SCPPA to purchase 25 MW from the existing 725MW Geyser s Geothermal project located near Sonoma, California. The project should generate approximately 195 GWh of energy for PWP annually over the 15-year life of the contract.

Sapphire Solar and Storage Project . The City executed a contract dated December 15, 2 022, with SCPPA to purchase 39 MW of solar photovoltaic generation and 20 MW of battery storage from the 117MW Sapphire Solar and Storage (“Sapphire”) project located in Riverside County, California. The Sapphire project is projected to achieve commercial operation on December 31, 2026. The project should generate approximately 109 GWh of energy for PWP annually over the 20-year life of the contract.

29 Bonanza Solar and Storage Project. The City executed a contract dated February 26, 2024, with SCPPA to purchase 105 MW of solar photovoltaic generation and 55 MW of battery storage from the 300MW Bonanza Solar and Storage (“Bonanza”) project located in Clark County, Nevada. The Bonanza project is projected to achieve commercial operation on December 31, 2027. T he project should generate approximately 303 GWh of energy for PWP annually over the 20-year life of the contract.

Solar Initiative and Photovoltaic Program
In recent years, PWP has seen an increase in generating facilities installations. Since 2008, approximately 2,600 City customers have installed generating facilities, such as solar photovoltaic equipment, on their properties to help offset and manage their electrical demand on PWP ’s system. Over 16 years, PWP has reviewed and approved over 23.5 MW of so lar photovoltaic technology (“PV”) capacity, roughly 8% of PWP ’s 2023 peak electric demand. With the revamp of PowerClerk 2.0, PWP can streamline the solar application process and is currently reviewing/approving over an all -time high of 400 solar applicat ions a year. With the increase in solar applications last year, PWP is looking to revise its Small Generation Agreement requirements which would reduce processing time and administrative burden, further simplifying the solar application process for its residents. PWP expects a steady increase in solar PV capacity over the next couple of years.

Energy Efficiency Goals and Programs
The City’s energy efficiency programs are designed to meet energy efficiency goals adopted by the City Council, while serving a broad cross-section of PWP’s customer groups. These achievements support the City’s sustainability goals and policies.

PWP achieved 91% of its energy efficiency goals in Fiscal Year 2022-23, while helping PWP customers save 10,682 MWh of energy and reducing peak demand by 0.95 MW. In total, more than 2,300 PWP customers received an energy efficiency rebate, electrification re bate, or direct installation service last year as a result of PWP’s energy efficiency and electrification programs. Additionally, approximately 49,000 residential customers received quarterly Home Energy Reports containing personalized information on their home’s energy usage data, trends, and comparisons, as well as helpful savings tips and leads to PWP efficiency programs and rebates.

Future Power Supply Resources
The City continues to procure additional renewable resources through SCPPA and directly with renewable resources providers to meet its projected RPS requirements. The City will continue to analyze a variety of renewable resources to meet the SB 100 compliance requirements. The City ’s goal is to have a diverse resource portfolio to meet its energy and compliance requirements, while mitigating environmental impacts at reasonable rates.

Fuel Supply
PWP’s local generating units are primarily fueled by natural gas, with average daily consumption of approximately 3,300 MMBtu during summer months. Duri ng peak months, gas requirements in excess of firm deliveries and long-term supply contracts are purchased at the Southern California Gas Company Citygate. The Southern California Gas Company (“SoCal Gas”) provides intra-state delivery of PWP’s natural gas supplies.

As noted above, the City is a participant in SCPPA ’s prepaid natural gas project which provides approximately 1,400 MMBtu of natural gas daily.

PWP also has access to Canadian gas via firm transportation on the Nova, Transcanada, and Pacific Gas & Electric (“PG&E”) expansion into the SoCal Gas system, with net capacity of approximately 3,989 MMBtu/day at Kern River Station in Kern County, California. PWP terminated the Nova and Transcanada firm transportation contract beginning October 1, 2023.

30 In January 2019, PG&E filed documents in a U.S. court seeking Chapter 11 reorganization. PWP currently holds a transportation service contract with PG&E for the option to transport up to 4,000 MMBtu of natural gas daily from Malin, Oregon to the southern terminus of the PG&E system. Although PWP pays a monthly reservation fee for the transportation contract, there is no activity that directly impacts PWP. From time to time, PWP has designated the capacity provided by the contract to other counterparties to recognize revenue to offset the reservation fee. PWP does not currently have any transactions directly with PG&E and does not expect to be adversely impacted by the bankruptcy filing.

In addition, the City is a participant in SCPPA’s Natural Gas Project, consisting of leasehold interests in natural gas fields located in Wyoming and Texas. These supplies are expected to account for an average of approximately 650 MMBtu/day. The City is currently selling the gas produced by its interests in the SCPPA Natural Gas Project rather than utilizing it in energy production at the Magnolia Power Project plant or its local generation. Such sale is rescindable at any time. See “– Joint Powers Agency Generation and Fuel Resources/Remote Ownership Interests – Southern California Public Power Authority – Natural Gas Project.” In October 2015, a leak was detected at So Cal Gas’s Aliso Canyon storage facility. The California Public Utilities Commission (“CPUC”) ordered that the Aliso Canyon inventory levels be reduce d to 15 billion cubic feet and ordered SoCal Gas to stop injections into the facility and only allowed further withdraws of natural gas from the facility under emergency situations. In November 2017, the CPUC issued the Aliso Canyon Withdrawal Protocol (the “Protocol”) that allows for the limited use of Aliso Canyon. The Protocol set forth minimum storage inventories, permits withdrawals when it is necessary to maintain reliability, to respond to risk to electric system reliability, and/or to avoid or limit curtailments to customers.

Aliso Canyon historically has been used by SoCal Gas as a tool to balance supply and demand and not being able to use it for normal business has caused operational challenges for SoCal Gas’s daily operation. As a result of th e Aliso Canyon gas storage situation, there is a possibility of disruptions to the normal natural gas supply for power plants in Southern California, including PWP ’s local Glenarm Power Plant. Effective June 1, 2016, the SoCal Gas implemented strict limitations and high penalties regarding scheduling and use of natural gas within its distribution system. PWP purchases/sells natural gas in the wholesale market and schedules deliveries to its power plants through the SoCal Gas pipelines. PWP must now closel y manage its natural gas supply daily and make adjustments to natural gas deliveries several times during the day as needed. Natural gas fired generation makes up approximately 10% of PWP’s resource portfolio, however it performs a critical function of ensuring PWP’s distribution system reliability, health and safety when peak energy demands exceed PWP’s ability to deliver enough energy (from sources outside PWP’s distribution system) to meet the demand. PWP utilizes its internal power plant to produce energy to make up for this shortfall in order to avoid rolling blackouts. The full impacts are not certain; however, the impacts on PWP’s natural gas supply are expected to be infrequent.

Transmission Resources
General
In January 2005, the City became a Participating Transmission Owner (“PTO”) in the CAISO and placed certain transmission facilities and entitlements to transmission service on certain facilities under the CAISO ’s operational control. Pursuant to the CAISO Tariff and applicable Federal Energy Regulatory Commission (“FERC”) precedent, FERC approved a Base Transmission Revenue Requirement ( “Base TRR”) and a Transmission Revenue Balancing Account Adjustment ( “TRBAA”) for the City to recover the costs of these facilities and entitlements.

The City has been filing annual updates to its TRBAA with FERC since becoming a PTO. The TRBAA is the mechanism by which transmission revenue credits associated with transmission service from the CAISO are flowed through to transmission customers. The TRBA A amount is used as an offset to the Base TRR of a PTO. The TRBAA does not change the Base TRR nor does it flow through transmission cost increases to PTOs.

Any change to the Base TRR requires that a petition must be filed with FERC.

31 In February 2019, the City filed a petition with FERC to revise its Base TRR to recover the cost increases the City has been experiencing since FERC approved its initial Base TRR. In April 2019, FERC approved the City’s petition and increased the City’s Base TRR by approximately $0.6 million, effective March 1, 2019.

Existing Transmission Resources
Transmission resources are an integral component of the City ’s plan to provide economical and reliable electric service to its customers. The City currently has several firm capacity transmission agreements to deliver over 200 MW of remote generation to the T.M. Goodrich Receiving Station in the City, and to provide access to major hubs of the western wholesale power market. The transmission network allows the City to obtain low-cost energy supplies when available. Depending on the generation source, the energy is transmitted through a combination of the transmission resources listed in the following table.

TABLE 4

FIRM TRANSMISSION SERVICE AGREEMENTS
Transmission Line path Owner/Party Capacity(2)
Sylmar-T.M. Goodrich SCE/CAISO(1) 336 MW
Pacific-Northwest DC Intertie City 72 MW
Northern Transmission System IPA/Utah
Mona Substation 76 MW
IPP-Gonder 11 MW
Southern Transmission System SCPPA 141 MW
Adelanto/Victorville-Sylmar LADWP 136 MW
Mead-Phoenix SCPPA
Westwing-Mead 49 MW
Mead Substation 25 MW
Mead-Marketplace 84 MW
Mead-Adelanto SCPPA 75 MW
Hoover
McCullough-Victorville City 25 MW
Adelanto-Victorville LADWP 26 MW
Adelanto-Sylmar LADWP 26 MW
Victorville-Sylmar LADWP 26 MW
Hoover-Sylmar LADWP 26 MW
Mead-McCullough LADWP 26 MW
_______________________
(1) The CAISO became the control area operator and scheduling agent for this line commencing with CAISO operations.
(2) Transmission lines with different import/export ratings.

Source: Power Supply Business Unit of PWP.

Southern California Edison Company. The City has a transmission contract with SCE for rights to firm transfer capacity from LADWP’s Sylmar Substation to the T. M. Goodrich Receiving Station in the City through SCE, as well as an agreement with SCE for interconnection of the T.M. Goodrich Receiving Station to the SCE system.

Pacific Northwest DC Intertie. Spanning 850 miles from Celilo in northern Oregon to Sylmar, California, the Pacific Northwest DC Intertie ( “PDCI”) is a double -pole, ±500 kV transmission line. The PDCI conveys energy to the City from the Bonneville Power Administration and other Pacific Northwest utilities. PWP is entitled to 72 MW (2.32%) of the total 3,100 MW capacity of the southern portion (south of the point where the line crosses the Nevada-Oregon Border of the PDCI).

Northern Transmission System. The Northern Transmission System consists of two 50- mile long 345 kV AC transmission lines which connect the IPP to the Mona Substation in Utah and the Gonder Substation in Nevada. The City currently has entitlements of 87 MW of capacity on these transmission lines as a result of the

32 IPP Excess Sales Contract with the U tah Participants. IPA allocates 2.4735% of its outstanding debt to the Northern Transmission System. As of June 30, 2018, this allocation was approximately $0.5 million. The City’s maximum share of this obligation is 7.6%.

Southern Transmission System . The Southern Transmission System is a double -pole, ±500 kV DC transmission line spanning 488 miles from IPP in central Utah to the Adelanto Substation in Southern California, together with an AC/DC converter station at each end. It is operated and mainta ined by the LADWP under contract with IPA. In connection with its entitlement to the IPP, the City acquired a contractual entitlement to 141 MW (5.9%) of the total 2,400 MW capacity of the STS. To facilitate financing of the STS, the City assigned its contractual transmission rights to SCPPA, and now receives its STS transmission through a service contract with SCPPA. As the result of an upgrade to the STS , which was completed in December 2010, the capacity of the STS was increased from the previous 1,920 MW to 2,400 MW. The term of the City’s contractual transmission right extends until the expiration of the IPP contract in June of 2027. The terms of the SCPPA transmission service contract also extend to June 2027, or until all SCPPA bonds issued to finance the STS are paid or defeased if later.

The City’s transmission service contract with SCPPA obligates the City to pay the cost of its share of the transfer capability on a “take-or pay” basis. As of June 30, 2023, SCPPA had outstanding $179,360,000 principal amount of bonds relating to the STS.

Adelanto-Sylmar Transmission Line. The City has a contract with LADWP for 136 MW of transmission capacity from the STS at either Adelanto or Victorville through the LADWP system to the CAISO at Sylmar.

Mead-Phoenix Transmission Project. The Mead-Phoenix Transmission Project consists of a 256-mile, 500 kV AC transmission line, which was placed into commercial operation on April 15, 1996, extending between a southern terminus at the existing Westwing Substation ( in the vicinity of Phoenix, Arizona) and a northern terminus at Marketplace Substation, a substation located approximately 17 miles southwest of Boulder City, Nevada. The line is looped through the 500- kV switchyard constructed in the existing Mead Substa tion in southern Nevada with a transfer capability of 1,923 MW (as a result of certain upgrades completed in 2009). By connecting to Marketplace Substation, the Mead- Phoenix Transmission Project interconnects with the Mead- Adelanto Transmission Project (as described below) and with the existing McCullough Substation. The Mead- Phoenix Transmission Project is comprised of three project components. SCPPA executed an ownership agreement providing it with an 18.3077% member -related ownership share in the West wing-Mead project component, a 17.7563% member -related ownership share in the Mead Substation project component, and a

22.4082% member-related ownership share in the Mead -Marketplace project component. Other owners of the line are Arizona Public Service C ompany, M-S-R Public Power Agency, Salt River Project and Startrans IO, L.L.C. The City entered into a transmission service contract with SCPPA which provides to the City an entitlement to 49 MW on the Westwing – Mead component, 25 MW on the Mead Substation component, and 84 MW on the Mead to Marketplace component of the Mead-Phoenix Transmission Project and obligates the City to pay its share (13.8%) of the transfer capability on a “take-or-pay” basis. The term of this contract extends for the life of th e facility, or until all SCPPA bonds issued to finance the project are defeased if later. As of June 30, 2020, SCPPA had paid in full principal amount of its bonds issued to finance the interest of SCPPA members in the project.

Mead-Adelanto Transmission Project. This arterial line consists of a 202-mile, 500 kV AC transmission line extending between a southwest terminus at the existing Adelanto Substation in Southern California and a northeast terminus at Marketplace Substation, located approximately 17 miles southwest of Boulder City, Nevada.

By connecting to Marketplace Substation, the line interconnects with the Mead-Phoenix Transmission Project and the existing McCullough Substation in southern Nevada. The line has a transfer capability of 1,291 MW. SCPPA has executed an ownership agreement providing it with a total of a 67.9167% member-related ownership share in the project. The other owners of the line are M -S-R Public Power Agency and Startrans IO, L.L.C. The commercial operation date for the project was April 15, 1996, which coincided with the completion of the Mead- Phoenix Transmission Project. The City has entered into a transmission system contract with SCPPA which provides to the City an entitlement to 75 MW of transfer capability on the Mead -Adelanto Transmission Project and obligates the City to pay its share (8.6%) of the transfer capability on a “take-or-pay” basis. The term of this

33 contract extends for the life of the facility, or until all SCPPA bonds issued to finance the project a re defeased if later. As of June 30, 2020, SCPPA had paid in full principal amount of its bonds issued to finance the interest of SCPPA members in the project.

Hoover Transmission Projects. The City contracts with LADWP for 20.197 MW of transmission services from the Hoover Switchyard to the Sylmar Substation.

McCullough-Victorville Transmission Line . The City acquired a 26 MW equity entitlement from LADWP in the 180- mile, 500 kV AC McC ullough-Victorville No. 2 Transmission Line. Originally utilized to import the City’s PVNGS power, this line provides a parallel path to the Mead- Adelanto transmission line into the critical Mead Substation.

Victorville-Sylmar. The City contracts with LA DWP for 26 MW of firm transmission service from the Victorville Substation to the Sylmar Substation as a continuation of the McCullough-Victorville Line.

Future Transmission Resources
As a PTO CAISO member, PWP has rights to transmission resources throughout the west to deliver contractual and spot market supplies into the City through the CAISO grid through the Sylmar interconnection with LADWP, about 10 miles from the City, to PWP ’s CAISO interconnection point at PWP ’s TM Goodrich Substation.

Inter-Utility Sales Transactions
General. In addition to making market purchases when economical, PWP also sells excess electric and gas commodity and transmission capacity when the City does not need it. The City has entered into a number of long-term capacity sales, and energy schedulers and dispatchers also respond to opportunities to market excess power when conditions warrant. The additional net revenues from these transactions help keep electricity rates down by offsetting fixed energy costs.

CAISO – Participating Generator Agreement. Under the CASIO Participating Generator Agreement, the City sells capacity and energy from its local generation resources at the Glenarm Power Plant into the CAISO’s ancillary service markets on a day-ahead and hour-ahead basis. Due to the short-term nature of the market, these ancillary service capacity and energy revenues are extremely volatile and difficult to predict; however, it is estimated that they will range from approximately $3 million to $10 million in future years.

Interconnections and Distribution Facilities
PWP owns facilities for the distribution of electric power within the City limits (approximately 23 square miles). These facilities include approximately 92 miles of 34 kV subtransmission circuits, 408 miles of 17 kV distribution circuits, 263 miles of 4 kV distribution circuits, 3 receiving stations and 11 distribution stations. For Fiscal Year 2022- 23, the City ’s system experienced approximately 16.8 minutes of outage time per customer served. PWP ’s benchmark for this metric is currently 35 minutes. Distribution infrastructure investments contributed to this improved measure of performance.

Electric Rates and Charges
The City is obligated by its Charter and by its rate ordinance to establish rates and colle ct charges in an amount sufficient to meet its expenses of operation and maintenance and debt service requirements (with specific requirements as to priority and coverage). See “SECURITY AND SOURCES OF PAYMENT FOR THE 2024A BONDS – Rate Covenant.” Electr ic rates are subject to approval by the City Council. Electric rates are not subject to regulation by the CPUC or by any other state agency. See, however, “RATE REGULATION.”

34 PWP’s electric rate structure is unbundled into distribution, customer, energy, transmission and Public Benefit Charge (“PBC”). The PWP rate structure is cost -based and does not provide for cross subsidies among customer classes. The PWP electric rates include variable components which are designed to recover from customers increased costs to the utility associated with energy and transmission. The City provides no free electric service. The following table sets forth average rates for each customer class as of June 30, 2019 through June 30, 2023.

TABLE 5

FIVE-YEAR HISTORY OF ELECTRIC RATES
Dollars Per Kilowatt Hour
Fiscal Year Ended June 30
Customer Class 2019 2020 2021 2022 2023
Residential $0.1928 $0.2089 $0.2106 $0.2100 $0.2188
Small Commercial and Industrial 0.1772 0.1963 0.1974 0.2008 0.2065 Medium Commercial and Industrial 0.1667 0.1847 0.1854 0.1844 0.1916 Large Commercial and Industrial 0.1659 0.1830 0.1878 0.1845 0.1802 Street Lighting and Traffic Signals 0.1495 0.1793 0.1884 0.1882 0.2015 ___________________________________
Note: Average rates above include Public Benefit Charge.

Source: Finance and Administration Business Unit of PWP.

Within PWP, “ commercial and industrial ” customers are principally educational and healthcare institutions and office buildings, as well as a wide range of businesses. These businesses include postal service, engineering, telecommunications, healthcare, property development, insurance, office products and packaging, and chemical products. No single commercial industrial customer cu rrently accounts for more than 6% of total annual electrical sales revenue. The top 10 commercial and industrial customers typically represent approximately 15% of PWP’s annual electric sales revenue.

Billing and Collection Procedures
Billing and collection services for all electric services are provided by PWP and the City ’s Finance Department. Most residential and certain commercial customers are billed bimonthly for electric and/or water service; most large commercial users are billed monthly for electric and water service. The City prepares a single bill for electric, water, refuse and sewer collection services. Payments received for the billed period are credited first to the oldest charges, then to current charges for each service in the order stated. • Deposits
• Refuse
• Sewer
• Electric
• Water
All charges for water and water service are due and payment rendered, and become delinquent 30 days after the bill date. To manage late/non-payments a 48-hour notice of termination is generated approximately 75 days after the actual billing date. If payment is not received the water service is interrupted. Should the bill not be paid within 15 days of a final notice, the electric service is then also interrupted. The total bill plus all reconnection charges must be paid to resume service. After 60 days, the account is written off by the PWP Collection Department and sent to the City Finance Department for further collection efforts.

In March 2020 to assist PWP customers experiencing financial difficulties as a result of COVID-19, PWP temporarily suspended the collection and assignment of late fees and delinquent charges on all accounts. The temporary change in procedure led to an increase in the bad debt projected for Fiscal Year 2021. In April 2021, the City Council approved the resumption of late fees for past due accounts effective July 1, 2021, however, due

35 to the requirements of participating the arrearage recovery programs, the City was unable to charge late fees or disconnect customers for a specific time period per the rules outlined in the program.

Along with many other utilities in the State, PWP participated in the California Arrearage Payment Programs, which provided financial assistance for California energy utility customers to help reduce past due energy bill balances during the COVID-19 pandemic.

Impact of Economic Conditions of the Development in the District Certain events and factors which negatively affect the regional, State and national economies could have an adverse effect on the Electric System and its finances, such as the COVID -19 pandemic and global market instability caused by the war in Ukraine and in the Middle East. Any adverse impact of the foregoing and other economic factors on the Electric System and its finances cannot be predicted.

Customers, Energy Sales and Revenues
The average number of customers, energy sales and revenues derived from sales, by classification of service, during the past five Fiscal Years, are listed below.

TABLE 6

CUSTOMERS, ENERGY SALES AND REVENUES
Fiscal Year Ended June 30
2019 2020 2021 2022 2023
Number of Customers
Residential 58,096 58,517 58,654 59,240 57,769
Small Commercial & Industrial 7,446 7,591 7,582 7,667 7,609 Medium Commercial & Industrial 1,022 884 876 874 850
Large Commercial & Industrial 148 134 134 124 116
Public Street & Highway Lighting 5 5 5 5 5
Wholesale Sales to Other Utilities 4 6 6 6 6 Total 66,721 67,137 67,257 67,916 66,355

Megawatt-hour Sales:

Residential 325,487 319,437 344,009 333,881 351,780
Small Commercial & Industrial 140,983 136,151 127,519 135,566 135,447 Medium Commercial & Industrial 263,682 250,862 233,640 252,170 259,963 Large Commercial & Industrial 281,949 270,620 225,524 239,199 314,303 Public Street and Highway Lighting 13,371 12,273 11,574 11,428 11,364 Other (Misc.) (6,816) 320 2,951 1,297 (5,445) Total Retail Energy Sales 1,018,656 989,663 945,217 973,541 1,067,412 Wholesale Sales to Other Utilities 26,645 68,513 32,496 145 151 Total Energy Sales 1,045,301 1,058,176 977,713 973,686 1,067,563

Revenues from Sale of Energy:

Residential $ 62,973,543 $ 66,826,434 $ 72,459,893 $70,130,803 $76,964,112 Small Commercial & Industrial 24,992,841 26,730,908 25,826,682 27,215,223 27,964,187 Medium Commercial & Industrial 43,680,757 46,499,626 43,339,086 46,499,423 49,816,955 Large Commercial & Industrial 46,618,773 49,543,632 42,370,832 44,128,473 56,650,986 Wholesale Sales to Other Utilities 10,714,292 5,336,904 10,391,248 6,545,178 10,250,261 Public Street & Highway Lighting 1,998,411 2,200,868 2,178,520 2,150,565 2,289,269 Other(2) 27,076,181 20,734,520 25,699,483 29,839,590 31,888,840 Total Energy Revenue $218,054,798 $217,872,892 $222,265,744 $226,509,255 $255,824,610 __________________________
(1) Other revenue includes PTO – Base TRR revenues, Cap and Trade revenues, unbilled revenue and miscellaneous governmental revenue.

Source: Finance and Administration Business Unit of PWP.

36 Indebtedness and Joint Agency Obligations
Upon the issuance of the 2024A Bonds and the refunding of the 2013A Bonds, in addition to the 2024A Bonds, the City will have outstanding $104,810,000 aggregate principal amount of Bonds which are payable from the Light and Power Fund and secured by a pledge of the Net Income of the Electric System. See “ SECURITY AND SOURCES OF PAYMENT FOR THE 2024A BONDS.”
As previously discussed, the City participates in the SCPPA joint powers agency. SCPPA provides for the financing and construction of electric generating and transmission projects for participation by some or all of its members. The City is a participant in the following SCPPA projects: PVNGS, Magnolia Power Project and Milford Wind Corridor Phase I Project, with respect to generation, is a parti cipant in the Mead -Phoenix Transmission Project, the Mead -Adelanto Transmission Project and the Southern Transmission System, with respect to transmission, and is a participant in the Prepaid Natural Gas Project and the Natural Gas Project, with respect to fuel supply. To the extent the City participates in projects developed by SCPPA, the Electric System is obligated for its proportionate share of the cost of the particular project, including in most cases, the costs of debt service on indebtedness incurr ed by SCPPA to finance the cost s of such projects. See TABLE 7 – “OUTSTANDING DEBT OF JOINT POWERS AGENCIES.”
In addition, the City has entered into certain power sales contracts with IPA and others for the delivery of electric power from IPP. The Electric System’s share of IPP power is equal to 6.0% of the generation output of IPP, IPA ’s 1,800 MW coal -fueled generating station, located in central Utah. The contracts constitute an obligation of the Electric System to make payments solely from reven ues from the Light and Power Fund. The power sales contracts also require the Electric System to pay certain minimum charges that are based on debt service requirements. However, the City’s entitlement under the IPP contract expires on June 15, 2027.

Obligations of the City under the agreements with IPA and SCPPA constitute Maintenance and Operating Expenses of the City payable prior to any of the payments required to be made on the Bonds. Agreements between the City and SCPPA (other than the agreement relating to SCPPA’s Natural Gas Prepaid bonds) and the City and IPA are on a “ take-or-pay” basis, which requires payments to be made whether or not applicable projects are operating or operable, or whether the output from such projects is suspended, interfe red with, reduced, curtailed or terminated in whole or in part. In addition, all of these agreements (other than the agreement relating to SCPPA’s Natural Gas Prepaid bonds and the agreement relating to SCPPA ’s Natural Gas Project in which the City contributed its share of capital costs and did not participate in the related financing) contain “ step-up” provisions obligating the City to pay a share of the obligations of a defaulting participant. Such payments represent the Electric System’s share of current and long-term obligations. Payment for these obligations will be made from operating revenues received during the year that payment is due. The City’ s participation and share of debt service obligations (without giving effect to interest due on the obligations or any “step up” provisions) for each of the joint powers agency projects in which it participates are shown in the following table.

37 TABLE 7

OUTSTANDING DEBT OF JOINT POWERS AGENCIES
As of June 30, 2023

Outstanding
Debt
City’s
Participation(1)
City’s Share of
Outstanding
Debt(2)
IPA
Intermountain Power Project $56,367,083 5.8% $3,249,800 SCPPA
Southern Transmission System 179,360,000 5.9 10,582,240 Magnolia Power Project(3) 220,510,000 6.4 14,112,640
Milford Wind Corridor Phase I Project 86,215,000 2.5 2,155,375 Natural Gas Prepaid(4) 258,460,000 16.5 42,645,900
Total $800,912,083 $72,745,955
____________________________________
(1) City’s participation percentages have been rounded in this table. Participation obligation is subject to increase upon default of another project participant (other than with respect to SCPPA’s Natural Gas Prepaid bonds). The City has no obligation for debt service costs (and no “step-up” obligation) in connection with SCPPA’s Natural Gas Project. (2) Principal only. Total amount is actual participation percentage of outstanding debt service amount. (3) Excludes bonds relating solely to City of Cerritos. (4) City payment obligation is with respect to actual quantity of natural gas delivered each month on a take-and -pay basis.

Responsibility for bond repayment is non-recourse to the City.

Sources: Finance and Administration Business Unit of PWP, SCPPA and IPA.

For the Fiscal Year ended June 30, 2023, the City’s payments of debt service on its joint powers agency obligations aggregated approximately $10 million. A portion of the joint powers agency obligation debt service is variable rate debt. Unreimbursed draws under liquidity arrangements supporting joint powers agency variable rate debt obligations bear interest at rates well in excess of the current variable rate on such bonds. Moreover, in certain circumstances, the failure to reimburse draws on the liquidity agreements may result in the acceleration of scheduled payment of the principal of such variable rate joint powers agency obligations. In addition, swap agreements entered into by the joint powers agencies in connection with certain of such obligations are subject to early termination under certain circumstances, in which event the joint powers agency could owe substantial termination payments to the applicable swap provider (an allocable portion of such payments the project participants would be obligated for).

Reserve Policies
During the past few years PWP has, in practice, had cash balances that exceeded 60 days of operating expenses on hand in accordance with reserve policies formalized in May 2006 as a matter of policy and not pursuant to any bond indenture or agreement. PWP was as of June 30, 2023, and currently is, in compliance with such policies. These funds represent moneys required for unanticipated operational expenses, as well as approved capital expenditures, unexpended PBC moneys and reserves for energy and transmission cost increases. The following table sets forth estimated reserves at June 30, 2023 based on unaudited information, for each fund.

Reserve levels are calculated in accordance with PWP’s reserve policy.

38 TABLE 8

RESERVES
As of June 30, 2023
Reserves(1) ($ million)
Operating Reserve $ 34.6
Energy Reserve 34.1
Transmission Reserve 6.7
Contingency Reserve 1.7
Bond Service Reserve 14.5
PBC Reserve 12.9
General Fund Transfer Reserve 13.0
Stranded Investment Reserve 40.3
Capital Reserve 166.9
Total $324.7
__________________________
(1) Based on estimated information.

Source: Finance and Administration Business Unit of PWP.

Operating Reserve. This reserve account provides for 60 days of operations and maintenance expenses.

Energy Reserve. This reserve account is available to mitigate energy cost volatility and unexpected plant outages, which have to be covered by power purchased in the energy markets. The reserve amount is driven mainly by a periodic assessment of PWP ’s load forecast, the amount of power required to be purchased in the energy markets to supplement power already secured through long- term commitments and past purchases, and the estimated near-term forecast of natural gas and power costs.

Transmission Reserve. This reserve account is avail able to mitigate transmission cost volatility and is calculated based on proposed Transmission Services Charge reserve requirement.

Contingency Reserve. This reserve account is designated for equipment replacement and/or emergency work due to natural disasters.

Bond Service Reserve. This reserve account is a depository account for bond debt service reserves funds held by the City for PWP bonds.

Public Benefit Charge Reserve. This reserve account is a depository account for balancing costs and revenues associated with the PBC Program and it is used exclusively to fund PBC-related expenditures.

General Fund Transfer Reserve. This reserve account is designated to provide funding to complete the General Fund transfer from the Light and Power Fund according to the schedule determined in the City Charter.

The schedule provides for 75% of the transfer to be made in July of the succeeding fiscal year with the remaining 25% to be made upon delivery of the audited financial statements. This reserve account is built up in the applicable fiscal year and depleted in the following fiscal year.

Stranded Investment Reserve. This reserve account was established in 1997 to mitigate the difference between the costs associated long -term contracts with IPA and SCPPA, and the anticipated energy costs in a deregulated energy market.

Capital Reserve. This reserve account is designated to fund the design and construction costs of near - term committed capital projects. PWP generally maintains a cash flow budget for key capital projects and ensures that it has on hand sufficient funds to cover its current year ongoing capital projects. Currently, PWP is utilizing the Capital Reserve to cover its pay -as-you-go portion of the financing required for its near -term capital investments.

39 Funding of Capital Improvements
Five-year capital plans for the PWP Electric System are based on the City’s Power Delivery Master Plan and Energy Integrated Resource Plan and approved by the City Council. In June 2022, the City Council adopted the Power Delivery Master Plan which identified the infrastructure needs of the power distribution system and recommended system improvements over a 20 -year planning period. In December 2023, the City Council approved the Energy Integrated Resource Plan which provides a 20- year strategic power resource plan that establishes broad objectives and an overall direction for future policy, program and procurement decisions with respect to PWP ’s power supply resource portfolio. See also “THE ELECTRIC SYSTEM OF PWP – Energy Integrated Resource Plan.”
The City expects routine capital requirements, including those contemplated by the Power Delivery Master Plan and the Energy Integrated Resource Plan for the next five Fiscal Years to aggregate approximately $520.2 million. These improvements are expected to be funded through revenues and the balance will be funded through the iss uance of the future financings. PWP seeks to maintain a long -term funding ratio for capital investment of approximately 65- 70% from long- term debt and 30- 35% from pay- as-you-go funding made available through current rates.

TABLE 9

CAPITAL REQUIREMENTS
(In Thousands)
Fiscal Year Capital Requirements
2025 $110,028
2026 115,866
2027 110,307
2028 121,610
2029 62,348
Total $ 520,159
____________________
Source: Finance and Administration Business Unit of PWP.

The major objectives of the City’s five-year capital plans are focused on improving system infrastructure, system capacity, and reliability. Projects will focus on upgrades to distribution system components: switchgear, cable, overcurrent protection devices, substations and dispatch sites. Projects to convert 4 kV circuits in PWP distribution systems to operate at 17 kV along with cable replacement programs ensure adequate service for new customers; construction of electrical systems, undergrounding, and planning for subtransmission system enhancements will mitigate risk and ensure dependability in service. Components of the near -term capital plan include, but are not limited to, the following:

Distribution System Conversion to 17 kV - This project provides for the conversion of existing 4 kV distribution systems to 17 kV, allowing for more efficient operation with newer equipment. The conversion process provides the additional benefits of reduced equipment overloading, improved voltage regulations, reduced outages, and reduced energy losses on the distribution system. Lastly, due to increased system capacity, conversion to 17 kV systems will ensure adequate electrical service for new residential and commercial construction, renovation, and upgrades.

Energy Storage Systems - This project provides for local battery energy storage systems. The Energy Integrated Resource Plan was developed to help PWP supply reliable and environmentally responsible. One of the recommended resources is the installation of e nergy storage systems to assist meeting resource adequacy requirements.

Advanced Metering Infrastructure (“AMI ”) - This project provides meters, collectors, fiber optic backhaul, and enterprise software for remote collection of utility metering data via an AMI smart meter network.

AMI is needed to collect interval metering data to assist PWP and customers in improvin g efficient electric and

40 water use to promote conservation. The project will provide detection services, improved customer service with real-time data, support time-of-use power rate structures to encourage conservation and load-shifting and enable customers with solar panels, home batteries, or electric vehicles to make better decisions on how they manage their system.

Historical Operating Results and Debt Service Coverage
The following table shows the historical operating results and debt service coverage during the past five Fiscal Years on PWP’s parity obligations payable from PWP’s Light and Power Fund. [Remainder of page intentionally left blank.]

41 TABLE 10

HISTORICAL OPERATING RESULTS AND DEBT SERVICE COVERAGE
(Dollar Amounts in Thousands)
Fiscal Year Ended June 30
2019 2020 2021 2022 2023
Revenues:

Base Rate Operating Revenues $ 68,549 $ 75,867 $ 75,865 $ 76,626 $ 80,054 Recovered Energy and Transmission Costs 104,361 109,503 104,157 106,308 128,051 PTO – Base TRR Revenues 14,945 15,830 14,867 15,296 16,157 Public Benefit Charge Revenues 7,118 6,839 6,633 6,795 7,331 Sales to Other Utilities 10,714 5,337 10,391 6,545 10,250 Other Operating Revenues 12,369 4,497 10,353 14,939 13,982 Total Operating Revenues $218,056 $217,873 $222,266 $226,509 $255,825

Expenses:

Energy Costs – Fuel
Retail $ 5,446 $ 4,199 $ 1,592 $ 5,396 $ 9,949 Wholesale 4,491 1,508 2,351 2,210 5,091
Purchased Power
Retail 91,666 90,538 90,289 90,576 113,715
Wholesale 1,953 1,551 2,038 1,858 1,934
Direct Operating Expenses 28,023 28,444 27,192 26,418 32,518 General, Administrative and Commercial 24,055 29,798 32,006 28,583 29,709 Interest Expense 9,538 9,129 8,293 7,699 7,278
Depreciation 31,702 31,955 32,271 33,981 37,850 Total Expenses $196,874 $197,122 $196,032 $196,721 $238,044

Earnings from Operations $ 21,182 $ 20,751 $ 26,234 $ 29,788 $ 17,781 Non-Operating Income 19,334 17,109 9,387 (1,036) 12,263 Net Income $ 40,516 $ 37,860 $ 35,621 $ 28,752 $ 30,044

Cash Flow and Debt Service Calculation
Add Back Interest Expense $ 9,538 $ 9,129 $ 8,293 $ 7,699 $ 7,278 Add Back Depreciation 31,702 31,955 32,271 33,981 37,850 Add Back Amortization 674 674 674 674 674 Available for Debt Service $ 82,430 $ 79,618 $ 76,859 $ 71,106 $ 75,846

Debt Service $ 23,253 $ 23,254 $ 23,059 $ 23,077 $ 15,712

Debt Service Coverage 3.54x 3.42x 3.33x 3.08x 4.83x

Amount Available After Debt Service $ 59,177 $ 56,364 $ 53,800 $ 48,029 $ 60,134 _________________________
Source: Finance and Administration Business Unit of PWP.

42 Condensed Balance Sheet
The following Condensed Balance Sheet has been prepared by the City. The information for the Fiscal Years ended June 30, 2019 through June 30, 2023 has been prepared based upon audited financial statements.

TABLE 11

ELECTRIC UTILITY FUND

CONDENSED BALANCE SHEET
(Dollar Amounts in Thousands)
Fiscal Year Ended June 30
2019 2020 2021 2022 2023
Current & Non-Current Assets $285,432 $316,766 $319,134 $323,519 $326,683 Restricted Assets 98,865 84,485 71,050 56,347 54,756
Net Property, Plant and Equipment 517,491 514,892 530,113 536,499 537,612 Total Assets 901,788 916,143 920,297 916,365 919,051 Deferred Outflow of Resources 13,388 10,150 11,063 9,644 22,272 Current Liabilities 30,607 33,586 35,224 35,818 31,678 Long-Term Liabilities 300,210 288,176 275,148 237,851 262,479 Total Liabilities 330,817 321,762 310,372 273,669 294,157 Deferred Inflow of Resources 2,969 2,595 1,431 22,031 4,813 Total Net Position $581,390 $601,936 $619,557 $630,309 $642,353 _________________________
Source: Finance and Administration Business Unit of PWP.

RATE REGULATION
The City sets rates, fees and charges for electric service. The authority of the City to impose and collect rates and charges for electric power and energy sold and delivered is not subject to the general regulatory jurisdiction of the CPUC and presently neither the CP UC nor any other regulatory authority of the State of California nor the FERC approves such rates and charges. Although the retail rates of the City for electric service are not subject to approval by any federal agency, the City is subject to certain ratemaking provisions of Sections 211-213 of the Federal Power Act (“FPA”). It is possible that future legislative and/or regulatory changes could subject the rates and/or service area of the City to the jurisdiction of the CPUC or to other limitations or requirements.

FERC could potentially assert jurisdiction over rates of licensees of hydroelectric projects and customers of such licensees under Part I of the FPA, although it has not as a practical matter exercised or sought to exercise such jurisdiction to modify rates that would legitimately be charged.

Under Sections 211, 211A, 212 and 213 of the FPA, FERC has the authority, under certain circumstances and pursuant to certain procedures, to order any utility (municipal or otherwise) to provide transmission access to others at FERC -approved rates. In addition, the Energy Policy Act of 2005 expanded FERC ’s jurisdiction to require municipal utilities that sell more than eight million MWhs of energy per year to pay refunds under certain circumstances for sales into organ ized markets. To date, it is unclear when, if ever, the City would meet this threshold requirement.

The CEC is authorized to evaluate rate policies for electric energy as related to the goals of the Warren- Alquist State Energy Resources Conservation and Development Act and to make recommendations to the Governor, the Legislature and publicly owned electric utilities.

43 DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS
State Legislation
A number of bills affecting the electric utility industry have been introduced or enacted by the California Legislature in recent years. In general, these bills regulate greenhouse gas emissions and provide for greater investment in energy efficiency and environmentally friendly generation and storage alternatives, principally through more stringent renewable resource portfolio standard requirements. The following is a brief summary of certain of these bills that have been enacted.

Greenhouse Gas Emissions – Executive Orders. On June 1, 2005, then Governor Arnold Schwarzenegger signed Executive Order S-3-05, which placed an emphasis on efforts to reduce greenhouse gas emissions by establishing statewide greenhouse gas reduction targets. The targets are: (i) a reduction to 2000 emissions levels by 2010; (ii) a reduction to 1990 levels by 2020; and (iii) a reduction to 80% below 1990 levels by 2050. The Executive Order also called for the California Environmental Protection Agency to lead a multi - agency effort to examine the impacts of climate change on California and develop strategies and mitigation plans to achieve the targets. On April 25, 2006, then Governor Schwarzenegger also signed Executive Order S -06-06 which directed the State of California to meet a 20% biomass utilization target within the renewable generation targets of 2010 and 2020 for the contribution to greenhouse gas emission reduction.

On April 29, 2015, then Governor Jerry Brown signed Executive Order B-30-15, which establishes a new interim statewide greenhouse gas emission reduction target to reduce greenhous e gas emissions to 40% below 1990 levels by 2030. Executive Order B -30-15 indicates that the new interim target is aimed at ensuring that California meets the target established by Executive Order S-3-05 of reducing greenhouse gas emissions to 80% below 1990 levels by 2050. Executive Order B -30-15 also directs the California Natural Resources Agency to update the State ’s climate adaptation strategy every three years and to ensure that its provisions are fully implemented. Among other requirements, Executive Order B-30-15 provides that the State’s adaptation strategy must identify a lead agency or agencies that are responsible for adaptation efforts in at least the following sectors:
water, energy, transportation, public health, agriculture, emergency ser vices, forestry, biodiversity and habitat, and ocean and coastal resources. Executive Order B-30-15 required that the lead agencies for each sector outline the actions in their sector that will be taken as identified in the State ’s adaptation strategy and report back to the California Natural Resources Agency by June 2016.

The interim statewide greenhouse gas emission reduction target established by Executive Order B-30-15 was codified with the enactment of SB 32 , which was signed by then Governor Brown on September 8, 2016 became effective as law on January 1, 2017. SB 32 requires the California Air Resources Board ( “CARB”), the designated state agency charged with monitoring and regulating sources of emissions of greenhouse gases, to ensure that statewide greenhouse gas emissions are reduced to at least 40% below the 1990 level no later than December 31, 2030. Companion legislation, AB 197, also signed by then Governor Brown on September 8, 2016, increased legislative oversight of CARB. AB 197 added to the CARB board two members of the State Legislature as ex officio, nonvoting members and provides for the voting members to serve staggered six-year terms. Subject to specified requirements, an individual voting member may serve longer but only upon reappointment at the end of their six -year term. AB 197 further established a Joint Legislative Committee on Climate Change Policies, consisting of at least three members of the Senate and three members of the Assembly, to ascertain facts and make recommendations to the houses of the Legislature concerning the State ’s programs, policies and investments related to climate change. In addition, AB 197 requires that CARB, when adopting rules and regulations to achieve emissions reductions beyond the statewide greenhouse gas emissions limit, and to protect the state’s most impacted and disadvantaged communities, to follow specified requirements, consider the social costs of the emissions of greenhouse gases, and prioritize emission reduction rules and regulation s that achieve specified results.

44 On September 16, 2022, Governor Newsom signed AB 1279, which accelerates the “80% by 2050” GHG reduction of SB 32 to 85% by 2045. AB 1279 was among several laws identified in the 2022 Scoping Plan for Achieving Carbon Neutrality (issued November 16, 2022) to help achieve California’s new ambitious targets.

Greenhouse Gas Emissions – Global Warming Solutions Act. Then Governor Schwarzenegger signed AB 32, the Global Warming Solutions Act of 2006, which became effective as law on January 1, 2007. The GWSA prescribed a statewide cap on global warming pollution with a goal of returning to 1990 greenhouse gas emission levels by 2020. In addition, the GWSA established an annual mandatory reporting requirement for all investor-owned utilities (“IOUs”), local publicly-owned electric utilities and other load -serving entities (electric utilities providing energy to end- use customers) to inventory and report greenhouse gas emissions to CARB, required CARB to adopt regulations for significant greenhouse gas emission sources (allowing CARB to design a “cap-and-trade” system) and gave CARB the authority to enforce such regulations beginning in 2012.

On December 11, 2008, CARB adopted a “ scoping plan” to reduce greenhouse gas emissi ons. The scoping plan set out a mixed approach of market structures, regulation, fees and voluntary measures. The scoping plan included a cap-and-trade program. In August 2011, CARB revised the scoping plan in response to litigation.

The revised scoping plan also included a cap-and-trade program. The scoping plan is required to be updated every five years. CARB issued the proposed first update to the scoping plan update on February 10, 2014, which was approved by CARB on May 22, 2014. The scoping pla n update recommends that a plan to extend the cap -and- trade program beyond 2020 be developed by 2017. In addition, CARB approved a resolution at its October 25, 2013 board meeting that directed CARB’s executive officer to develop a plan for a post-2020 program, including a cost containment mechanism, before 2018. CARB has completed the 2030 Target Scoping Plan Update towards incorporating the 2030 interim emissions reduction target (40% below 1990 emissions levels by 2030). The 2030 Target Scoping Plan was adopted by CARB on December 14, 2017.

On October 20, 2011, CARB adopted a regulation implementing its cap- and-trade program. The California Office of Administrative Law (“OAL”) approved the regulation on December 13, 2011. The cap-and- trade regulation became effective on January 1, 2012. Emission compliance obligations under the regulation began on January 1, 2013. The cap- and-trade program covers sources accounting for 85% of California ’s greenhouse gas emissions, the largest program of its type in the United States.

The cap-and-trade program was implemented in phases. The first phase of the program (January 1, 2013 to December 31, 2014) introduced a hard emissions cap covering emissions from electricity generators, electricity importers and large industrial sources emitting more than 25,000 metric tons of carbon dioxide -equivalent greenhouse gases (“CDE”) per year. In 2015, the program was expanded to cover emissions from transportation fuels, natural gas, propane and other fossil fuels. The cap will decline each year until the end of the program, which was extended from 2020 to 2030 pursuant to AB 398 signed into law in July 2017.

The cap-and-trade program includes the distribution of carbon allowances equal to the annual emissions cap. Each all owance is equal to one metric ton of CDE. As part of a transition process, initially, most of the allowances were distributed for free. Additional allowances are being auctioned quarterly (auctions began in November 2012). Utilities can acquire more allowances at these auctions or on the secondary market. IOUs are required to auction the allowances they received for free from CARB. This requirement also applies to POUs that sell electricity into the CAISO markets, other than sales of electricity from r esources funded by municipal tax- exempt debt where the POU makes a matched purchase to serve its traditional retail customers. Utilities required to sell their allowances in the auctions are then required to purchase allowances to meet their compliance obligations, and use any remaining proceeds from the sale of their allocated allowances for the benefit of their ratepayers and to meet the goals of the GWSA. POUs that do not sell into the CAISO markets, and those that sell into the CAISO markets only electricity from resources funded by municipal tax-exempt debt, have three options (which are not mutually exclusive) once their allocated allowances are distributed to them. They can (i) place allowances in their compliance accounts to meet compliance obligations, (ii) place allowances in the compliance account of a joint powers agency or public power utility that generates power on their behalf, and/or (iii) auction the allowances and use the proceeds to benefit their ratepayers and meet the goals of the GWSA.

45 The cap-and-trade program also allows covered entities to use offset credits for compliance (not exceeding 8% of a covered entity’ s compliance obligation). Offsets can be generated by emission reduction projects in sectors that are not regulated under the cap-and-trade program. CARB has approved the following types of offset projects: urban forest projects, reforestation projects, destruction of ozone -depleting substances, livestock methane management projects, destruction of fugitive coal mine methan e and rice cultivation practices. CARB will continue to consider additional and updated offset protocols, including international, sector-based offsets.

The California cap-and-trade program is linked to the equivalent program in Quebec, Canada. The link took effect on January 1, 2014, although the first joint auction was delayed until November 25, 2014 in order to resolve certain technical issues. California’s program may be linked to additional Canadian provincial cap- and- trade programs, and possibly other U.S. state cap-and-trade programs, in later years as part of the Western Climate Initiative (“WCI”). The WCI is a regional effort consisting of California and four Canadian provinces (Quebec, British Columbia, Ontario and Manitoba), which have established a greenhouse gas reduction trading framework.

The California Chamber of Commerce initiated litigation alleging that CARB’s sale of allowances in the cap-and-trade auctions was an unconstitutional tax, since the legislation authorizing cap- and-trade (AB 32) was not passed with a 2/3 supermajority vote of the California Legislature. In 2017, California ’s Supreme Court declined to review the Third Court of Appeals’ decision in CARB’s favor, essentially ending the legal challenge.

This court decision paved the way for the extension of the program to align cap-and-trade with SB 32.

CARB adopted amended cap- and-trade regulation to extend the program beyond 2020 by establishing new emissions caps. Enabling future auction and allocation of allowances on behalf of rate-payers, and program linkage beyond 2020 with WCI participants. The 2016 rulemaking became effective October 1, 2017. CARB also adopted revised regulation in 2018 to address programmatic clarifications, and to address, allowance price caps , offset usage, Energy Imbalance Market related GHG emissions accounting, and Ontario ’s actions to revoke its participation in California cap- and-trade market. The regulatory amendments were adopted by CARB in December 2018.

In February 2023, CARB issued a market notice regarding further updates to the cap- and-trade regulations. Topics to be considered include banked allowances, evaluation of the program caps within the context of the 2022 Scoping Plan goals, conducting electricity sector and industrial sec tor leakage studies, updates to offset protocols, addressing the new Extended Day Ahead Market for electricity, protecting low income households from disproportionate impacts of energy prices, and carbon dioxide sequestration and removal projects developed under the SB 905 Carbon Capture, Removal, Utilization, Storage Program.

On April 9, 2024, CARB posted the Standardized Regulatory Impact Assessment for the cap- and-trade regulation, which is an initial economic evaluation of potential changes to the cap- and-trade program. CARB anticipates releasing draft regulatory language for the cap- and-trade program for public comment in the coming months, which may be further informed through public workshops and reflect an updated economic analysis.

The City is unable to predict at this time the full impact of the cap-and-trade program over the long-term on the Electric System or on the electric utility industry generally or whether any additional changes to the adopted program will be made. Since the advent of the cap- and-trade program in 2012, regulations by CARB have provided the electric sector, including the City, with sufficient allocated greenhouse gas allowances or credits to cover existing operations in meeting retail load obligations. The City may bank allocated allowances in its compliance account to satisfy a portion of its ongoing compliance obligations. The City may also buy or sell allowances in the quarterly auctions or on the bi-lateral market to meet its additional compliance obligations. The City could be adversely affected in the future if CARB changes the allowance allocation methodology, or if the greenhouse gas emissions of its resource portfolio is in excess of the allowances administratively allocated to it and it is required to purchase compliance instruments on the market to cover its emissions.

Low Carbon Fuel Standard ( “LCFS”) – LCFS is one of a suite of programs designed to reduce GHG emissions enacted through AB 32, the 2006 Global Warming Solutions Act. LCFS applies to fuels used for

46 transportation and works with the cap-and-trade program and with the advance car clean cars program to reduce transportation GHG emissions. LCFS requires a 10% reduction in the GHG emissions carbon intensity (“CI”) of all transportation fuel by 2020 and a 20% reduction by 2030. The LCFS standards are expressed in terms of the CI of gasoline and diesel fuel and their individual substitutes. The program is based on the standard that each fuel has “life cycle” greenhouse gas emissions that includes CO2, CH4 and N2O. This life cycle calculation examines the GHG emissions related to the production, transportation, and the use of a given fuel.

LCFS sets an annual CI benchmark for gasoline, diesel, and the fuels that replace them, such as electricity.

Each fuel’s annual CI scores are compared to a declining CI benchmark. Low carbon fuels below the benchmark generate credits. Fuels above the CI standard generate deficits.

LCFS specifically exempts a number of lower -carbon fuels, such as electricity and hydrogen, because they meet the 2020 carbon intensity targets. Providers of these fuels that choose not to participate in the LCFS program have no obligations for these fuels under LCFS. However, LCFS allows these fuel providers to “opt-in” to the program and generate LCFS credits that they can sell and trade in the California LCFS market. LCFS regulation provides guidelines on permissible uses of credit sale proceeds.

PWP opted in to the LCFS program in the winter of 2017 and uses credit revenue for a variety of activities, including construction of Electric Vehicle (“EV”) infrastructure, mandatory contribution to the Clean Fuel Reward program, which provides point-of-sale rebates to EV buyers, and EV-related outreach and supporting community- based programs. Credit sale proceeds have also been used to educate the public on EV usage, and to provide rebates for EV charging equipment of up to $600 for residential customers and $75,000 per site for commerc ial customers.

Electric utilities value the LCFS credit program because it encourages the sale of EVs, which provides a new electricity market. It also supports EV charging to balance uneven demand and variable wind and solar power supply.

Since January 2018, credit prices have ranged from as low as approximately $60/MT to as high as $193/MT. Prices in the market trading are based on the immediate needs of market participants. Since the credits do not expire, and with the extension of the LCFS p rogram through 2030, LCFS entities, with a compliance obligation, can bank their credits for future compliance.

Greenhouse Gas Emissions – Emissions Performance Standard. SB 1368 became effective as law on January 1, 2007. It provided for an emission per formance standard (“EPS”) , restricting new investments in baseload fossil fuel electric generating resources that exceed the rate of greenhouse gas emissions for existing combined-cycle natural gas baseload generation. SB 1368 allows the CEC to establish a regulatory framework to enforce the EPS for POUs such as the City. The CPUC has a similar responsibility for the IOUs. The regulations promulgated by the CEC were approved by the OAL on October 16, 2007. The CEC regulations prohibit any investment in baseload generation that does not meet the EPS of 1,100 pounds of carbon dioxide ( “CO2”) per MWh of electricity produced, with limited exceptions for routine maintenance, requirements of pre -existing contractual commitments, or threat of significant financial harm.

The EPS standard is 1,100 pounds CO2/MWh, meaning that utilities cannot enter into any new long term fossil fuel contracts higher than this EPS.

Energy Procurement and Efficiency Reporting. SB 1037 was signed by then Governor Schwarzenegger on September 29, 2005. It requires that each POU, including the City, prior to procuring new energy generation resources, first acquire all available energy efficiency, demand reduction, and renewable resources that are cost - effective, reliable and feasible. SB 1037 also requires each POU to report annually to its customers and to the CEC its investment in energy efficiency and demand reduction programs. The City has complied with such reporting requirements.

47 Further, AB 2021, signed by then Governor Schwarzenegger on September 29, 2006, requires that POUs establish, report, and explain the basis of the annual energy efficiency and demand reduction targets by June 1, 2007 and every three years thereafter for a ten-year horizon. A subsequent bill has changed the time interval for establishing annual targets to every four years. The City has complied with this reporting requirement under AB 2021. Future reporting requirements under AB 2021 include: (i) the identification of sources of funding for the investment in energy efficiency and demand reduction programs; (ii) the methodologies and input assumptions used to determine cost -effectiveness; and (iii) the results of an independent evaluation to measure and verify energy efficiency savings and demand reduc tion program impacts. The information obtained from the POUs is being used by the CEC to present the progress made by the POUs towards the State of California’s goal of reducing electrical consumption by 10% within ten years and the greenhouse gas targets presented in Executive Order S-3-

05. In addition, the CEC will provide recommendations for improvement to assist each POU in achieving cost - effective, reliable, and feasible savings in conjunction with the established targets for reduction. Then Governor Brown signed A B 802 into law on October 8, 2015 that allows savings to bring buildings up to code to count (rather than only “above code” savings to count) towards energy efficiency and demand reduction targets while setting new benchmarking requirements for building owners and usage disclosure requirements for California utilities.

SB 350, signed by then Governor Brown in October 2015, requires the CEC to establish a statewide goal of a cumulative doubling of statewide energy efficiency savings in elec tricity by retail customers by January 1, 2030. See “– Clean Energy and Pollution Reduction Act of 2015” below.

Renewables Portfolio Standard. SB X1 -2, the “California Renewable Energy Resources Act, ” was signed into law by then Governor Brown on April 12, 2011. SBX1-2 codifies the RPS target for retail electricity sellers to serve 33% of their loads with eligible renewable energy resources by 2020 as provided in Executive Order S-14-08 (signed by then Governor Brown in November 2008). As enacted, SBX1-2 makes the requirements of the RPS program applicable to POUs (rather than just prescribing that POUs meet the intent of the legislation as under previous statutes). However, the governing boards of P OUs are responsible for implementing the requirements, rather than the CPUC, as is the case for the IOUs. In addition, the CEC is given certain enforcement authority for POUs and CARB is given the authority to set penalties.

SBX1-2 requires each POU to adopt and implement a renewable energy resource procurement plan. As set out in more detail in the CEC’s RPS enforcement regulation, noted below, the plan must require the utility to procure at least the following amounts of electricity products from eligible renewable energy resources, which may include RECs, as a proportion of total kilowatt hours sold to the utility ’s retail end-use customers: (i) over the 2011-2013 compliance period, an average of 20% of retail sales from January 1, 2011 to December 31, 2013, inclusive; (ii) over the 2014-2016 compliance period, a total equal to 20% of 2014 retail sales, 20% of 2015 retail sales, and 25% of 2016 retail sales; and (iii) over the 2017-2020 compliance period, a total equal to 27% of 2017 retail sales, 29% of 2018 retail sales, 31% of 2019 retail sales, and 33% of 2020 retail sales.

SB 350 (2015), SB 100 (2018), and SB 1020 (2022) further increase and/or accelerate requirements and are discussed in greater detail below.

SBX1-2 provides exemption for any facility approved by the governing board of a POU prior to June 1, 2010 as satisfying renewable energy procurement obligations adopted under prior law if the facility is a “renewable electrical generation facility ” as defined in the bill (subject to certain r estrictions). Renewable electrical generation facilities include certain out- of-state renewable energy generation facilities if such facility:
(i) will not cause or contribute to any violation of a California environmental quality standard or requirement, (ii) participates in the accounting system to verify compliance with the RPS program requirements, and (iii) either (a) commenced initial commercial operation after January 1, 2005 or (b) either (x) the electricity generated by the facility is from incremental generation resulting from expansion or repowering of the facility or (y) the electricity generated by the facility was procured by a retail seller or POU as of January 1, 2010. The percentage of a retail electricity seller’s RPS requirements that may be met with unbundled RECs from generating facilities outside California declines over time, beginning at 25% through 2013 and declining to a level of 10% in 2017 and beyond.

48 Clean Energy and Pollution Reduction Act of 2015. SB 350, the “Clean Energy and Pollution Reduction Act of 2015,” was signed into law by then Governor Brown on October 7, 2015. SB 350 establishes an RPS target of 50% by December 31, 2030 for the amount of electricity generated and sold to retail customers from eligible renewable energy resources for retail sellers and POUs, including interim targets of (i) 40% by the end of the 2021-2024 compliance period, (ii) 45% by the end of the 2025-2027 compliance period and (iii) 50% by the end of the 2028-2030 compliance period.

SB 350 requires each retail seller of electricity (including IOUs, most POUs above a certain size threshold, community choice aggregators and energy service providers) to provide a renewable energy procurement plan on an annual basis, and to file an IRP, and a schedule for periodic updates to the plan, for approval. This includes addressing how affected utilities plan to meet the 2030 interim emissions reductions goal set by CARB. IRPs for retail sellers other than POUs will be reviewed by the CPUC. For POUs, the g overning body of the POU is responsible for adopting the IRP, subject to review by the CEC, which can recommend modifications to correct any shortcomings.

SB 350 specifies the factors that must be considered in proposed procurement plans and provides that the goals must be balanced by the need to have just and reasonable rates, to ensure system and local reliability, to preserve the resilience of the electric grid, and to enhance distribution system management. The bill specifically requires the CPUC to identify a “balanced portfolio of resources” to ensure “reliability” and “optimal integration” of renewables, and requires that utilities include in their procurement plans a “strategy for procuring best-fit and least cost resources” to meet the portfolio needs the CPUC identifies.

SB 350 further requires the CEC to establish annual targets for statewide energy efficiency savings and demand reduction that will achieve a cumulative doubling of statewide energy efficiency savings in electricity and natural gas final end uses of retail customers by January 1, 2030. The CPUC is required to establish energy efficiency targets for electrical and gas corporations consistent with this goal, and specifies programs that may be used to achieve the goal. POUs are required to establish annual targets for energy efficiency savings and demand reduction consistent with the goal and to report those targets to the CEC every four years for the next 10- year period. The bill provides guidance as to what measures qualify and requires an evaluation of feasibility and cost effectiveness in setting annual targets for those savings. SB 350 also requires the CEC to adopt a responsible contractor policy and establish consumer protection guidelines. The CEC is developing additional gu idelines on the statewide energy efficiency goals.

SB 350 required the CAISO to prepare proposed governance modifications to facilitate the transformation of the CAISO into a regional organization but provides that such governance modifications will not ta ke effect prior to completion of a specified process for review and study of the impacts of a regional market and the enactment by the California Legislature of future legislation implementing the proposed governance changes by 2019.

In July 2016, the CA ISO released a revised set of proposed principles for regional governance of the CAISO, which were presented at a joint state agency workshop on July 26, 2016. Following further input from stakeholders, the second revised proposal “ Principles for Governan ce of a Regional ISO ” was published in October 2016. The following year, AB 813 (Holden) was introduced and would have authorized the transformation of the CAISO into a multistate regional transmission system. After a two-year legislative session, the bill ultimately failed in August 2018. While stakeholder discussion has continued in the following years, no regional organization has yet been created.

The 100 Percent Clean Energy Act of 2018. SB 100, the “100 Percent Clean Energy Act of 2018”, was signed into law by then Governor Brown on September 10, 2018. SB 100 establishes a state policy that RPS - eligible and zero-carbon resources supply 100 percent of all retail sales in California by December 31, 2045. SB 100, establishes a 60% renewable energy procurement requirement of retail sales by December 31, 2030. SB 100 also accelerates the interim RPS targets established by SB 350 in 2015. New requirements are 44% by the end of

49 the 2021–24 compliance period, 52% by the end of 2025–27, and 60% by the end of the 2028 -30 compliance period.

SB 100 also restricts utilities from increasing carbon emissions out of state to achieve this state policy.

Regulatory agencies such as CEC, ARB and CPUC are tasked with ensuring that the electric system is balanced and reliable, and that the policy does not cause unreasonable impacts to customer rates and bills. Regulatory agencies are also required to prepare a joint report to the state legislature in collaboration with California balancing authorities by January 1, 2021, and every four years thereafter. The report will include a review of policy implementation including costs, resources and barriers to achieving the 100 clean energy goal.

In September 2022, Governor Newsom signed into law SB 1020, which revised the policy of the State established by SB 100 to provide that eligible renewable energy resources and “ zero-carbon resources” supply 90% of all retail sales of electricity to State end -use customers by December 31, 2035, 95% by December 31, 2040, 100% by December 31, 2045, and 100% of electricity procured to serve all state agencies by December 31, 2035.

Solar Power. On August 21, 2006, then Governor Schwarzenegger signed into law SB 1 (also known as the “California Solar Initiative ”). This legislation requires PO Us, including the City, to establish a program supporting the stated goal of the legislation to install 3,000 MW of photovoltaic energy in California. POUs are also required to establish eligibility criteria in collaboration with the CEC for the funding of solar energy systems receiving ratepayer-funded incentives. The legislation gives a POU the choice of selecting an incentive based on the installed capacity or based on the energy produced by the solar energy system, measured in kilowatt -hours.

Incentives would be required to decrease at a minimum average rate of 7% per year. POUs also have to meet certain reporting requirements regarding the installed capacity, number of installed systems, number of applicants, amount of awarded incentives and the con tribution toward the program ’s goals. The City has established the “Pasadena Solar Initiative” in accordance with the requirements of SB 1. The Pasadena Solar Initiative provided rebates for solar installations from a 10 -year period during 2008- 2017. As of January 1, 2018, PWP no longer provides rebates for solar installations and stopped accepting new applications, primarily because the r esidential solar market in Pasadena has matured and is expected to be sustainable without further rebate programs from PWP. After many years of contributing towards market transformation, the Pasadena Solar Initiative is expected to reach 10.54 MW of total installed solar capacity.

Legislation Relating to Wildfires. In September 2016, then Governor Brown signed into law SB 1028, which requires each POU, including the City, each IOU and each electric cooperative in the State to construct, maintain, and operate its electrical lines and equipment in a manner that will minimize the risk of catastrophic wildfire posed by those electrical lines and equipment. Effective January 1, 2017, SB 1028 requires the governing board of each POU to make an initial determination of whether its overhead electric lines and equipment pose a significant risk of catastrophic wildfire based on historical fires and local conditions. POU governing boards must independently make this determination based on all relevant information, including the CPUC’s Fire Threat Map which was adopted by the CPUC in January 2018. PWP has identified the portions of its overhead electrical lines and equipment that are located within each of threat areas identified in CPUC ’s Fire Threat Map. PWP has determined that its overhead electric lines and equipment do not pose a significant risk of catastrophic wildfire.

SB 901, which was signed into law in September 2018, is meant to further address response, mitigation, and prevention of wildfires. SB 901 requires, among other things, POUs, such as the City, to prepare before January 1, 2020 and annually thereafter, a wildfire mitigation plan. SB 901 requires the City to contract with a qualified independent evaluator to review and assess the comprehensiveness of its plan. The report of the independent evaluator is to be made available to the public and presented at a public meeting of the POU ’s governing board. AB 1054 requires, among other things, each POUs, such as the City, to submit, by July 1 of each year, its wildfire mitigation plan to the California Wildfire Safety Advisory Board for review and commission.

The City intends to continue to update and file its Wildfire Mitigation Plan to the California Wildfire Safety Advisory Board by June of each year.

50 A number of wildfires occurred in California in in the last several years. Under the doctrine of inverse condemnation (a legal concept that entitles property owners to just compensation if their property is damaged by a public use), California courts have imposed liability on utilities in legal actions brought by property holders for damages caused by such utilities’ infrastructure. Thus, if the facilities of a utility, such as its electric distribution and transmission lines, are determined to be the substa ntial cause of a fire, and the doctrine of inverse condemnation applies, the utility could be liable for damages without having been found negligent. In August 2019, in its decision in the case of City of Oroville v. Superior Court of Butte County, No. S243247 (Cal. Aug. 15, 2019) involving damages related to sewage overflows from a city sewer system, the California Supreme Court issued a rare but narrow decision regarding inverse condemnation liability. The residential property owner in that case failed to install a mandatory sewer backflow device, allowing the court to conclude the absence of that device was the substantial cause of the damages to the residence. The property owner was unable to prove the property damage was the probable result or necessary effect of an inherent risk associated with the design, construction or maintenance of the relevant public improvements. SB 1028, SB 901 and AB 1054 do not address existing legal doctrine relating to utilities’ liability for wildfires. How any future legis lation addresses the State’s inverse condemnation and “strict liability” issues for utilities in the context of wildfires in particular is not certain at this time but could be significant for the electric utility industry, including PWP.

Future Regulation
The electric industry is subject to continuing legislative, regulatory and administrative reform. States routinely consider changes to the way in which they regulate the electric industry. Historically, both further deregulation and forms of additional regulation have been proposed for the industry, which has been highly regulated throughout its history. While there is no current proposal to further deregulate the industry, there still are additional regulations or legislative mandates being proposed o r considered for the industry such as higher reliance on renewable energy and tighter regulations for greenhouse gas emission reductions. The City is unable to predict at this time the impact any such proposals will have on the operations and finances of the Electric System or the electric utility industry generally.

Impact of Developments on the City
The effect of the developments in the California energy markets described above on the Electric System cannot be fully ascertained at this time. Also, volatility in energy prices in California may return due to a variety of factors that affect both the supply and demand for electric energy in the western United States. The Aliso Canyon storage issues, the SB 100 goal of a carbon neutral economy by 2045, coupled with the pending closure of once through cooling units, will impact the electric industry in the years to come. Mandates to force procurement (energy storage, wind, etc.) will also continue to impact the electric industry. Additional factors include, but are not limited to, the adequacy of generation resources to meet peak demands, the availability and cost of renewable energy, the impact of economy-wide greenhouse gas emission legislation and regulations, fuel costs and availability, weather effects on customer demand, transmission congestion, the strength of the economy in California and surrounding states and levels of hydroelectric generation within the region (including the Pacific Northwest). See “OTHER FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY.”

OTHER FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY
Federal Policy on Cybersecurity
On February 13, 2013, then President Obama issued the Executive Order “ Improving Critical Infrastructure Security ” (“Executive Order ”). Among other things, the Executive Order calls for improved information sharing and processing of security clearances for owners and operators of critical infrastructure. The Executive Order further requires the Secretary of Commerce to direct the National Institute o f Standards and Technology (“NIST”) to lead the development of a framework ( “Framework”) to reduce cyber risks to critical infrastructure. NIST released the first version of the voluntary Framework on February 12, 2014. NIST has indicated that it intends for the Framework to be a living document that will continue to be updated and improved

51 as industry provides feedback on implementation. NIST posted the second draft of the proposed update in December 2017 and finalized the second version in April 2018.

The Cybersecurity Information Sharing Act of 2015 was signed into law on December 18, 2015 as part of the year -end Omnibus Appropriations Act. It creates an industry- supported, voluntary cybersecurity information sharing program that will encourage both public and private sector entities to share cyber -related threat information.

In September 2018, the White House released its “2018 National Cybersecurity Strategy,” which sought to update the nation’s cybersecurity strategy. FERC has also sought to expand reporting rules for incidents involving attempts to compromise operation of the electric grid and address supply chain cybersecurity risks.

On November 16, 2018, then President Trump signed into law the Cybersecurity and Infrastructure Security Agency Act of 2018. This landmark legislation elevates the mission of the former National Protection and Programs Directorate within Department of Homeland Security and establishes the Cybersecurity and Infrastructure Security Agency (“CISA”). CISA builds the national capacity to defend against cyber-attacks and works with the federal government to provide cybersecurity tools, incident response services and assessment capabilities to safeguard the ‘ .gov’ networks that support the essential operations of partner departments and agencies.

In March of 2023, the Biden administration adopted the “2023 National Cybersecurity Strategy.” The 2023 National Cybersecurity Strategy replaces but continues momentum on many of the priorities of the 2018 National Cybersecurity Strategy.

Federal Energy Legislation
Energy Policy Act of 1992. The Energy Policy Act of 1992 (the “EPAct of 1992”) made fundamental changes in federal regulation of the electric utility industry, particularly in the area of transmission access under sections 211, 212, and 213 of the FPA, 16 U.S.C. Section 791(a) et seq. The purpose of these changes in part was to bring about increased competition among wholesale suppliers. As amended, sections 211, 212 and 213 authorize FERC to compel a transmission provider to provide transmission service upon application by an electricity supplier. FERC’s authority includes the authority to compel the enlargement of transmission capacity as necessary to provide the service. The service must be provided at rates, charges , terms and conditions that are set by FERC.

Electric utilities that are owned by municipalities or other public agencies are “transmitting utilities” that may be subject to an order under sections 211, 212, and 213. EPAct of 1992 prohibits FERC from requiring “retail wheeling” under which a retail customer that was located in one utility’s service area could obtain electricity from another source. An order by FERC to provide transmission might adver sely affect the PWP’s system by, and among other things, increasing the PWP’s cost owning and operating transmission facilities and/or by reducing the availability of the PSP’s transmission resources for the PWP’s own use.

Energy Policy Act of 2005 . Under the federal Energy Policy Act of 2005 ( “EPAct 2005”), FERC was given refund authority over POUs if they sell into short -term markets, like the CAISO markets, and sell eight million MWhs or more of electric energy on an annual basis. In addition, FERC wa s given authority over the behavior of market participants. Under FERC ’s authority it can impose penalties on any seller for using a manipulative or deceptive device, including market manipulation, in connection with the purchase or sale of energy or of transmission service. The Commodity Futures Trading Commission also has jurisdiction to enforce certain types of market manipulation or deception claims under the Commodity Exchange Act.

EPAct 2005 authorized FERC to issue permits to construct or modify transmission facilities located in a national interest electric transmission corridor if FERC determines that the statutory conditions are met. EPAct 2005 also required the creation of an electric reliability organization ( “ERO”) to establish and enforce, under FERC supervision, mandatory reliability standards ( “Reliability Standards”) to increase system reliability and

52 minimize blackouts. Failure to comply with such Reliability Standards exposes a utility to significant fines and penalties by the ERO.

NERC Reliability Standards. EPAct 2005 required FERC to certify an ERO to develop mandatory and enforceable Reliability Standards, subject to FERC review and approval. The Reliability Standards apply to users, owners and operators of the Bulk-Power System, as more specifically set forth in each Reliability Standard. On February 3, 2006, FERC issued Order 672, which certified the North American Electric Reliability Corporation (“NERC”) as the ERO. Many Reliability Standards have since been approved by FERC. Such standards pertain not only to the planning, operations, and maintenance of Bulk-Power System facilities, but also to the cyber and physical security of certain critical facilities.

The ERO or the entities to which NERC has delegated enforcement auth ority through an agreement approved by FERC (“Regional Entities”), such as the Western Electricity Coordinating Council, may enforce the Reliability Standards, subject to FERC oversight, or FERC may independently enforce them. Potential monetary sanctions include fines of up to $1 million per violation per day. FERC Order 693 further provided the ERO and Regional Entities with the discretion necessary to assess penalties for such violations, while also having discretion to calculate a penalty without collecting the penalty if circumstances warrant.

Federal Regulation of Transmission Access
EPAct 2005 authorizes FERC to compel “open access” to the transmission systems of certain utilities that are not generally regulated by FERC, including municipal utilities if the utility sells more than four million MWhs of electricity per year. Under open access, a transmission provider must allow all customers to use the system under standardized rates, terms and conditions of service.

FERC Order No. 888 requires the provision of open access transmission services on a nondiscriminatory basis by all “ jurisdictional utilities” (which, by definition, does not include municipal entities like the City) by requiring all such utilities to file Open Access Transmission Tariffs ( “OATTs”). Order No. 888 also requires “non-jurisdictional utilities” (which, by definition, does include the City) that purchase transmission services from a jurisdictional utility under an open access tariff and that owns or controls transmission facilities to provide open access service to the jurisdictional utility under terms that are comparable to the service that the non-jurisdictional utility provides itself. Section 211A of the EPAct 2005 authorizes, but does not require, FERC to order unregulated transmission utilities to provide transmission services. Specifically, FERC may require an unregulated transmitting utility to provide access to their transmission facilities (1) at rates that are comparable to those that the unregulated transmitting ut ility charges to itself; and (2) on terms and conditions (not relating to rates) that are comparable to those under which the unregulated transmitting utility provides transmission services to itself that are not unduly discriminatory or preferential.

On February 16, 2007, FERC issued Order 890, which concluded that reform of its pro forma OATT was necessary to reduce the potential for undue discrimination and provide clarity in the obligations of transmission providers and customers. Significantly, in O rder 890 FERC stated that it will implement its authority under Section 211A with respect to unregulated transmitting utilities on a case -by-case basis and retain the current reciprocity provisions.

On July 21, 2011, FERC issued Order 1000, which among other things requires public utility (jurisdictional) transmission providers to participate in a regional transmission planning process that produces a regional transmission plan and that incorporates a regional and inter -regional cost allocation methodology.

Further, FERC states that it has the authority to allocate costs to beneficiaries of transmission services, even in the absence of a contractual relationship between the owner of the transmission facilities and the beneficiary. Under EPAct 2005, FERC may not require municipal utilities to join regional transmission organizations, in which participating utilities allow an independent entity to oversee operation of the utilities ’ transmission facilities.

FERC has stated, however, that FERC expects such uti lities to participate in the regional processes for

53 transmission planning and that FERC will pursue associated complaints against such utilities on a case- by-case basis.

At its April 2022 meeting, FERC issued a Notice of Proposed Rulemaking (the “Notice”) that would, if adopted, result in reforms to the planning of the nation’s transmission system as well as the allocation of costs for new transmission projects. The Notice follows input FERC sought from interested parties on a variety of reforms aimed at expanding the nation’s transmission grid to accommodate the surge of renewable generation expected in the next two decades to achieve aggressive decarbonization goals of the Biden administration and many states.

The Notice addresses reforms to transmission planning and cost allocation.

Other Federal Legislation
Congress has considered and is considering numerous bills addressing domestic energy policies and various environmental matters, including bills relating to energy supplies and development (such as a federal energy efficiency standard and expedited permitting for natural gas drilling projects), global warming and water quality. Many of these bills, if enacted into law, could have a material impact on the Electric System and the electric utility indust ry generally. In light of the variety of issues affecting the utility sector, federal energy legislation in other areas such as reliability, transmission planning and cost allocation, operation of markets and environmental requirements is also possible. However, the City is unable to predict the outcome or potential impacts of any possible legislation on the Electric System at this time.

Environmental Issues
General. Electric utilities are subject to continuing environmental regulation. Federal, State a nd local standards and procedures which regulate the environmental impact of electric utilities are subject to change. These changes may arise from continuing legislative, regulatory and judicial action regarding such standards and procedures. Consequently, there is no assurance that any City facility or project will remain subject to the laws and regulations currently in effect, will always be in compliance with future laws and regulations or will always be able to obtain all required operating permits. An inability to comply with environmental standards could result in additional capital expenditures, reduced operating levels or the shutdown of individual units not in compliance.

In addition, increased environmental laws and regulations may create certain barriers to new facility development, may require modification of existing facilities and may result in additional costs for affected resources.

Greenhouse Gas Regulations Under the Clean Air Act . The United States Environmental Protection Agency (the “EPA”) regulates GHG emissions under existing law by imposing monitoring and reporting requirements, and through its permitting programs. Like other air pollutants, GHGs are regulated under the Clean Air Act through the Prevention of Significant Deterioration ( “PSD”) Permit Program and the Title V Permit Program. A PSD permit is required before commencement of construction of new major stationary sources or major modifications of a major stationary so urce and requires best available control technologies to control emissions from the new or modified stationary source. Title V permits are operating permits for major sources that consolidate all Clean Air Act requirements (arising, for example, under the Acid Rain, New Source Performance Standards, National Emission Standards for Hazardous Air Pollutants, and/or PSD programs) into a single document and the permit process provides for review of the documents by the EPA, state agencies and the public. GHGs from major natural gas -fired facilities are regulated under both permitting programs through performance standards imposing efficiency and emissions standards.

On October 23, 2015, the EPA, under the Obama a dministration, published the Clean Power Plan and final regulations for (1) carbon pollution standards for new, modified, and reconstructed power plans, and (2) carbon pollution emission guidelines for existing electricity utility generating units. The total national emissions reduction goal under the Clean Power Plan targeted an average of a 32 percent reduction from 2005 levels by 2030, with incremental interim goals for the years 2022 through 2029. The Clean Power Plan would have allowed states multiple options for measuring reductions and different established reduction goals depending upon the regulatory program set forth in the state plan. On July 8, 2019, the EPA issued final new regulations entitled the

54 “Affordable Clean Energy Rule” to replace the Clean Power Plan. On January 19, 2021, upon a challenge by a number of environmental advocates, state and municipal attorneys, and a coalition, the D.C. Circuit vacated the Affordable Clean Energy Rule. Moreover, on October 29, 2021, the U.S. Supreme Court granted certiorari to hear challenges to EPA ’s authority to regulate GHGs emissions from power plants. On June 30, 2022, the U.S.

Supreme Court denied the EPA the authority to create emissions caps, stating that Congress must provide specific direction to the EPA, instead of a broad scope of power, for the agency to regulate GHGs emissions. On May 11, 2023, the EPA announced proposed new carbon pollution standards for coal and gas -fired power plants. The proposals would set limits for new gas-fired combustion turbines, existing coal, oil and gas-fired steam generating units, and certain existing gas -fired combustion turbines. The EPA is simultaneously proposing to repeal the Affordable Clean Energy Rule. At this time, PWP is unable to predict what the final rules will contain or the impact they may have on the operations and finances of the Electric System.

In the meantime, the State of California has moved forward with its plans to reduce GHG emissions. In 2016, the Legislature passed SB 32, which codifies a 2030 GHG emissions reduction target of 40 percent below 1990 levels. With SB 32, the Legislature passed companion legislation AB 197, which provides additional direction for developing the Scoping Plan. CARB is moving forward with a second update to the States Climate Change Scoping Plan to reflect the 2030 target set by Executive Order B -30-15 and codified by SB 32. See “DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS – State Legislation – Greenhouse Gas Emissions – Global Warming Solutions Act.”
Air Quality – National Ambient Air Quality Standards . The Clean Air Act requires that the EPA establish National Ambient Air Quality Standards ( “NAAQS”) for certain air pollutants. When a NAAQS has been established, each state must identify areas in its state that do not meet the EPA standard (known as “ non- attainment areas”) and develop regulatory measures in its state implementation plan to reduce or control the emissions of that air pollutant in order to meet the applicable standard and become an “attainment area.” The EPA periodically reviews the NAAQS for various air pollutants and has in recent years increased, or proposed to increase, the stringency of the NAAQS for certain air pollutants.

In 2014, the U.S. Supreme Court found in its review of EPA v. EME Homer City Generation, LP that the EPA has the authority to impose a Cross -State Air Pollution Rule which curbs air pollution emitted in upwind states to facilitate downwind attainment of three NAAQs.

The EPA revised the NAAQS for particulate matter on December 14, 2012, the NAAQS for sulfur dioxide on June 22, 2010, and the NAAQS for nitrogen dioxide on February 9, 2010, and in each case made them more stringent. On December 18, 2014, the EPA issued a final rule making initial area designations for the 2012 NAAQS for fine particulate matter (“PM2.5”), designating 14 areas in six states as non-attainment, including the Los Angeles South Coast Air Basin, CA effective on April 15, 2015. On October 1, 2015, the EPA lowered the ozone standard to 70 ppb effective December 28, 2015. On June 4, 2018 they published a final rule initially designating some areas and voluntarily reclassifying five of six nonattainment areas in California, including the Los Angeles – South Coast Air Basin. This reclassification ensures that these five areas will have an attainment date for the 2015 ozone NAAQS that is no earlier than the areas attainment date for the prior 2008 ozone NAAQS.

California declined reclassification for the Sacramento Metro area only. These dev elopments may result in stringent permitting processes for new sources of emissions and additional state restrictions on existing sources of emissions, such as power plants.

In 2020, the EPA announced a proposed decision to retain the existing 70 ppb ozone standard. The decision was finalized on December 7, 2020. In August 2023, the EPA announced a new review of ozone NAAQS to support consideration of new information and advice.

On June 10, 2021, the EPA announced that it will reconsider the previous admini stration’s decision to retain the particulate matter NAAQS, which were last strengthened in 2012. The EPA stated that it is reconsidering the previous administration’s December 2020 decision to retain existing standards because available scientific evidence and technical information indicate that the current standards may not be adequate to protect public health

55 and welfare, as required by the Clean Air Act. While some particulate matter is emitted directly from sources such as construction sites, unpaved roads, fields, smokestacks or fires, most particles form in the atmosphere as a result of complex reactions of chemicals such as sulfur dioxide and nitrogen oxides, which are pollutants emitted from power plants and other sources. On February 7, 2024, the EPA strengthened the NAAQS for particulate matter to protect Americans from harmful and costly health impacts, such as heart attacks and premature death. EPA is setting the level of the primary (health-based) annual PM2.5 standard at 9.0 micrograms per cubic meter to provide increased public health protection, consistent with the available health science. The EPA is also revising the Air Quality Index to improve public communications about the risks from PM2.5 exposures and making changes to the monitoring network to enhance protection of air quality in communities overburdened by air pollution.

Mercury and Air Toxics Standards . On December 16, 2011, the EPA signed a rule establishing new standards to reduce air pollution from coal- and oil-fired power plants under sections 111 (new source performance standards and 112 (toxics program) of the Clean Air Act. The final rule was published in the Federal Register on February 16, 2012. The EPA updated the Mercury and Air Toxics Standards ( “MATS”) emission limits on November 30, 2012 and again on March 28, 2013. Under section 111 of the Clean Air Act, MATS revised the standards that new and modified facilities, including coal - and oil-fired power plants, must meet for particulate matter, sulfur dioxide, and nitrogen oxide. Under section 112, MATS sets toxics standards limiting emissions of heavy metals, including mercury, arsenic, chromium, and nickel; and acid gases, including hydrochloric acid and hydrofluoric acid, from existing and new power plants larger than 25 MW that burn coal or oil. Power plants have up to four years to meet these standards. While many plants already meet some or all of these new standards, some plants will be required to install new equipment to meet the standards. On November 25, 2014, the U.S.

Supreme Court agreed to review the MATS rule following the filing of petitions for writ of certiorari from 23 states and industry groups. On June 29, 2015, the U.S. Supreme Court issued its decision in the case, finding that the EPA interpreted the Clean Air Act improperly because it did not consider the costs of emissions reductions prior to crafting the MATS rules, and remanded the case back to the District of Columbia Circuit Court. On December 15, 2015, the District of Columbia Circuit Court determined to leave the MATS rule in place while it was being revised on remand as ordered by the U.S. Supreme Court. The EPA issued a final finding on April 14, 2016. On March 3, 2016, the U.S. Supreme Court denied an application filed by several s tates to stay the rule during the litigation. On December 27, 2018, EPA proposed to revise the supplemental cost finding for the MATS rule, as well as the Clean Air Act ’s required “risk and technology review.” After evaluating projected costs to coal- and oil-fired power plants of complying with the MATS rule, and the benefits attributable to regulating hazardous air pollutant (“HAP”) emissions from such power plants (as directed by the Supreme Court, Michigan v. EPA), EPA proposed that it is not “appropriate and necessary” to regulate HAP emissions from power plants under Section 112 of the Clean Air Act. Under the EPA proposal, the emission standards and other requirements of the MATS rule (from 2012) would remain in place since EPA did not propose to re move coal- and oil-fired power plants from the list of sources that are regulated under Section 112 of the Act. The City currently purchases power from coal-fired power stations that may be affected by the regulations, and in the event the MATS standards are ultimately upheld, the City may be exposed to increased costs. However, under the City ’s 2018 Power Integrated Resource Plan ( “2018 Power IRP”), the City determined to remove coal from its power portfolio by June 2027, potentially as early as 2025.

In April 2023, the EPA published its proposed rule entitled “National Emission Standards for Hazardous Air Pollutants: Coal - and Oil-Fired Electric Utility Steam Generating U nits Review of the Residual Risk and Technology Review.” The proposed rule establishes a lower mercury emissions standard for lignite coal, which does not apply to IPP. The rule also proposes to reduce the emissions standards for filterable particular matt er (“fPM”) from 0.03 lb/MMBtu to 0.01 lb/MMBtu. In addition, it requires the owners and operators of existing coal-fired plants to only use a continuous emissions monitoring system to demonstrate compliance with the new fPM standards.

Regulation of Coal C ombustion Residuals . On June 21, 2010, the EPA proposed to regulate coal combustion residuals ( “CCR”) such as ash. The EPA proposed to list these residuals as a special waste and regulate them as a hazardous waste. This would have required a federal or state permitting program covering the storage, treatment, transport, disposal, and other activities related to residuals. The EPA also proposed an

56 alternative regulation that would classify residuals as nonhazardous solid waste. Under the alternative regulation, plants could dispose of residuals in surface impoundments or landfills if they comply with national minimum standards. The disposal standards would address location, liner requirements, groundwater monitoring and other issues, but permits would n ot be required under the alternative regulation. The EPA solicited additional public comments on its proposed coal combustion residual regulation on October 12, 2011 and again on August 2, 2013.

The EPA released its final CCR rule on December 19, 2014, adopting the industry-preferred alternative regulation classifying CCRs as nonhazardous solid waste. These requirements have been finalized under the solid waste provisions, subtitle D, of the Resource Conservation and Recovery Act and became effective in October 2015.

Under the CCR rule, existing impoundments for managing CCR must either cease accepting CCR materials as of the rule’s effective date, or implement a variety of measures to ensure that such facilities will not result in release to the environment. One such requirement is that all such facilities be retrofitted with liners that are intended to prevent mitigation to groundwater of contaminates found in CCR. In addition, the rule requires monitoring of groundwater to determine whether releases have occurred and to contain or clean up any such releases that are discovered.

The IPP utilizes impoundments (ponds and landfills) for the management of CCR that are subject to the CCR rule. The IPP has met all interim compliance requirements for the new CCR rule including setting up a public website and posting CCR operating records, developing new groundwater monitoring wells and sampling plans, beginning to sample groundwater wells quarterly, and developing and implementing a fugitive dust monitoring plan.

The PWP believes that the IPP’s CCR management facilities may not meet the design criteria required for surface impoundments and that releases of certain contaminants have occurred form current unlined impoundments. The PWP understands that IPA has made notification that IPP will cease operations of the coal - fired boilers and switch to another fuel source for generation by 2028.

The PWP has estimated the IPP’s total cost of compliance with the final CCR rule to fall within the range of $55 million to $70 million in over a time period commencing in 2019 and ending between approximately 2025 and 2028 (except for long -term monitoring and maintenance, which would last approximately 30 years after closure). Of this total cost, the Electric System would be resp onsible for a percentage equal to its total use of energy produced by IPP.

In November 2019, the EPA proposed revisions (Part A) to the CCR rule. The proposed revisions focused on closure requirements for impoundments and landfills. IPA is opting to compl y with the alternative closure requirements as currently described in the current CCR rule. The proposed revisions include additional requirements to get approval for the EPA or the state to close impoundments in accordance with alternate closure procedures. There is also a new requirement to prepare a plan to mitigate potential risk to human health and environment from CCR surface impoundments. The Part A revisions were finalized and published in the Federal Register in August 2020. IPP has submitted a request to the EPA demonstrating that they meet the alternate closure procedures as described in the regulations. IPP is awaiting EPA review and approval which was initial expected to be received by April 2021; however, as of April 2024, the EPA has not yet m ade a determination in I PP’s demonstration submission.

In February 2020, the EPA proposed a federal CCR permit program. Currently, the CCR rule is self - implementing and is enforced primarily through citizen suits which are deiced in federal district court s. This program will not change the provisions of the regulations but the EPA will be able to review, approve, issue and enforce the CCR regulations through the permit program.

In March 2020, the EPA proposed more revisions (Part B) to the CCR rule includi ng provisions to demonstrate equivalent alternate liners, using CCR for closing impoundments, and completion of closure by removal during post closure care period. The proposed revisions do not impact IPA’s plan to follow alternate closure requirements.

57 Effluent Limitations Guidelines and Standards. On June 7, 2013, the EPA proposed to set technology- based effluent limitations guidelines and standards for metals and other pollutants in wastewater discharged from steam electric power plants. The proposal covered wastewater associated with several types of equipment and processes, including flue gas desulfurization, fly ash, bottom ash, flue gas mercury control and gasification of fuels. The EPA also considered best management practices for surface impound ments containing CCRs. The EPA proposed four preferred alternatives for regulating wastewater discharges. The stringency of controls, types of waste streams covered, and the costs vary between the four alternatives. On September 30, 2015, the EPA announced its final Steam Electric Effluent Limitation Guidelines to update the federal limits on toxic metals in discharge wastewater (the “Guidelines”). On October 13, 2020, the EPA revised the Guidelines for two waste streams: flue gas desulfurization ( “FGD”) wastewater and bottom ash transport water; revised the voluntary incentives program for FGD wastewater; added subcategories; and established new compliance dates.

The City currently purchases power from coal-fired power stations that may be affected by the regulations described above; compliance with such rules could therefore result in an increase in the cost of power that the City purchases from such units. However, as stated earlier, under the City’s 2018 Power IRP, the City determined to remove coal from its power portfolio by June 2027, potentially as early as 2025.

Global Health Emergencies; COVID-19 Pandemic
A pandemic, epidemic or outbreak of an infectious disease can have significant adverse health and financial impacts on global and local economi es. For example, beginning in 2020, the COVID -19 pandemic negatively affected economic activity throughout the world, including the United States and the State of California. The initial impacts of stay -at home orders globally was unprecedented with commer ce, travel, asset values and financial markets experiencing disruptions worldwide. The COVID-19 pandemic impacted PWP in certain respects, however there was not a material adverse impact to PWP’s operations or its ability to meet its financial obligations as a result of the COVID -19 pandemic. Certain employees of the PWP systems are considered essential workers and were exempt from the “stay at home” and “safer at home” orders issued by the State, the County and the City, and therefore, PWP continued to ful ly provide services to its customers through the pandemic. The declarations of the COVID -19 pandemic as a public health emergency have been lifted.

However future pandemics and other widespread public health emergencies can and do arise from time to time.

No assurance can be given that the operations or finances of the PWP will not be negatively affected in the event that the pandemic and its consequences again become more severe or another national or localized outbreak of highly contagious or epidemic disease occurs in the future.

Other Factors
The electric utility industry in general has been, or in the future may be, affected by a number of other factors which could impact the financial condition and competitiveness of many electric utilities and the level of utilization of generating and transmission facilities. In addition to the factors discussed above, such factors include, among others, (a) effects of compliance with rapidly changing environmental, safety, licensing, regulatory and legislative requirements other than those described above (including those affecting nuclear power plants or potential new energy storage requirements), (b) changes resulting from conservation and demand- side management programs on the timing and use of electric energy, (c) effects on the integration and reliability of the power supply from the increased usage of renewables, (d) changes resulting from a national energy policy, (e) effects of competition from other electric utilities (including increased competition resulting from a movement to allow direct access or from mergers, acquisitions, and “strategic alliances” of competing electric and natural gas utilities and from competitors transmitting less expensive electricity from much greater distances over an interconnected system) and new methods of, and new facilities for, producing low -cost electricity, (f) the repeal of certain federal statutes that would have the effect of increasing the competitiveness of many IOUs, (g) increased competition from independent power producers and marketers, brokers and federal power marketing agencies, (h) “self-generation” or “distributed generation” (such as microturbines and fuel cells) by industrial and commercial customers and others, (i) issues relating to the ability to issue tax-exempt obligations, including severe restrictions on the ability to sell to nongovernmental entities electricity from generation projects and transmission service

58 from transmission line projects financed with outstanding tax -exempt obligations, (j) effect s of inflation on the operating and maintenance costs of an electric utility and its facilities, (k) changes from projected future load requirements, (l) increases in costs and uncertain availability of capital, (m) shifts in the availability and relative costs of different fuels (including the cost of natural gas and nuclear fuel), (n) financial difficulties, including bankruptcy, of fuel suppliers and/or renewable energy suppliers, (o) sudden and dramatic increases in the price of energy purchased on the open market that may occur in times of high peak demand in an area of the country experiencing such high peak demand, such as has occurred in California, (p) inadequate risk management procedures and practices with respect to, among other things, the purc hase and sale of energy and transmission capacity, (q) other legislative changes, voter initiatives, referenda and statewide propositions, (r) effects of the changes in the economy, population and demand of customers in the PWP’s service area, (s) effects of possible manipulation of the electric markets, (t) natural disasters or other physical calamities, including, but not limited to, earthquakes and floods, (u) terrorist attacks and (v) changes to the climate, (w) outbreak of another infectious disease such as the COVID -19 pandemic impacting the global, national, or local economy or a utility’s service area, (x) natural disasters or other physical calamities, including but not limited to, earthquakes, floods, and wildfires, and potential liabilities of electric utilities in connection therewith, (y) adverse impacts to the market of insurance relating to wildfires and other calamities leading to higher cost or prohibitive or expensive coverage, or limited or unavailability of coverage for certain types of ri sk, and (z) legislation of court actions allowing City residents and/or businesses to purchase power from sources outside the PWP. Any of these factors (as well as other factors) could have an adverse effect on the financial condition of any given electri c utility and likely will affect individual utilities in different ways.

The City is unable to predict what impact such factors will have on the business operations and financial condition of the Electric System, but the impact could be significant. This Official Statement includes a brief discussion of certain of these factors. This discussion does not purport to be comprehensive or definitive, and these matters are subject to change subsequent to the date hereof. Extensive information on the electric utility industry is available from the legislative and regulatory bodies and other sources in the public domain, and potential purchasers of the 2024A Bonds should obtain and review such information.

CONSTITUTIONAL LIMITATIONS IN CALIFORNIA AFFECTING FEES AND CHARGES

IMPOSED BY THE CITY
The following is a discussion of certain limitations under provisions of the California Constitution that may affect the rates, fees and charges imposed by the City for the electric services it provides.

Proposition 218 and Proposition 26
Proposition 218, a State ballot initiative known as the “Right to Vote on Taxes Act,” was approved by the voters of the State of California on November 5, 1996. Proposition 218 added Articles XIIIC and XIIID to the State Constitution. Article XIIIC imposes a majority voter approval requirement on local governments (including the City) with respect to taxes for general purposes, and a two -thirds voter approval requirement with respect to taxes for special purposes. Article XIIID creates additional requirements for the imposition by most local governments of general taxes, special taxes, assessments and “property-related” fees and charges. Article XIIID explicitly exempts fees for the provision of electric service from the provisions of such article.

Article XIIIC expressly extends the people’ s initiative power to the reduction or repeal of l ocal taxes, assessments, and fees and charges imposed prior to its effective date (November 1996). The California Supreme Court held in Bighorn-Desert View Water Agency v. Verjil, 39 Ca1.4th 205 (2006) that, under Article XIIIC, local voters by initiative may reduce a public agency ’s water rates and delivery charges, as those are property- related fees or charges within the meaning of Article XIIID, and noted that the initiative power described in Article XIIIC may extend to a broader category of fees and ch arges than the property- related fees and charges governed by Article XIIID. Moreover, in the case of Bock v. City Council of Lompoc, 109 Cal.App.3d 52 (1980), the Court of Appeal determined that an electric rate ordinance was not subject to the same const itutional restrictions that are applied to the use of the initiative process for tax measures so as to render it an improper subject of the initiative

59 process. Thus, electric service charges (which are expressly exempted from the provisions of Article XIIID) may be subject to the initiative provisions of Article XIIIC, thereby subjecting such fees and charges to reduction by the electorate. The Authority believes that even if the electric rates of the City are subject to the initiative power, under Article XIIIC or otherwise, the electorate of the City would be precluded from reducing its electric rates and charges in a manner materially and adversely affecting the payment of the 2024A Bonds by virtue of the “impairment of contracts clause” of the United States Constitution.

The California electorate approved Proposition 26 at the November 2, 2010 election, amending Article XIIIC of the California Constitution. Proposition 26 was designed to supplement tax limitations California voters adopted when they approved Proposition 13 in 1978, and Proposition 218 in 1996. Proposition 26 applies by its terms to any levy, charge or exaction imposed, increased or extended by a local government on or after November 3, 2010. Proposition 26 deems any such levy, charge or fe e to be a “tax”, requiring voter approval under Article XIIIC unless it comes within one of the listed exceptions. Proposition 26 expressly excludes from its definition of a “tax,” among other things, a “charge imposed for a specific government service or product provided directly to the payor that is not provided to those not charged, and which does not exceed the reasonable costs to the local government of providing the service or product.” Proposition 26 is applicable to the electric rates of governmental entities such as the City; therefore, newly adopted rates must conform to its requirements.

Proposition 26 is subject to interpretation by California courts, including the extent to which it is applicable to pre-existing electric rates and general fund transfers. A number of lawsuits have been filed against public agencies in California relating to electric utility fund transfers. In Citizens for Fair REU Rates v. City of Redding (filed on January 20, 2015 and modified on February 19, 2015), for example, the California Court of Appeal considered a ratepayer challenge to a “payment in lieu of taxes ” (or “PILOT”) required by the City of Redding to be made by its electric utility as an annual budgetary transfer amount without voter approval. The city’s PILOT was designed to compensate the general fund for the costs of services that other city departments provide to the electric utility. The amount of the PILOT was equivalent to the ad valorem taxes the electric utility would have had to pay if the electric uti lity were privately owned. The suits alleged that the PILOT was passed through to the city’s electric utility customers as part of the rates and charges for electric service in excess of the reasonable costs to the city of providing electric service. The Court of Appeal determined that Proposition 26 has no retroactive effect as to local taxes that existed prior to November 3, 2010, but found that since the PILOT was subject to the City Council’s recurring discretion, the PILOT did not escape the purview of Proposition 26. The Court of Appeal concluded that the PILOT constituted a “tax” under Proposition 26 for which the city must secure voter approval unless the city proved that the amount collected was necessary to cover the reasonable costs to the city of providing electric service. On April 29, 2015, the California Supreme Court granted review of the decision of the Court of Appeal. The California Supreme Court rendered its decision on August 27, 2018, reversing the judgment of the Court of Appeal. The California Supreme Court determined that the budgetary transfer from the Redding electric utility to the city’s general fund, calculated by using the PILOT, itself is not the type of exaction that is subject to Article XIIIC of the California Constitution. The court reasoned that it is only the Redding electric utility rate, not the PILOT, that is imposed on customers for electric service. The California Supreme Court concluded that because the total rate revenue of the electric utility was insufficient to cover the electric utility ’s uncontested operating expenses (other than the PILOT) in the years at issue, the challenged rate did not exceed the reasonable costs of providing electric service, and therefore did not constitute a tax.

The City is unable to predict at this time how Propositions 218 and 26 will ultimately be interpreted by the courts in the context of the Electric System rates or what the ultimate impact of Propositions 218 or 26 will be.

Future Initiatives
Articles XIIIC and XIIID and the amen dments effected thereto by Proposition 26 were adopted as measures that qualified for the ballot pursuant to California ’s initiative process. From time to time, including presently, other initiatives have been, and could be, proposed, and if qualified for the ballot, could be adopted

60 affecting the City and/or the City’s revenues or operations. Neither the nature and impact of these measures nor the likelihood of qualification for ballot or passage can be predicted by the City.

A voter initiative entitled “The Taxpayer Protection and Government Accountability Act ” (“Initiative 1935”) was recently determined to be eligible for the November 2024 Statewide general election and, unless withdrawn by its proponent prior to June 27, 2024, will be certified as qualif ied for the ballot in such election.

Were it to be adopted by a majority of voters in the Statewide general election, Initiative 1935 would amend the California Constitution to, among other things, provide that charges for services or product provided dire ctly to the payor (such as charges for electricity) are “taxes” subject to voter approval unless the local government can prove by clear and convincing evidence that the charge is reasonable and does not exceed the “ actual cost” of providing the service or product, defined as “(i) the minimum amount necessary to reimburse the government for the cost of providing the service or the product to the payor and (ii) where the amount charged is not used by the government for any purpose other than reimbursing that cost.” If adopted, Initiative 1935 would be subject to judicial interpretation. The City is unable to predict whether and how Initiative 1935, if adopted, would be interpreted by the courts, and there can be no assurance that any such interpretation or application would not have an adverse impact on the City, the Electric System or the revenues of the Electric System.

RATINGS
Fitch Ratings, Inc. and S&P Global Ratings have assigned their municipal bond ratings of “ ____” and “____,” respectively, to the 2024A Bonds. Such ratings reflect only the views of such organizations and any desired explanation of the significance of such ratings may be obtained from the rating agency furnishing the same, at the following addresses: Fitch Ratings, Inc., One State Street Plaza, New York, New York 10004; and S&P Global Ratings, 55 Water Street, New York, New York 10041. Generally, a rating agency bases its rating on the information and materials furnished to it and on investigations, studies and assumptions of its own. There is no assurance that any of such ratings will continue for any given period of time or that such ratings will not be revised downward or withdrawn entirely by the applicable rating agency, if in the judgment of such rating agency circumstances so warrant. Any such downward revision or withdrawal of such ratings may have an adverse effect on the 2024A Bonds.

TAX MATTERS
Federal Income Taxes
In the opinion of Bond Counsel, based upon an analysis of existing laws, regulati ons, rulings and court decisions, and assuming, among other matters, compliance with certain covenants, interest on the 2024A Bonds is excluded from gross income for federal income tax purposes under Section 103 of the California Revenue and Taxation Code (the “Code”) and is exempt from State of California personal income taxes. Bond Counsel is of the further opinion that interest on the 2024A Bonds is not a specific preference item for purposes of federal alternative minimum tax imposed on individuals and corporations, however, interest is taken into account in determining the annual adjusted financial statement income of certain corporations for the purpose of computing the alternative minimum tax imposed on certain corporations.

The Code imposes various restrictions, conditions and requirements relating to the exclusion from gross income for federal income tax purposes of interest on obligations such as the 2024A Bonds. The City has covenanted to comply with certain restrictions designed to ensure that i nterest on the 2024A Bonds will not be included in federal gross income. Failure to comply with these covenants may result in interest on the 2024A Bonds being included in federal gross income, possibly from the date of original issuance of the 2024A Bonds.

The opinion of Bond Counsel assumes compliance with these covenants. Bond Counsel has not undertaken to determine (or to inform any person) whether any actions taken (or not taken) or events occurring (or not occurring) after the date of issuance of t he 2024A Bonds may adversely affect the value of, or the tax status of interest on, the 2024A Bonds.

61 Current and future legislative proposals, if enacted into law, clarification of the Code or court decisions may cause interest on the 2024A Bonds to be sub ject, directly or indirectly, to federal income taxation or to be subject to or exempted from state income taxation, or otherwise prevent Owners from realizing the full current benefit of the tax status of such interest. For example, legislative proposals are announced from time to time which generally would limit the exclusion from gross income of interest on obligations like the 2024A Bonds to some extent for taxpayers who are individuals and whose income is subject to higher marginal income tax rates.

Other proposals have been made that could significantly reduce the benefit of, or otherwise affect, the exclusion from gross income of interest on obligations like the 2024A Bonds. The introduction or enactment of any such legislative proposals, clarification of the Code or court decisions may also affect, perhaps significantly, the market price for, or marketability of, the 2024A Bonds. Prospective purchasers of the 2024A Bonds should consult their own tax advisors regarding any pending or proposed federal or state tax legislation, regulations or litigation, and regarding the impact of future legislation, regulations or litigation, as to which Bond Counsel expresses no opinion.

Certain requirements and procedures contained or referred to in the Fiscal Age nt Agreement, the tax certificate, and other relevant documents may be changed and certain actions (including, without limitation, defeasance of the 2024A Bonds) may be taken or omitted under the circumstances and subject to the terms and conditions set forth in such documents. Bond Counsel expresses no opinion as to the exclusion from gross income of interest on any 2024A Bond if any such change occurs or action is taken or omitted upon the advice or approval of counsel other than Best Best & Krieger LLP.

The Internal Revenue Services (“IRS”) has initiated an expanded program for the auditing of tax-exempt bond issues, including both random and targeted audits. It is possible that the 2024A Bonds will be selected for audit by the IRS. It is also possible that the market value of the 2024A Bonds might be affected as a result of such an audit of the 2024A Bonds (or by an audit of other similar bonds).

Although Bond Counsel is of the opinion that interest on the 2024A Bonds is excluded from gross income for federal income tax purposes and is exempt from State of California personal income taxes, the ownership or disposition of, or the accrual or receipt of interest on, the 2024A Bonds may otherwise affect an Owner’s federal or state tax liability. The nature and extent of these other tax consequences will depend upon the particular tax status of the Bond Owner or the Owner ’s other items of income or deduction, and Bond Counsel expresses no opinion regarding any such other tax consequences.

A copy of the proposed form of opinion of Bond Counsel is attached hereto as Appendix F.

LITIGATION
There is no litigation or action of any nature now pending against the City or, to the knowledge of its respective officers, threatened, seeking to restrain or enjoin the issuance, sale, execution or delivery of the 2024A Bonds or in any way contesting or affecting the validity of the 2024A Bonds or any proceedings of the City taken with respect to the issuance or sale thereof, or the pledge or application of any moneys or security provided for the payment of the 2024A Bonds or the use of proceeds thereof. There is no litigation pending, or to the knowledge of the City, threatened, questioning the existence of the City or the title of the officers of the City to their respective offices. There is no litigation pending, or to the knowledge of the City, threatened, which materially questions or affects the financial condition of the Electric System.

AUDITED FINANCIAL STATEMENTS
The audited financial statements of the City’s Water and Power Enterprise Funds, as of June 30, 2023 and for the year then ended, are included in Appendix B to this Off icial Statement. A complete copy of the City ’s Comprehensive Annual Financial Report may be obtained from the City. There has been no material adverse change in the finances of the Electric System since June 30, 2023. The 2024A Bonds are revenue obligations of the City payable only from the Net Income of the Electric System in the Light and Power Fund and certain other

62 funds as provided in the Fiscal Agent Agreement. The financial statements of the City ’s Water and Power Enterprise Funds for the Fiscal Y ear ended June 30, 2023 have been audited by Lance, Soll & Lunghard, LLP, independent accountants (the “Auditor”) as stated in their report appearing in Appendix B. The Auditor has not updated its report or taken any action intended or likely to elicit in formation concerning the accuracy, completeness or fairness of the statements made in this Official Statement, and no opinion is expressed by the Auditor with respect to any event or transaction subsequent to their report dated June 8, 2023. The City has not requested, nor has the Auditor given, the Auditor ’s consent to the inclusion in Appendix B of its report on such financial statements.

FORWARD-LOOKING STATEMENTS
The statements contained in this Official Statement and in the Appendices hereto, and in any other information provided by PWP or the City, that are not purely historical, are forward-looking statements, including statements regarding PWP or the City ’s expectations, hopes, intentions or strategies regarding the future.

Prospective investors s hould not place undue reliance on forward- looking statements. All forward- looking statements included in this Official Statement are based on information available to PWP and the City on the date hereof, and PWP and the City assume no obligation to update any such forward-looking statements. It is important to note that PWP’s actual results could differ materially from those in such forward-looking statements.

The forward-looking statements herein are necessarily based on various assumptions and estimates and are inherently subject to various risks and uncertainties, including risks and uncertainties relating to the possible invalidity of the underlying assumptions and estimates and possible changes or developments in social, economic, business, industry, market, legal and regulatory circumstances and conditions and actions taken or omitted to be taken by third parties, including customers, suppliers and competitors, and legislative, judicial and other governmental authorities and officials. Assumptions related to the foregoing involve judgments with respect to, among other things, future economic, competitive and market conditions and future business decisions, all of which are difficult or impossible to predict accurately and many of which are beyond the control of PWP and the City. Any of such assumptions could be inaccurate and, therefore, there can be no assurance that the forward - looking statements included in this Official Statement would prove to be accurate.

MUNICIPAL ADVISOR
The City has retained PFM Financial Advisors LLC, Los Angeles, California, as municipal advisor (the “Municipal Advisor”) in connection with the issuance of the 2024A Bonds. The Municipal Advisor has not been engaged, nor has it undertaken, to audit, authenticate or otherwise verify the information set forth in this Official Statement, or any other related information available to the City, with respect to accuracy and completeness of disclosure of such information. The Municipal Advisor has reviewed this Official Stat ement, but makes no guaranty, warranty or other representation respecting accuracy and completeness of the information contained in this Official Statement. Certain fees of the Municipal Advisor are contingent on the issuance and delivery of the 2024A Bonds

CERTAIN LEGAL MATTERS
The issuance of the 2024A Bonds is subject to the approving opinion of Best Best & Krieger LLP, Los Angeles, California, Bond Counsel. A complete copy of the proposed form of Bond Counsel opinion is contained in Appendix F. Bond Counsel will receive compensation from the City contingent upon the sale and delivery of the 2024A Bonds. Certain legal matters will be passed upon for the City by Michele Beal Bagneris, City Attorney of the City, and by Best Best & Krieger LLP, Los Angeles, California, Disclosure Counsel.

PURCHASE AND REOFFERING
____________ (the “Initial Purchaser”) purchased the 2024A Bonds from the City at a competitive sale at an aggregate purchase price of $___________ (representing the aggregate principal amount of t he 2024A

63 Bonds, plus original issue premium of $___________, and less an Initial Purchaser ’s discount of $_________).

The public offering prices may be changed from time to time by the Initial Purchaser. The Initial Purchaser may offer and sell 2024A Bonds to certain dealers and others at prices lower than the offering prices shown on the inside cover page hereof.

CONTINUING DISCLOSURE
Pursuant to a Continuing Disclosure Agreement to be entered into with Digital Assurance Certification, L.L.C. (“DAC”) simultaneously with the issuance of the 2024A Bonds (the “Continuing Disclosure Agreement”), under which the City has designated DAC as Disclosure Dissemination Agent (the “Disclosure Dissemination Agent”), the City has covenanted for the benefit of the holde rs and beneficial owners of the 2024A Bonds to provide certain financial information and operating data relating to the City and the Electric System by not later than 210 days following the end of the City ’s Fiscal Year (which Fiscal Year presently ends on June 30) (the “Annual Report”), commencing with the report for Fiscal Year 2023-24, and to provide notices of the occurrence of certain enumerated events. The Annual Report and the notices of specified events will be filed by the City with the MSRB through the MSRB’s EMMA System. The specific nature of the information to be contained in the Annual Report and the notice of specified events is set forth in APPENDIX E – “FORM OF CONTINUING DISCLOSURE AGREEMENT” herein. These covenants have been made in order to assist the Initial Purchaser in complying with SEC Rule 15c2- 12(b)(5) (the “Rule”). In the last five years, the City has not failed in any material respect to comply with any previous undertaking to provide continuing disclosure reports and notices of enumerated events pursuant to the provisions of the Rule.

The City will reserve the right to amend the Continuing Disclosure Agreement, and to obtain the waiver of non-compliance with any provision of the Continuing Disclosure Agreement, if such amendment or waiver is supported by a written opinion of counsel expert in federal securities laws selected by the City to the effect that such amendment or waiver would not materially impair the interest of the holders of the 2024A Bond and would not, in and of itself, cause the Continuing Disclosure Agreement to violate the Rule if such amendment or waiver had been effective at the time of the primary offering of the 2024A Bonds, after taking into account any applicable amendments to or official interpretations of the Rule.

The Disclosure Dissemination Agent has only the duties specified in the Continuing Disclosure Agreement. The Disclosure Dissemination Agent’s obligation to deliver the information at the times and with the contents described in the Continuing Disclosure Agreement is limited to the extent the City has provided that information to the Disclosure Dissemination Agent as required by the Continuing Disclosur e Agreement. The Disclosure Dissemination Agent has no duty with respect to the content of any disclosures or notice made pursuant to the terms of the Continuing Disclosure Agreement or duty or obligation to review or verify any information in the Annual Report, Audited Financial Statements, notice of Notice Event or Voluntary Report (all as defined in the Continuing Disclosure Agreement), or any other information, disclosure or notices provided to it by the City, and the Disclosure Dissemination Agent shall not be deemed to be acting in any fiduciary capacity for the City, the holders of the 2024A Bonds or any other party. The Disclosure Dissemination Agent has no responsibility for any failure to report to the Disclosure Dissemination Agent a Notice Event or a duty to determine the materiality thereof, as to determine or liability for failing to determine whether the City has complied with the Continuing Disclosure Agreement, and the Disclosure Dissemination Agent may conclusively rely upon certification of the City at all times.

The City has adopted policies and procedures to assist the City in complying with disclosure undertakings.

The City intends to amend its policies and procedures in response to two new event notices that were added effective February 27, 2019 to the list of events for which notice is required by the Rule.

64 EXECUTION AND DELIVERY
The execution and delivery of this Official Statement have been duly authorized by the City.

CITY OF PASADENA, CALIFORNIA
By:

Director of Finance

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APPENDIX A

THE CITY OF PASADENA

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APPENDIX B

AUDITED FINANCIAL STATEMENTS OF PASADENA WATER AND POWER ENTERPRISE FUNDS FOR THE FISCAL EAR ENDED JUNE 30, 2023

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APPENDIX C

BOOK ENTRY SYSTEM
The description that follows of the procedures and rec ordkeeping with respect to beneficial ownership interests in the 2024A Bonds, payment of principal of and interest on the 2024A Bonds to Participants or Beneficial Owners, confirmation and transfer of beneficial ownership interests in the 2024A Bonds, and other 2024A Bonds -related transactions by and between DTC, Participants and Beneficial Owners, is based on information furnished by DTC which the City believes to be reliable, but the City takes no responsibility for the completeness or accuracy thereof.

The Depository Trust Company (“DTC”), New York, New York, will act as securities depository for the 2024A Bonds (the “2024A Bonds”). The 2024A Bonds will be issued as fully-registered securities registered in the name of Cede & Co. (DTC’s partnership nominee) or such other name as may be requested by an authorized representative of DTC. One fully-registered security bond will be issued for each maturity of the 2024A Bonds, each in the aggregate principal amount of such maturity, and will be deposited with DTC.

DTC, the world’s largest securities depository, is a limited -purpose trust company organized under the New York Banking Law, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the New York Uniform Commercial Code, and a “clearing agency” registered pursuant to the provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds and provides asset servicing for over 3.5 million issues of U.S. and non-U.S. equity issues, corporate and municipal debt issues, and money market instruments (from over 100 countries) that DTC’s participants (“Direct Participants”) deposit with DTC. DTC also facilitates the post -trade settlement among Direct Participants of sales and other securities transactions in deposited securities, through electronic computerized book-entry transfers and pledges between Direct Participants’ accounts. This eliminates the need for physical movement of securities certif icates. Direct Participants include both U.S. and non- U.S. securities brokers and dealers, banks, trust companies, clearing corporations, and certain other organizations. DTC is a wholly-owned subsidiary of The Depository Trust & Clearing Corporation ( “DTCC”). DTCC is the holding company for DTC, National Securities Clearing Corporation and Fixed Income Clearing Corporation, all of which are registered clearing agencies. DTCC is owned by the users of its regulated subsidiaries. Access to the DTC system is also available to others such as both U.S. and non- U.S. securities brokers and dealers, banks, trust companies, and clearing corporations that clear through or maintain a custodial relationship with a Direct Participant, either directly or indirect ly (“Indirect Participants”). DTC has a Standard & Poor’s rating of AA+.

The DTC Rules applicable to DTC’s Participants are on file with the Securities and Exchange Commission. More information about DTC can be found at www.dtcc.com. The information on such website is not incorporated herein by reference.

Purchases of the 2024A Bonds under the DTC book- entry system must be made by or through Direct Participants, which will receive a credit for the 2024A Bonds on DTC’s records. The ownership interest of each actual purchaser of each 2024A Bond (“Beneficial Owner”) is in turn to be recorded on the Direct and Indirect Participants’ records. Beneficial Owners will not receive written confirmation from DTC of their purchase.

Beneficial Owners are, however, expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the Direct or Indirect Participant through which the Beneficial Owner entered into the transaction. Transfers of ownership interests in the 2024A Bonds are to be accomplished by entries made on the books of Direct and Indirect Participants acting on behalf of Beneficial Owners. Beneficial Owners will not receive certificates representing their ownership interests in the 2024A Bonds, except in the event that use of the book-entry system for the 2024A Bonds is discontinued.

To facilitate subsequent transfers, all 2024A Bonds deposited by Direct Participants with DTC are registered in the name of DTC’s partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of 2024A Bonds with DTC and their registration in the name of Cede & Co. or such other DTC nominee do not effect any change in beneficial ownership. DTC has no knowledge

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of the actual Beneficial Owners of the 2024A Bonds. DTC’s records reflect only the identity of the Direct Participants to whose accounts such 2024A Bonds are credited, which may or may not be the Beneficial Owners.

The Direct and Indirect Participants will remain responsible for keeping account of their holdings on behalf of their customers.

Conveyance of notices and other communications by DTC to Direct Participants, by Direct Participants to Indirect Participants, and by Direct Participants and Indirect Participants to Beneficial Owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Beneficial Owners of the 2024A Bonds may wish to take c ertain steps to augment the transmission to them of notices of significant events with respect to the 2024A Bonds, such as redemptions, defaults and proposed amendments to the Fiscal Agent Agreement. For example, Beneficial Owners of 2024A Bonds may wish to ascertain that the nominee holding the 2024A Bonds for their benefit has agreed to obtain and transmit notices to Beneficial Owners. In the alternative, Beneficial Owners may wish to provide their names and addresses to the Bond Registrar and request that copies of notices be provided directly to them.

Redemption notices shall be sent to DTC. If less than all of the 2024A Bonds of a maturity are being redeemed, DTC’s practice is to determine by lot the amount of the interest of each Direct Participant in such maturity to be redeemed.

Neither DTC nor Cede & Co. (nor such other DTC nominee) will consent or vote with respect to 2024A Bonds unless authorized by a Direct Participant in accordance with DTC’s MMI Procedures. Under its usual procedures, DTC mails an Omnibus Proxy to the City as soon as possible after the record date. The Omnibus Proxy assigns Cede & Co.’s consenting or voting rights to those Direct Participants to whose accounts 2024A Bonds are credited on the record date (identified in a listing attached to the Omnibus Proxy).

Principal, redemption price and interest payments on the 2024A Bonds will be made to Cede & Co. or such other nominee as may be requested by an authorized representative of DTC. DTC’s practice is to credit Direct Participants’ accounts upon DTC’s receipt of funds and corresponding detail information from the City or the Fiscal Agent, on each payment date in accordance with their respective holdings shown on DTC’s records.

Payments by Direct and Indirect Participants to Beneficial Owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in “street name,” and will be the responsibility of such Participant and n ot of DTC, the Fiscal Agent or the City, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of principal, redemption price and interest to Cede & Co. (or such other nominee as may be requested by an authori zed representative of DTC) is the responsibility of the City or the Fiscal Agent, disbursement of such payments to Direct Participants will be the responsibility of DTC, and disbursement of such payments to Beneficial Owners is the responsibility of Direct and Indirect Participants.

DTC may discontinue providing its services as security depository with respect to the 2024A Bonds at any time by giving reasonable notice to the City or the Fiscal Agent. Under such circumstances, in the event that a successor depository is not obtained, the 2024A Bonds are required to be printed and delivered.

The City may decide to discontinue use of the system of book-entry transfers through DTC (or a successor securities depository). In that event, definitive 2024A Bonds will be printed and delivered.

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APPENDIX D

SUMMARY OF CERTAIN PROVISIONS OF THE FISCAL AGENT AGREEMENT

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APPENDIX E

FORM OF CONTINUING DISCLOSURE AGREEMENT
This Continuing Disclosure Agreement (the “Disclosure Agreement”), dated as of _________ 1, 2024, is executed and delivered by the City of Pasadena (the “Issuer”) and Digital Assurance Certification, L.L.C., as exclusive Disclosure Dissemination Agent (the “Disclosure Dissemination Agent” or “DAC”) for the benefit of the Holders (hereinafter defined) of the Bonds (hereinafter defined) in order to provide certain continuing disclosure with respect to the Bonds in accordance with Rule 15c2-12 of the United States Securities and Exchange Commission under the Securities Exchange Act of 1934, as the same may be amended from time to time (the “Rule”).

The services provided under this Disclosure Agreement solely relate to the execution of instructions received from the Issuer through use of the DAC system and do not constitute “advice” within the meaning of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”). DAC will not provide any advice or recommend ation to the Issuer or anyone on the Issuer’s behalf regarding the “issuance of municipal securities” or any “municipal financial product” as defined in the Act and nothing in this Disclosure Agreement shall be interpreted to the contrary.

SECTION 1. Definitions. Capitalized terms not otherwise defined in this Disclosure Agreement shall have the meaning assigned in the Rule or, to the extent not in conflict with the Rule, in the Official Statement (hereinafter defined). The capitalized terms shall have the following meanings:
“Annual Filing Date” means the date, set in Sections 2(a) and 2(f), by which the Annual Report is to be filed with the MSRB.
“Annual Financial Information” means annual financial information as such term is used in paragraph (b)(5)(i) of the Rule and specified in Section 3(a) of this Disclosure Agreement. “Annual Report” means an Annual Report described in and consistent with Section 3 of this Disclosure Agreement.
“Audited Financial Statements” means the financial statements (if any) of t he Issuer for the prior fiscal year, certified by an independent auditor as prepared in accordance with generally accepted accounting principles or otherwise, as such term is used in paragraph (b)(5)(i) of the Rule and specified in Section 3(a)(i) of this Disclosure Agreement. “Bonds” means the bonds as listed on the attached Exhibit A, with the 9- digit CUSIP numbers relating thereto.
“Certification” means a written certification of compliance signed by the Disclosure Representative stating that the Annual Report, Audited Financial Statements, Notice Event notice, Failure to File Event notice, Voluntary Event Disclosure or Voluntary Financial Disclosure delivered to the Disclosure Dissemination Agent is the Annual Report, Audited Financial Statements, Notice Event notice, Failure to File Event notice, Voluntary Event Disclosure or Voluntary Financial Disclosure required to be submitted to the MSRB under this Disclosure Agreement. A Certification shall accompany each such document submitted to the Disclosure Dissemination Agent by the Issuer and include the full name of the Bonds and the 9-digit CUSIP numbers for all Bonds to which the document applies.

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“Disclosure Dissemination Agent” means Digital Assurance Certification, L.L.C., acting in its capacity as Disclosure Dissemination Agent hereunder, or any successor Disclosure Dissemination Agent designated in writing by the Issuer pursuant to Section 9 hereof. “Disclosure Representative” means the Director of Finance of the Issuer or his or her designee, or such other person as the Issuer shall designate in writing to the Disclosure Dissemination Agent from time to time as the person responsible for providing Information to the Disclosure Dissemination Agent.
“Failure to File Event” means the Issuer’s failure to file an Annual Report on or before the Annual Filing Date.
“Fiscal Agent” means The Bank of New York Mellon Trust Company, N.A., as successor fiscal agent under that Electric Revenue Bond Fiscal Agent Agreement, dated as of August 1, 1998, by and between the Issuer and the Fiscal Agent, as amended and supplemented, including as amended and supplemented by the Eleventh Supplement to Electric Revenue Bond Fiscal Agent Agreement, dated as of _________ 1, 2024, by and between the Issuer and the Fiscal Agent, relating to Bonds. “Force Majeure Event” means: (i) acts of God, war, or terrorist action; (ii) failure or shut-down of the Electronic Municipal Market Access system maintained by the MSRB; or (iii) to the extent beyond the Disclosure Dissemination Agent’s reasonable control, interruptions in telecommunications or utilities services, failure, malfunction or error of any telecommunications, computer or other electrical, mechanical or technological application, service or system, computer virus, interruptions in Internet service or telephone service (including due to a virus, electrical delivery problem or similar occurrence) that affect Internet users generally, or in the local area in which the Disclosure Dissemination Agent or the MSRB is located, or acts of any government, regulatory or any other competent authority the effect of which is to prohibit the Disclosure Dissemination Agent from performance of its obligations under this Disclosure Agreement. “Holder” means any person (a) having the power, directly or indirectly, to vote or consent with respect to, or to dispose of ownership of, any Bonds (including persons holding Bonds through nominees, depositories or other intermediaries) or (b) treated as the owner of any Bonds for federal income tax purposes.
“Information” means, collectively, the Annual Reports, the Audited Financial Statements (if any), the Notice Event notices, the Failure to File Event notices, the Voluntary Event Disclosures and the Voluntary Financial Disclosures.
“MSRB” means the Municip al Securities Rulemaking Board established pursuant to Section 15B(b)(1) of the Securities Exchange Act of 1934 or any other entity designated or authorized by the Securities and Exchange Commission to receive reports pursuant to the Rule.

Until otherwise designated by the MSRB or the Securities and Exchange Commission, filings with the MSRB are to be made through the Electronic Municipal Marketplace Access (EMMA) website of the MSRB, currently located at http://emma.msrb.org
.
“Notice Event” means any of the events enumerated in paragraph (b)(5)(i)(C) of the Rule and listed in Section 4(a) of this Disclosure Agreement.
“Obligated Person” means any person, including the Issuer, who is either generally or through an enterprise, fund, or account of such person committed by contract or other arrangement to support payment of all, or part of the obligations on the Bonds (other than providers of municipal bond

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insurance, letters of credit, or other liquidity facilities). With respect to the Bonds, only the Issuer constitutes the Obligated Person.
“Official Statement” means that Official Statement dated _________, 2024 prepared by the Issuer in connection with the Bonds, as listed on Exhibit A.
“Voluntary Event Disclosure” means information of the category specified in any of subsections (e)(vi)(1) through (e)(vi)(11) of Section 2 of this Disclosure Agreement that is accompanied by a Certification of the Disclosure Representative containing the information prescribed by Section 7(a) of this Disclosure Agreement.
“Voluntary Financial Disclosure” means information of the category specified in any of subsections (e)(vii)(1) through (e)(vii)(9) of Section 2 of this Disclosure Agreement that is accompanied by a Certification of the Disclosure Representative containing the information prescribed by Section 7(b) of this Disclosure Agreement.

SECTION 2. Provision of Annual Reports and Other Reports. (a) The Issuer shall provide, annually, an electronic copy of the Annual Report and Certification to the Disclosure Dissemination Agent, together with a copy for the Fiscal Agent, not later than 30 days prior to the Annual Filing Date. Promptly upon receipt of an electronic copy of the Annual Report and t he Certification, the Disclosure Dissemination Agent shall provide an Annual Report to the MSRB not later than 210 days after the end of the Issuer’s Fiscal Year (presently June 30), commencing with the report for Fiscal Year 2023-24. Such date and each anniversary thereof is the Annual Filing Date.

The Annual Report must be submitted in electronic format, accompanied by such identifying information as is prescribed by the MSRB. The Annual Report may be submitted as a single document or as separate documents comprising a package, and may cross- reference other information as provided in Section 3 of this Disclosure Agreement.
(b) If on the fifteenth (15th) day prior to the Annual Filing Date, the Disclosure Dissemination Agent has not received a copy of the Annual Report and Certification, the Disclosure Dissemination Agent shall contact the Disclosure Representative by telephone and in writing (which may be by e-mail) to remind the Issuer of its undertaking to provide the Annual Report pursuant to Section 2(a). Upon such reminder, the Disclosure Representative shall either (i) provide the Disclosure Dissemination Agent with an electronic copy of the Annual Report and the Certification) no later than two (2) business days prior to the Annual Filing Date, or (ii) instruct the Disclosure Dissemination Agent in writing that the Issuer will not be able to file the Annual Report within the time required under this Disclosure Agreement, state the date by which the Annual Report for such year will be provided and i nstruct the Disclosure Dissemination Agent to immediately provide a notice to the MSRB in substantially the form attached as Exhibit B. (c) If the Disclosure Dissemination Agent has not received an Annual Report and Certification by 6:00 p.m. Eastern time on Annual Filing Date (or, if such Annual Filing Date falls on a Saturday, Sunday or holiday, then the first business day thereafter) for the Annual Report, a Failure to File Event shall have occurred and the Issuer irrevocably directs the Disclosure Disse mination Agent to immediately send a notice to the MSRB in substantially the form attached as Exhibit B. (d) If Audited Financial Statements of the Issuer are prepared but not available prior to the Annual Filing Date, the Issuer shall, when the Audited Fi nancial Statements are available, provide in a timely manner an electronic copy to the Disclosure Dissemination Agent, accompanied by a Certification, together with a copy for the Fiscal Agent, for filing with the MSRB.

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(e) The Disclosure Dissemination Agent shall:
(i) verify the filing specifications of the MSRB each year prior to the Annual Filing Date;
(ii) upon receipt, promptly file each Annual Report received under Sections 2(a) and 2(b) with the MSRB;
(iii) upon receipt, promptly fil e each Audited Financial Statement received under Section 2(d) with the MSRB;
(iv) upon receipt, promptly file the text of each Notice Event received under Sections 4(a) and 4(b)(ii) with the MSRB, identifying the Notice Event as instructed by the Issuer pursuant to Section 4(a) or 4(b)(ii) (being any of the categories set forth below) when filing pursuant to Section 4(c) of this Disclosure Agreement:

1. “Principal and interest payment delinquencies;”

2. “Non-Payment related defaults, if material;”

3. “Unscheduled draws on debt service reserves reflecting financial difficulties;”

4. “Unscheduled draws on credit enhancements reflecting financial difficulties;”

5. “Substitution of credit or liquidity providers, or their failure to perform;”

6. “Adverse tax opinions, IRS notices or events affecting the tax status of the security;”

7. “Modifications to rights of securities holders, if material;”

8. “Bond calls, if material;”

9. “Defeasances;”

10. “Release, substitution, or sale of property securing repayment of t he securities, if material;”

11. “Rating changes;”

12. “Tender offers;”

13. “Bankruptcy, insolvency, receivership or similar event of the obligated person;”

14. “Merger, consolidation, or acquisition of the obligated person, if material;” and

15. “Appointment of a successor or additional trustee, or the change of name of a trustee, if material;”

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(v) upon receipt (or irrevocable direction pursuant to Section 2(c) of this Disclosure Agreement, as applicable), promptly file a completed copy of Exhibit B to this Disclosure Agreement with the MSRB, identifying the filing as “Failure to provide annual financial information as required” when filing pursuant to Section 2(b)(ii) or Section 2(c) of this Disclosure Agreement;
(vi) upon receipt, promptly file the text of each Voluntary Event Disclosure received under Section 7(a) with the MSRB, identifying the Voluntary Event Disclosure as instructed by the Issuer pursuant to Section 7(a) (being any of the categories set forth below) when filing pursuant to Section 7(a) of this Disclosure Agreement:

1. “amendment to continuing disclosure undertaking;”

2. “change in obligated person;”

3. “notice to investors pursuant to bond documents;”

4. “certain communications from the Internal Revenue Service;”

5. “secondary market purchases;”

6. “bid for auction rate or other securities;”

7. “capital or other financing plan;”

8. “litigation/enforcement action;”

9. “change of tender agent, remarketing agent, or other on-going party;”

10. “derivative or other similar transaction;” and

11. “other event-based disclosures;”
(vii) upon receipt, promptly file the text of each Voluntary Financial Disclosure received under Section 7(b) with the MSRB, identifying the Voluntary Financial Disclosure as instructed by the Issuer pursuant to Sec tion 7(b) (being any of the categories set forth below) when filing pursuant to Section 7(b) of this Disclosure Agreement:

1. “quarterly/monthly financial information;”

2. “change in fiscal year/timing of annual disclosure;”

3. “change in accounting standard;”

4. “interim/additional financial information/operating data;”

5. “budget;”

6. “investment/debt/financial policy;”

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7. “information provided to rating agency, credit/liquidity provider or other third party;”

8. “consultant reports;” and

9. “other financial/operating data.”
(viii) provide the Issuer evidence of the filings of each of the above when made, which shall be by means of the DAC system, for so long as DAC is the Disclosure Dissemination Agent under this Disclosure Agreement.
(f) The Issuer may adjust the Annual Filing Date upon change of its fiscal year by providing written notice of such change and the new Annual Filing Date to the Disclosure Dissemination Agent, Trustee (if any) and the MSRB, provided that the period between the existing Annual Filing Date and new Annual Filing Date shall not exceed one year.
(g) Any Information received by the Disclosure Dissemination Agent before 6:00 p.m. Eastern time on any business day that it is required to file with the MSRB pursuant to the terms of this Disclosure Agreement and that is accompanied by a Certification and all other information required by the terms of this Disclosure Agreement will be filed by the Disclosure Dissemination Agent with the MSRB no later than 11:59 p.m. Eastern time on the same business day; provided, however, the Disclosure Dissemination Agent shall have no liability for any delay in filing with the MSRB if such delay is caused by a Force Majeure Event provided that the Disclosure Dissemination Agent uses reasonable efforts to make any such filing as soon as possible.

SECTION 3. Content of Annual Reports.
(a) The Issuer’s Annual Report shall contain or include by reference the following:
(i) The Issuer’s annual Comprehensive Annual Financial Report (the “CAFR”) which shall include the audited financial statements of the Issuer’s Light and Power Fund for the prior fiscal year, prepared in accordance with generally accepted accounting principles as promulgated to apply to governmental entities from time to time by the Governmental Accounting Standards Board. If the Issuer’s audited financial statements are not available by the time the Annual Report is required to be filed pursuant to Section 2(a), the Annual Report shall contain unaudited financial statements in a for mat similar to the financial statements contained in the final Official Statement, and the audited financial statements shall be filed in the same manner as the Annual Report when they become available; (ii) Pasadena Water and Power’s most recently publish ed Annual Report, not previously filed with the MSRB;
(iii) Updated information comparable to the information in the following tables as they appear in the Official Statement relating to the Bonds:

1. Table 3 entitled “TOTAL POWER GENERATED AND PURCHASED (MWh);”

2. Table 4 entitled “POWER SUPPLY RESOURCES;”

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3. Table 7 entitled “CUSTOMERS, ENERGY SALES AND REVENUES;”

4. Table 8 entitled “OUTSTANDING DEBT OF JOINT POWERS
AGENCIES;”

5. Table 10 entitled “HISTORICAL OPERATING RESULTS AND DEBT SERVICE COVERAGE;” and

6. Table 11 entitled “CITY OF PASADENA ELECTRIC UTILITY FUND CONDENSED BALANCE SHEET.”
(b) Any or all of the items listed above may be included by specific reference from other documents, including official statements of debt issues with respect to which the Issuer is an Obligated Person, which have been previously filed with the MSRB or the Securities and Exchange Commission or available to the public on the MSRB Internet website. If the document incorporated by reference is a final official statement, it must be available from the MSRB. The Issuer will clearly identify each such document so incorporated by reference.

Any Annual Financial Information containing modified operating data or financial information is required to explain, in narrative form, the reasons for the modification and the impact of the change in the type of operating data or financial information being provided. The Issuer will reserve the right to modify from time to time the specific type of information provided or the format of the presentation of such information, to the extent necessary or appropriate in the judgment of the Issuer; provided that the Issuer will agree that any such modification will be done in a manner consistent with the Rule.

SECTION 4. Reporting of Notice Events.
(a) Reporting of Notice Events.

The occurrence of any of the following events with respect to the Bonds constitutes a Notice Event:

1. Principal and interest payment delinquencies;

2. Non-payment related defaults, if material;

3. Unscheduled draws on debt service reserves reflecting financial difficulties;

4. Unscheduled draws on credit enhancements reflecting financial difficulties;

5. Substitution of credit or liquidity providers, or their failure to perform;

6. Adverse tax opinions, the issuance by the Internal Revenue Service of proposed or final determinations of taxability, Notices of Proposed Issue (IRS Form 5701- TEB) or other material notices or determinations with respect to the tax status of the Bonds, or other material events affecting the tax status of the Bonds;

7. Modifications to rights of Bond holders, if material;

8. Bond calls, if material, and tender offers;

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9. Defeasances;

10. Release, substitution, or sale of property securing repayment of the Bonds, if material;

11. Rating changes;

12. Bankruptcy, insolvency, receivership or similar event of the Obligated Person;
Note to subsection (a)(12) of this Section 4: For the purposes of the event described in subsection (a)(12) of this Section 4, the event is considered to occur when any of the f ollowing occur: the appointment of a receiver, fiscal agent or similar officer for an Obligated Person in a proceeding under the U.S. Bankruptcy Code or in any other proceeding under state or federal law in which a court or governmental authority has assumed jurisdiction over substantially all of the assets or business of the Obligated Person, or if such jurisdiction has been assumed by leaving the existing governing body and officials or officers in possession but subject to the supervision and orders of a court or governmental authority, or the entry of an order confirming a plan of reorganization, arrangement or liquidation by a court or governmental authority having supervision or jurisdiction over substantially all of the assets or business of the Obligated Person.

13. The consummation of a merger, consolidation, or acquisition involving an Obligated Person or the sale of all or substantially all of the assets of the Obligated Person, other than in the ordinary course of business, the entry into a definitive agreement to undertake such an action or the termination of a definitive agreement relating to any such actions, other than pursuant to its terms, if material; and

14. Appointment of a successor or additional trustee or the change of name of a trustee, if material.

15. Incurrence of a financial obligation of the Obligated Person, if material, or agreement to covenants, events of default, remedies, priority rights, or other similar terms of a financial obligation of the Obligated Person, any of which affect security holders, if material.

Note to subsection (a)(15) of this Section 4: Financial obligation means a (A) debt obligation; (B) derivative instrument entered into in connection with, or pledged as security or a source of payment for, an existing o r planned debt obligation; or (C) guarantee of (A) or (B). Financial obligation shall not include municipal securities as to which a final official statement has been provided to the MSRB consistent with the Rule.

16. Default, event of acceleration, termi nation event, modification of terms, or other similar events under the terms of a financial obligation of the Obligated Person, any of which reflect financial difficulties.

The Issuer shall, in a timely manner not in excess of ten business days after its o ccurrence, notify the Disclosure Dissemination Agent in writing of the occurrence of a Notice Event. Such notice shall

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instruct the Disclosure Dissemination Agent to report the occurrence pursuant to subsection (c) and shall be accompanied by a Certificat ion. Such notice or Certification shall identify the Notice Event that has occurred (which shall be any of the categories set forth in Section 2(e)(iv) of this Disclosure Agreement), include the text of the disclosure that the Issuer desires to make, cont ain the written authorization of the Issuer for the Disclosure Dissemination Agent to disseminate such information, and identify the date the Issuer desires for the Disclosure Dissemination Agent to disseminate the information (provided that such date is not later than the tenth business day after the occurrence of the Notice Event). (b) The Disclosure Dissemination Agent is under no obligation to notify the Issuer or the Disclosure Representative of an event that may constitute a Notice Event. In the event the Disclosure Dissemination Agent so notifies the Disclosure Representative, the Disclosure Representative will within two business days of receipt of such notice (but in any event not later than the tenth business day after the occurrence of the Notice Event, if the Issuer determines that a Notice Event has occurred), instruct the Disclosure Dissemination Agent that (i) a Notice Event has not occurred and no filing is to be made or (ii) a Notice Event has occurred and the Disclosure Dissemination Agent is to report the occurrence pursuant to subsection (c) of this Section 4, together with a Certification. Such Certification shall identify the Notice Event that has occurred (which shall be any of the categories set forth in Section 2(e)(iv) of this Disclosure Agreement), include the text of the disclosure that the Issuer desires to make, contain the written authorization of the Issuer for the Disclosure Dissemination Agent to disseminate such information, and identify the date the Issuer desires for the Disclosure Dissemination Agent to disseminate the information (provided that such date is not later than the tenth business day after the occurrence of the Notice Event). (c) If the Disclosure Dissemination Agent has been instructed by the Issuer as prescribed in subsection (a) or (b)(ii) of this Section 4 to report the occurrence of a Notice Event, the Disclosure Dissemination Agent shall promptly file a notice of such occurrence with the MSRB in accordance with Section 2(e)(iv) hereof.

SECTION 5. CUSIP Numbers. Whenever providing information to the Disclosure Dissemination Agent, including but not limited to Annual Reports, documents incorporated by reference to the Annual Reports, Audited Financial Statements, Notice Event notices, Failure to File Event notices, Voluntary Event Disclosures and Voluntary Financial Disclosures, the Issuer shall indicate the full name of the Bonds and the 9-digit CUSIP numbers for the Bonds as to which the provided information relates.

SECTION 6.

Additional Disclosure Obligations. The Issuer acknowledges and understands that other state and federal laws, including but not limited to the Securities Act of 1933 and Rule 10b- 5 promulgated under the Securities Exchange Act of 1934, may apply to the Issuer, and that the failure of the Disclosure Dissemination Agent to so advise the Issuer shall not constitute a breach by the Disclosure Dissemination Agent of any of its duties and responsibilities under this Disclosure Agreement. The Issuer acknowledges and understands that the duties of the Disclosure Dissemination Agent relate exclusively to execution of the mechanical tasks of disseminating information as described in this Disclosure Agreement.

SECTION 7. Voluntary Filings.
(a) The Issuer may instruct the Disclosure Dissemination Agent to file a Volunt ary Event Disclosure with the MSRB from time to time pursuant to a Certification of the Disclosure Representative.

Such Certification shall identify the Voluntary Event Disclosure (which shall be any of the categories set forth in Section 2(e)(vi) of this Disclosure Agreement), include the text of the disclosure that the Issuer desires to make, contain the written authorization of the Issuer for the Disclosure Dissemination Agent to disseminate such information, and identify the date the Issuer desires for the Disclosure Dissemination Agent to disseminate the information. If the Disclosure Dissemination Agent has been instructed by the Issuer as prescribed in this Section 7(a) to file a Voluntary Event Disclosure, the Disclosure Dissemination

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Agent shall p romptly file such Voluntary Event Disclosure with the MSRB in accordance with Section 2(e)(vi) hereof.
(b) The Issuer may instruct the Disclosure Dissemination Agent to file a Voluntary Financial Disclosure with the MSRB from time to time pursuant to a Certification of the Disclosure Representative.

Such Certification shall identify the Voluntary Financial Disclosure (which shall be any of the categories set forth in Section 2(e)(vii) of this Disclosure Agreement), include the text of the disclosure that the Issuer desires to make, contain the written authorization of the Issuer for the Disclosure Dissemination Agent to disseminate such information, and identify the date the Issuer desires for the Disclosure Dissemination Agent to disseminate the informatio n. If the Disclosure Dissemination Agent has been instructed by the Issuer as prescribed in this Section 7(b) to file a Voluntary Financial Disclosure, the Disclosure Dissemination Agent shall promptly file such Voluntary Financial Disclosure with the MSRB in accordance with Section 2(e)(vii) hereof.
(c) The parties hereto acknowledge that the Issuer is not obligated pursuant to the terms of this Disclosure Agreement to file any Voluntary Event Disclosure pursuant to Section 7(a) hereof or any Voluntary Financial Disclosure pursuant to Section 7(b) hereof. (d) Nothing in this Disclosure Agreement shall be deemed to prevent the Issuer from disseminating any other information through the Disclosure Dissemination Agent using the means of dissemination set fort h in this Disclosure Agreement or including any other information in any Annual Report, Audited Financial Statements, Notice Event notice, Failure to File Event notice, Voluntary Event Disclosure or Voluntary Financial Disclosure, in addition to that required by this Disclosure Agreement. If the Issuer chooses to include any information in any Annual Report, Audited Financial Statements, Notice Event notice, Failure to File Event notice, Voluntary Event Disclosure or Voluntary Financial Disclosure in addition to that which is specifically required by this Disclosure Agreement, the Issuer shall have no obligation under this Disclosure Agreement to update such information or include it in any future Annual Report, Audited Financial Statements, Notice Event notice, Failure to File Event notice, Voluntary Event Disclosure or Voluntary Financial Disclosure.

SECTION 8. Termination of Reporting Obligation. The obligations of the Issuer and the Disclosure Dissemination Agent under this Disclosure Agreement shall terminate with respect to the Bonds upon the legal defeasance, prior redemption or payment in full of all of the Bonds, when the Issuer is no longer an obligated person with respect to the Bonds, or upon delivery by the Disclosure Representative to the Disclosure Dissemination Agent of an opinion of nationally recognized bond counsel to the effect that continuing disclosure is no longer required.

SECTION 9.

Disclosure Dissemination Agent. The Issuer has appointed Digital Assurance Certification, L.L.C. as exclusive Disclosure Dissemination Agent under this Disclosure Agreement. The Issuer may, upon thirty days written notice to the Disclosure Dissemination Agent and the Fiscal Agent, replace or appoint a successor Disclosure Dissemination Agent. Upon termination of DAC’s ser vices as Disclosure Dissemination Agent, whether by notice of the Issuer or DAC, the Issuer agrees to appoint a successor Disclosure Dissemination Agent or, alternately, agrees to assume all responsibilities of Disclosure Dissemination Agent under this Disclosure Agreement for the benefit of the Holders of the Bonds. Notwithstanding any replacement or appointment of a successor, the Issuer shall remain liable until payment in full for any and all sums owed and payable to the Disclosure Dissemination Agent. The Disclosure Dissemination Agent may resign at any time by providing thirty days’ prior written notice to the Issuer.

SECTION 10.

Remedies in Event of Default . In the event of a failure of the Issuer or the Disclosure Dissemination Agent to comply with any provision of this Disclosure Agreement, the Holders’

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rights to enforce the provisions of this Agreement shall be limited solely to a right, by action in mandamus or for specific performance, to compel performance of the parties’ obligation under this Disclosur e Agreement. Any failure by a party to perform in accordance with this Disclosure Agreement shall not constitute a default on the Bonds or under any other document relating to the Bonds, and all rights and remedies shall be limited to those expressly stated herein.

SECTION 11. Duties, Immunities and Liabilities of Disclosure Dissemination Agent. (a) The Disclosure Dissemination Agent shall have only such duties as are specifically set forth in this Disclosure Agreement. The Disclosure Dissemination Agent’s obligation to deliver the information at the times and with the contents described herein shall be limited to the extent the Issuer has provided such information to the Disclosure Dissemination Agent as required by this Disclosure Agreement. The Disclosur e Dissemination Agent shall have no duty with respect to the content of any disclosures or notice made pursuant to the terms hereof. The Disclosure Dissemination Agent shall have no duty or obligation to review or verify any Information or any other infor mation, disclosures or notices provided to it by the Issuer and shall not be deemed to be acting in any fiduciary capacity for the Issuer, the Holders of the Bonds or any other party. The Disclosure Dissemination Agent shall have no responsibility for the Issuer’s failure to report to the Disclosure Dissemination Agent a Notice Event or a duty to determine the materiality thereof. The Disclosure Dissemination Agent shall have no duty to determine, or liability for failing to determine, whether the Issuer has complied with this Disclosure Agreement. The Disclosure Dissemination Agent may conclusively rely upon certifications of the Issuer at all times.

The obligations of the Issuer under this Section shall survive resignation or removal of the Disclosure Dissemination Agent and defeasance, redemption or payment of the Bonds. (b) The Disclosure Dissemination Agent may, from time to time, consult with legal counsel (either in-house or external) of its own choosing in the event of any disagreement or controversy, or question or doubt as to the construction of any of the provisions hereof or its respective duties hereunder, and shall not incur any liability and shall be fully protected in acting in good faith upon the advice of such legal counsel. The fees and expenses of such counsel shall be payable by the Issuer. (c) All documents, reports, notices, statements, information and other materials provided to the MSRB under this Disclosure Agreement shall be provided in an electronic format and accompanied by identifying information as prescribed by the MSRB.

SECTION 12. Amendment; Waiver . Notwithstanding any other provision of this Disclosure Agreement, the Issuer and the Disclosure Dissemination Agent may amend this Disclosure Agreement and any provision of this Disclosure Agreement may be waived, if such amendment or waiver is supported by an opinion of counsel expert in federal securities laws acceptable to both the Issuer and the Disclosure Dissemination Agent to the effect that such amendment or waiver does not materia lly impair the interests of Holders of the Bonds and would not, in and of itself, cause the undertakings herein to violate the Rule if such amendment or waiver had been effective on the date hereof but taking into account any subsequent change in or official interpretation of the Rule; provided neither the Issuer nor the Disclosure Dissemination Agent shall be obligated to agree to any amendment modifying their respective duties or obligations without their consent thereto.

Notwithstanding the preceding paragraph, the Disclosure Dissemination Agent shall have the right to adopt amendments to this Disclosure Agreement necessary to comply with modifications to and interpretations of the provisions of the Rule as announced by the Securities and Exchange Commission from time to time by giving not less than 20 days written notice of the intent to do so together with a copy of the proposed amendment to the Issuer. No such amendment shall become effective if the Issuer shall,

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within 10 days following the giving of such notice, send a notice to the Disclosure Dissemination Agent in writing that it objects to such amendment.

SECTION 13. Beneficiaries. This Disclosure Agreement shall inure solely to the benefit of the Issuer, the Fiscal Agent of the Bonds, the Disclosure Dissemination Agent, the participating underwriter (as defined in the Rule), and the Holders from time to time of the Bonds, and shall create no rights in any other person or entity.

SECTION 14.

Governing Law. This Disclosure Agreement shall be governed by the laws of th e State of California (other than with respect to conflicts of laws).

SECTION 15. Counterparts. This Disclosure Agreement may be executed in several counterparts, each of which shall be an original and all of which shall constitute but one and the same instrument. (Signature page follows)

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The Disclosure Dissemination Agent and the Issuer have caused this Continuing Disclosure Agreement to be executed, on the date first written above, by their respective officers duly authorized.

DIGITAL ASSURANCE CERTIFICATION, L.L.C.,
as Disclosure Dissemination Agent

By:

Name:

Title:

CITY OF PASADENA, CALIFORNIA,
as Issuer
By:

Matthew Hawkesworth
Director of Finance
APPROVED AS TO FORM:

By: ___________________________________
Michele Beal Bagneris
City Attorney

APPROVED AS TO FORM:

By: ___________________________________
Danny Kim, Partner
Best Best & Krieger LLP
Bond Counsel
-Signature Page-
Continuing Disclosure Agreement

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EXHIBIT A

NAME AND CUSIP NUMBERS OF BONDS
Name of Issuer City of Pasadena, California
Obligated Person(s) City of Pasadena, California
Name of Bond Issue: $__________ Electric Revenue/Refunding Bonds, 2024A Series Date of Issuance: __________, 2024
Date of Official Statement: _________, 2024

CUSIP Number:

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EXHIBIT B

NOTICE TO MSRB OF FAILURE TO FILE ANNUAL REPORT
Issuer:

Obligated Person:

City of Pasadena, California
City of Pasadena, California
Name of Bond Issue: $__________ Electric Revenue/Refunding Bonds, 2024A Series Date of Issuance: _________, 2024

NOTICE IS HEREBY GIVEN that the Issuer has not provided an Annual Report with respect to the above-named Bonds as required by the Continuing Disclosure Agreement, dated as of ___________ 1, 2024, between the Issuer and Digital Assurance Certification, L.L.C., as Disclosure Dissemination Agent. The Issuer has notified the Disclosure Dissemination Agent that it anticipates that the Annual Report will be filed by______________.

Dated: ________________ DIGITAL ASSURANCE CERTIFICATION, L.L.C., on behalf of the City of Pasadena, California

By:

cc: Director of Finance, City of Pasadena

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APPENDIX F

PROPOSED FORM OF OPINION OF BOND COUNSEL

Pasadena City CouncilMay 13, 2024

Pasadena City Council
May 13, 2024