Vernon City Council
April 19, 2022

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Estate”) and are secured by a pledge of the Trust Estate. See the caption “SECURITY AND SOURCES OF PAYMENT—Pledge Effected by the Indenture.”
The issuance of the 2022 Bonds does not directly, indirectly or contingently obligate the City to levy or pledge any form of taxation or to make any appropriation for their payment. The 2022 Bonds are not secured by a legal or equitable pledge of, or lien or charge upon, any property of the City or any of its income or receipts except the Trust Estate pledged therefor pursuant to the Indenture which is subject to the provisions of the Indenture permitting the application thereof for the purposes and on the terms and conditions set forth therein. Neither the faith and credit nor the taxing power of the City, the State of California (the “State”) or any other public agency is pledged to the payment of the principal of, premium, if any, or interest on the 2022 Bonds. The 2022 Bonds do not constitute a debt, liability or obligation of the State or any public agency other than the special obligation of the City as provided in the Indenture.

The City has issued, and there are currently outstanding under the Indenture, $415,475,000 aggregate principal amount of Electric System Revenue Bonds payable from Net Revenues on a parity with the 2022 Bonds (of which $61,235,000 is expected to be refunded by the 2022 Bonds), consisting of: (a) the Electric System Revenue Bonds, 2008 Taxable Series A (the “2008A Bonds”), which are currently outstanding in the aggregate principal amount of $37,850,000; (b) the 2012A Bonds, which are currently outstanding in the aggregate principal amount of $37,640,000 (all of which is expected to be refunded by the 2022 Bonds); (c) the 2012B Bonds, which are currently outstanding in the aggregate principal amount of $35,100,000 (of which $23,595,000 is expected to be refunded by the 2022 Bonds); (d) the Electric System Revenue Bonds, 2015 Taxable Series A (the “2015A Bonds”), which are currently outstanding in the aggregate principal amount of $111,720,000; (e) the Electric System Revenue Bonds, 2020 Series A (the “2020A Bonds”), which are currently outstanding in the aggregate principal amount of $19,305,000; and (f) the Electric System Revenue Bonds, 2021 Series A (the “2021A Bonds”), which are currently outstanding in the aggregate principal amount of $173,815,000.

The Indenture permits the City to issue Additional Bonds and Refunding Bonds which are payable from Net Revenues on a parity with the 2022 Bonds on the terms and conditions set forth in the Indenture.

The 2008A Bonds, the 2012B Bonds not refunded with proceeds of the 2022 Bonds, 2015A Bonds, the 2020A Bonds, the 2021A Bonds, the 2022 Bonds and any such Additional Bonds and Refunding Bonds issued under the Indenture are referred to as the “Bonds.” All Bonds are equally and ratably secured by the pledge of the Trust Estate under the Indenture. See the captions “SECURITY AND SOURCES OF PAYMENT— Outstanding Electric System Obligations” and “SECURITY AND SOURCES OF PAYMENT—Additional Parity Obligations.”
Debt Service Reserve Fund
Pursuant to the Indenture, the Debt Service Reserve Fund is required to be maintained in an amount equal to the Debt Service Reserve Requirement. Amounts on deposit in the Debt Service Reserve Fund will be applied to make up any deficiency in any account of the Debt Service Fund for the payment when due of principal or Redemption Price of or interest on Bonds, including the 2022 Bonds. In connection with the issuance of the 2022 Bonds, a portion of the amount on deposit in the Debt Service Reserve Fund is expected to be released and applied to the redemption of the Refunded 2012 Bonds. See the caption “ESTIMATED SOURCES AND USES OF FUNDS.”
In lieu of the required deposits and transfers of money to the Debt Service Reserve Fund, the City may cause to be deposited in the Debt Service Reserve Fund a Reserve Financial Guaranty. Pursuant to the Fifth Supplemental Indenture, dated as of March 1, 2020 (the “Fifth Supplemental Indenture”), by and between the City and the Trustee, at such time as the 2008A Bonds, the 2012A Bonds, the 2012B Bonds and the 2015A Bonds are no longer Outstanding, the definition of “Reserve Financial Guaranty” under the Master Indenture Resolution No. 2022-10

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will be amended as described under the caption “SECURITY AND SOURCES OF PAYMENT—Debt Service Reserve Fund.”
Redemption Provisions
The 2022 Bonds are subject to redemption prior to maturity. See the caption “THE 2022 BONDS— Redemption of the 2022 Bonds.”
Continuing Disclosure
The City will covenant for the benefit of the holders and beneficial owners of the 2022 Bonds, pursuant to a Continuing Disclosure Agreement with the Trustee, in its capacity as dissemination agent, to provide to the Municipal Securities Rulemaking Board (the “MSRB”) through its Electronic Municipal Market Access System (“EMMA”) a copy of the annual audited financial statements of the Electric System, as well as certain operating and financial data relating to the Electric System, and notices of certain enumerated events.

The first Annual Report will be due by April 1, 2023. See the caption “CONTINUING DISCLOSURE” and Appendix E.

Other Matters
The summaries of and references to all documents, statutes, reports and other instruments that are 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, report or instrument. The capitalization of any word not conventionally capitalized or otherwise defined herein indicates that such word is defined in a particular agreement or other document and, as used herein, has the meaning given to it in such agreement or document.

Attached to this Official Statement as Appendix B are summaries of certain provisions of the Indenture. Copies of the Indenture are available for inspection at the offices of the Trustee, and copies of the Indenture will be provided by the Trustee upon request and payment of costs.

PLAN OF FINANCE
General
The 2022 Bonds are being issued to provide funds: (i) to refund and defease all of the outstanding 2012A Bonds and a portion of outstanding 2012B Bonds; and (ii) to pay costs of issuance of the 2022 Bonds, all as more fully described in this Official Statement.

Refunding of the Refunded 2012 Bonds
General. The City issued the 2012A Bonds, which are currently outstanding in the aggregate principal amount of $37,640,000, and the 2012B Bonds, which are currently outstanding in the aggregate principal amount of $35,100,000, pursuant to the Indenture, as supplemented by a Third Supplemental Indenture of Trust, dated as of January 1, 2012.

The City plans to apply a portion of the proceeds of the 2022 Bonds, together with other available monies, to refund all of the outstanding 2012A Bonds and a portion of each of the 2012B Bonds maturing on and after August 1, 2023, constituting the Refunded 2012B Bonds, as shown in the below tables. The $6,165,000 principal amount of the 2012B Bonds maturing on August 1, 2022 are not being refunded and are expected to be paid by the City as they become due.

Resolution No. 2022-10

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Refunded 2012A Bonds
Principal Payment Date
(August 1)
Principal
Amount Refunded
CUSIP®†
(924397) Redemption
Date
2030 $ 4,645,000 CL4 August 1, 2022
2033 4,155,000 CM2 August 1, 2022
2041 28,840,000 CN0 August 1, 2022
Refunded 2012B Bonds
Principal
Payment Date
(August 1)
Outstanding
Principal
Amount of
2012B Bonds
CUSIP®†
(924397)
Refunded
Principal
Amount of
2012B Bonds
Redemption
Date
Outstanding
Principal Amount
of 2012B Bonds
After Refunding
2023 $6,565,000 CQ3 $5,395,000 August 1, 2022 $1,170,000 2024 6,990,000 CR1 5,685,000 August 1, 2022 1,305,000
2025 7,440,000 CS9 6,050,000 August 1, 2022 1,390,000
2026 7,940,000 CT7 6,465,000 August 1, 2022 1,475,000
Under an Escrow Agreement, dated as of December 1, 2021 (the “2012 Escrow Agreement”), by and between the City and the Trustee, as escrow agent, the City will deliver a portion of the proceeds of the 2022 Bonds and certain amounts released from the Debt Service Reserve Fund to the Trustee for deposit in the escrow fund established under the 2012 Escrow Agreement (the “2012 Escrow Fund”). See the caption “ESTIMATED SOURCES AND USES OF FUNDS.” Such amount will be held in cash or will be invested in direct obligations of the Department of Treasury of the United States of America (the “Federal Securities”).

From the moneys and Federal Securities, if any, on deposit in the 2012 Escrow Fund, together with investment earnings thereon, the Trustee will pay the redemption price of the Refunded 2012 Bonds on August 1, 2022 (the “Redemption Date”), at a redemption price equal to the principal amount to be redeemed, without premium, plus accrued, unpaid interest to the Redemption Date.

As a result of the deposit and application of funds, Federal Securities, if any, and investment earnings as provided in the 2012 Escrow Agreement, the Refunded 2012 Bonds will be deemed paid and will no longer be deemed to be Outstanding under the Indenture, as of the date of issuance of the 2022 Bonds.

The amounts held by the Trustee in the 2012 Escrow Fund are pledged solely to the payment of the Refunded 2012 Bonds. The funds and Federal Securities deposited in the 2012 Escrow Fund and the investment earnings thereon will not be available for the payments of principal of and interest on the 2022 Bonds.

Verification. Sufficiency of the deposits in the 2012 Escrow Fund for such purposes will be verified by Causey Demgen & Moore P.C., Denver, Colorado (the “Verification Agent”). Assuming the accuracy of such computations, as a result of the deposit and application of funds as provided above, as of the date of F-4
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F-4
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† CUSIP numbers have been assigned by an organization unaffiliated with the City. The City is not responsible for the selection of the CUSIP numbers and makes no representation as to the accuracy thereof as set forth above.

Resolution No. 2022-10

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issuance of the 2022 Bonds, the Refunded 2012 Bonds will be defeased pursuant to the provisions of the Indenture.

The Verification Agent will also deliver to the City, on or before the delivery date of the 2022 Bonds, its verification report indicating that it has verified, in accordance with attestation standards established by the American Institute of Certified Public Accountants, the mathematical accuracy of (a) the mathematical computations of the adequacy of the cash and the maturing principal of and interest on the Federal Securities, if any, when deposited into the 2012 Escrow Fund, to pay, when due, the redemption price of the Refunded 2012 Bonds on the Redemption Date and (b) the mathematical computations of yield used by Bond Counsel to support its opinion that interest on the 2022 Bonds will be excluded from gross income for federal income tax purposes (assuming and subject to the satisfaction of certain terms and conditions of a Forward Delivery Purchase Contract for the 2022 Bonds). See “FORWARD DELIVERY OF THE 2022 BONDS.” The verifications described above to be performed by the Verification Agent will be solely based upon data, information and documents provided to the Verification Agent by Goldman Sachs & Co. LLC, as the Underwriter of the 2022 Bonds. The Verification Agent has restricted its procedures to recalculating the computations provided by Goldman Sachs & Co. LLC and has not evaluated or examined the assumptions or information used in the computations.

ESTIMATED SOURCES AND USES OF FUNDS
The estimated sources and uses of funds with respect to the 2022 Bonds are set forth below.

Sources(1)
Principal Amount $ 52,070,000.00
Plus Original Issue Premium 10,179,957.10
Debt Service Reserve Fund Release(1) 1,156,835.53
Total Sources $ 63,406,792.63

Uses
Deposit to 2022 Escrow Fund $ 62,999,903.13
Costs of Issuance(2) 406,889.50
Total Uses $ 63,406,792.63

(1) Reflects moneys released from the Debt Service Reserve Fund in connection with the refunding of the Refunded 2012 Bonds. See the caption “SECURITY AND SOURCES OF PAYMENT—Debt Service Reserve Fund.” (2) Includes Underwriter’s discount, legal fees, Trustee fees, Verification Agent fees, rating agency fees, printing costs and other expenses in connection with the issuance of the 2022 Bonds.

Resolution No. 2022-10

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DEBT SERVICE SCHEDULE
The following table shows the debt service schedule for the City’s Outstanding Bonds, including the 2022 Bonds.

Fiscal
Year
Ended
June 30
Debt Service on
Outstanding
Bonds(1)
2022 Bonds
Total
Principal Interest Debt Service
2022 $ 19,452,807.85(2) $ - $ - $ 19,452,806.85
2023 67,783,655.50 - 1,923,697.22 69,707,352.72
2024 62,533,954.00 4,690,000.00 2,486,250.00 69,710,204.00 2025 62,574,662.25 4,885,000.00 2,246,875.00 69,706,537.25 2026 62,576,502.25 5,130,000.00 1,996,500.00 69,703,002.25 2027 57,566,568.75 5,405,000.00 1,733,125.00 64,704,693.75 2028 62,179,089.00 950,000.00 1,574,250.00 64,703,339.00 2029 6,689,854.00 1,000,000.00 1,525,500.00 9,215,354.00 2030 6,692,198.75 1,055,000.00 1,474,125.00 9,221,323.75 2031 6,691,584.75 1,105,000.00 1,420,125.00 9,216,709.75 2032 6,686,813.25 1,160,000.00 1,363,500.00 9,210,313.25 2033 6,691,220.75 1,220,000.00 1,304,000.00 9,215,220.75 2034 6,692,839.25 1,285,000.00 1,241,375.00 9,219,214.25 2035 6,690,040.50 1,350,000.00 1,175,500.00 9,215,540.50 2036 6,690,856.50 1,420,000.00 1,106,250.00 9,217,106.50 2037 6,688,104.50 1,490,000.00 1,033,500.00 9,211,604.50 2038 6,694,262.00 1,565,000.00 957,125.00 9,216,387.00
2039 4,239,591.75 1,650,000.00 876,750.00 6,766,341.75
2040 - 5,295,000.00 703,125.00 5,998,125.00
2041 - 5,565,000.00 431,625.00 5,996,625.00
2042 - 5,850,000.00 146,250.00 5,996,250.00
TOTAL(2) $465,814,604.60 $52,070,000.00 $26,719,447.22 $ 544,604,051.82

(1) Reflects debt service on the 2008A Bonds, the portion of the 2012B Bonds not expected to be redeemed with the proceeds of the 2022 Bonds, the 2015A Bonds, the 2020A Bonds and the 2021A Bonds. The entire outstanding principal amount of the 2012A Bonds, which are currently outstanding in the aggregate principal amount of $37,640,000, is expected to be redeemed with a portion of the proceeds of the 2022 Bonds on August 1, 2022, and $23,595,000 of the 2012B Bonds is expected to be redeemed with a portion of the proceeds of the 2022 Bonds on August 1, 2022. (2) Reflects debt service payable for the remainder of Fiscal Year 2022 as of December 14, 2021.

THE 2022 BONDS
General
The 2022 Bonds will be issued in the aggregate principal amounts, will bear interest at the rates and will mature in the years and amounts as set forth on the inside cover pages of this Official Statement. The 2022 Bonds will be issued in denominations of $5,000 or any integral multiple thereof. The 2022 Bonds will be dated and will bear interest from their date of original issuance. Interest on the 2022 Bonds will be payable semiannually on each February 1 and August 1, commencing August 1, 2022. Interest on the 2022 Bonds will be calculated on the basis of a 360-day year consisting of twelve 30-day months. The 2022 Bonds will be registered in the name of Cede & Co., the nominee of The Depository Trust Company, New York, New York (“DTC”), and held in DTC’s book-entry system. So long as the 2022 Bonds are held in the book-entry system, DTC or its nominee will be the registered owner of the 2022 Bonds for all purposes of the Indenture. For purposes of this Official Statement, DTC or its nominee, and its successors and assigns, are referred to as the “Securities Depository.” So long as the 2022 Bonds are held in book-entry form through DTC, all payments with respect to principal of, premium, if any, and interest on each 2022 Bond will be made pursuant to DTC’s rules and procedures. See Appendix D.

Resolution No. 2022-10

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Redemption Provisions
Optional Redemption of the 2022 Bonds. The 2022 Bonds with stated maturities on or after August 1, 2033, are subject to redemption prior to their respective stated maturities, at the option of the City and from any source of available funds, as a whole or in part on August 1, 2032, or any date thereafter, and by lot within each maturity in integral multiples of $5,000, at a Redemption Price equal to the principal amount thereof plus accrued interest thereon to the redemption date, without premium.

Notice of Redemption. The Trustee is to give notice of the redemption of any 2022 Bonds by first class mail, postage prepaid, not more than 60 nor less than 30 days before the redemption date to the Owners of any 2022 Bonds to be redeemed (in whole or in part) at their addresses appearing in the Bond Register.

Such notice will specify the maturity date of the 2022 Bonds to be redeemed, the redemption date and the place or places where amounts due upon such redemption will be payable and, if less than all of the 2022 Bonds of any like maturity are to be redeemed, the letters and numbers or other distinguishing marks of such 2022 Bonds to be redeemed, and, in the case of a 2022 Bond to be redeemed in part only, such notice will also specify the respective portion of the principal amount thereof to be redeemed.

In the event that funds required to pay the Redemption Price of 2022 Bonds to be redeemed at the option of the City are not on deposit with the Trustee at the time the notice of redemption of such 2022 Bonds is given, such notice will state that such redemption is conditioned upon the receipt by the Trustee, on or prior to the date fixed for such redemption, of moneys sufficient to pay the Redemption Price of the 2022 Bonds to be redeemed, and that if such moneys have not been so received, said notice will be of no force and effect and the City will not be required to redeem such 2022 Bonds. In the event that a notice of redemption of 2022 Bonds contains such a condition and such moneys are not so received, the redemption of 2022 Bonds as described in the conditional notice of redemption will not be made and the Trustee, within a reasonable time after the date on which such redemption was to occur, is to give notice to the persons and in the manner in which the notice of redemption was given that such moneys were not so received and that there will be no redemption of 2022 Bonds pursuant to the conditional notice of redemption.

Receipt of notice of redemption is not a condition precedent to the redemption of 2022 Bonds and failure of any Owner of a 2022 Bond to receive any such notice or any insubstantial defect in such notice does not affect the validity of the proceedings for the redemption of 2022 Bonds.

SECURITY AND SOURCES OF PAYMENT
Pledge Effected by the Indenture
The payment of the principal and Redemption Price of and interest on the 2022 Bonds is secured by a pledge of the Trust Estate under the Indenture. The Trust Estate consists of: (i) the Revenues; (ii) all amounts on deposit in the Light and Power Fund, including the investments, if any, thereof; and (iii) all amounts on deposit in the Funds, other than the Rebate Fund, held by the Trustee under the Indenture, including the investments, if any, thereof. The pledge of the Trust Estate in the Indenture is subject to the provisions of the Indenture permitting the application thereof for the purposes and on the terms and conditions set forth therein.

The 2022 Bonds and all other Bonds issued under the Indenture are equally and ratably secured by the pledge of the Trust Estate pursuant to the Indenture. The 2022 Bonds and all other Bonds issued under the Indenture are equally and ratably payable from the Net Revenues, amounts in the Light and Power Fund other than the Operating Reserve, and amounts held in the Funds, other than the Rebate Fund, held by the Trustee under the Indenture. The City has and, in the future, may issue or incur other Parity Obligations which are secured by a pledge of the Trust Estate. The City has issued under the Indenture, and there is currently outstanding $415,475,000 aggregate principal amount of Electric System Revenue Bonds (of which $61,235,000 is expected to be refunded by the 2022 Bonds), consisting of the 2008A Bonds, the 2012A Bonds, the 2012B Bonds, the 2015A Bonds, the 2020A Bonds and the 2021A Bonds. See the caption “THE Resolution No. 2022-10

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ELECTRIC SYSTEM—Outstanding Electric System Parity Obligations” for more information about outstanding Parity Obligations.
“Revenues” is defined in the Indenture to include all gross income and revenue received or receivable by the City from the ownership or operation of the Electric System, including all rates and charges for the Electric Service and the other services and facilities of the Electric System, all proceeds of insurance covering business interruption loss relating to the Electric System and all other income and revenue howsoever derived by the City from the ownership or operation of the Electric System or otherwise arising from the Electric System, including all net receipts pursuant to Public Finance Contracts entered into in connection with any Obligations or program of investments relating to the Electric System and all income from the deposit or investment of any money in the Light and Power Fund, but excluding: (i) proceeds of taxes; (ii) refundable deposits made to establish credit and advances; (iii) contributions in aid of construction; and (iv) line extension fees. The proceeds of the utility users’ tax which is described under the caption “—Transfers to General Fund” do not constitute Revenues and are not pledged to payment of the Bonds. “Net Revenues” is defined in the Indenture to mean, for any period of time, the Revenues for such period less Operation and Maintenance Expenses for such period. “Operation and Maintenance Expenses” is defined in the Indenture to mean the costs paid or incurred by the City for operating and maintaining the Electric System including, but not limited to: (a) all costs of electric energy and power generated or purchased by the City for resale, costs of transmission, fuel supply and water supply in connection with the foregoing; (b) all costs and expenses of management of the Electric System; (c) all costs and expenses of maintenance and repair, and other expenses necessary or appropriate in the judgment of the City to maintain and preserve the Electric System in good repair and working order; (d) all administrative costs of the several departments of the City that are charged directly or apportioned to the operation or maintenance of the Electric System, such as salaries and wages (including retirement benefits) of employees, overhead, taxes (if any) and insurance premiums; (e) payments in lieu of taxes to any public agency other than the City in connection with the Electric System; (f) all costs, expenses and charges of the City required to be paid by it to comply with the terms of any Issuing Instrument authorizing the issuance of Parity Obligations, such as compensation, reimbursement and indemnification of the trustee, remarketing agent, broker-dealer or auction agent or fees and expenses of Independent Certified Public Accountants, Independent Engineers and other consultants; (g) the fees, expenses and indemnification of Credit Providers and Reserve Financial Guaranty Providers; (h) all amounts required to be paid by the City under contracts with joint powers agencies for the purchase of capacity rights in an electric generating station or electric transmission facilities, transmission capability or any other commodity, right or service in connection with the Electric System, which contracts require payments to be made by the City thereunder to be treated as operation and maintenance expenses of the Electric System; (i) all deposits to be made to a rebate fund established with respect to Parity Obligations to provide for any rebate to the United States required to maintain the Tax-Exempt status of interest on such Parity Obligations; (j) any cost or expense paid by the City to comply with requirements of law applicable to the Electric System or the City’s ownership or operation thereof or in any capacity with respect thereto or any activity in connection therewith, including without limitation the public benefit uses required by Section 385 of the California Public Utilities Code; and (k) any other costs or expense which, in accordance with Generally Accepted Accounting Principles, is to be treated as a cost of operating or maintaining the Electric System; but excluding in all cases depreciation, replacement and obsolescence charges or reserves therefor, amortization of intangibles, Franchise Payments to the City and Unrealized Items. Except as provided in clause (d) above, no transfer of Revenues to the City, including Franchise Payments, will constitute an Operation and Maintenance Expense.

For a description of certain obligations payable as Operation and Maintenance Expenses, see the caption “THE ELECTRIC SYSTEM–Power Supply Resources.”
Resolution No. 2022-10

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“Operating Reserve” is defined in the Indenture to mean, as of any date of calculation, an amount in the Light and Power Fund equal to the amount contained in the then current Budget for Operation and Maintenance Expenses for the four months next succeeding the month in which the date of calculation occurs. “Obligations” is defined in the Indenture to include: (a) obligations with respect to borrowed money such as bonds, notes or other evidences of indebtedness, installment purchase payments under any contract and lease payments under any financing or capital lease (determined to be such in accordance with Generally Accepted Accounting Principles) which are payable from the Net Revenues and/or amounts in the Light and Power Fund; (b) obligations to replenish any debt service reserve fund with respect to obligations of the City described in clause (a); (c) obligations under a Public Finance Contract payable from the Net Revenues and/or amounts in the Light and Power Fund; and (d) Credit Provider Reimbursement Obligations. “Public Finance Contract” is defined in the Indenture to mean: (a) any contract providing for payments based on levels of, or changes in, interest rates, currency exchange rates, stock or other indices; (b) any contract to exchange cash flows or a series of payments; or (c) any contract to hedge payment, currency, rate spread or similar exposure, including but not limited to interest, any interest rate swap agreement, currency swap agreement, forward payment conversion agreement or futures contract, any contract providing for payments based on levels of, or changes in, interest rates, currency exchange rates, stock or other indices, any contract to exchange cash flows or a series of payments, or any contract, including, without limitation, an interest rate floor or cap, or an option, put or call, to hedge payment, currency, rate, spread or similar exposure, between the City and a counterparty.
“Franchise Payments” is defined in the Indenture to mean the payment in lieu of franchise tax added to each Electric System customer bill to be paid to the City’s General Fund and any successor or replacement payment.

For definitions of certain other terms used herein, see Appendix B.

The issuance of the 2022 Bonds does not directly, indirectly or contingently obligate the City to levy or pledge any form of taxation or to make any appropriation for their payment. The 2022 Bonds are not secured by a legal or equitable pledge of, or lien or charge upon, any property of the City or any of its income or receipts except the Trust Estate pledged pursuant to the Indenture which is subject to the provisions of the Indenture permitting the application thereof for the purposes and on the terms and conditions set forth therein. Neither the faith and credit nor the taxing power of the City, the State or any other public agency is pledged to the payment of the principal of, or premium, if any, or interest on, the 2022 Bonds. The 2022 Bonds do not constitute a debt, liability or obligation of the State or any public agency other than the special obligation of the City as provided in the Indenture. The members of the City Council of the City, and the officers and employees of the City, will not be individually liable on the 2022 Bonds or in respect of any undertakings by the City under the Indenture.

Deposit and Application of Revenues
Pursuant to the Indenture, the City is to deposit or cause to be deposited all Revenues into the Light and Power Fund upon receipt thereof. Without limiting the provisions of the Indenture regarding investment of certain funds, the City is to apply the Revenues for each Fiscal Year, as received, first to the payment of Operation and Maintenance Expenses then due and payable, and then to the payment of amounts required to be paid with respect to Debt Service on, and reserves for, the Bonds and other Parity Obligations. The City may then apply any remaining Revenues to any lawful purpose in connection with the Electric System, including the payment of amounts required to be paid with respect to Subordinate Obligations, the payment of Costs of Capital Improvements and, to the extent permitted by the Indenture, to transfers to the City’s General Fund.

Resolution No. 2022-10

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Payments to Trustee for Bonds
During each Fiscal Year the City will pay the Trustee, from the Net Revenues of such Fiscal Year, the following amounts at the following times:
(a) on the fourth Business Day prior to each Interest Payment Date for any Outstanding Bonds, an amount equal to the interest payable on the Outstanding Bonds on such Interest Payment Date; provided, however, that such payments will be reduced by any available amounts on deposit in the Interest Account which are to be applied to such upcoming interest payment; (b) on the fourth Business Day prior to each date on which the principal of Outstanding Bonds which are Serial Obligations mature, an amount equal to the principal of such Outstanding Bonds maturing on such date; provided, however, that such payments will be reduced by any available amounts on deposit in the Principal Account which are to be applied to the upcoming principal payment; (c) on the fourth Business Day prior to each Sinking Fund Installment due date for Outstanding Bonds which are Term Obligations, an amount equal to the Sinking Fund Installments due with respect to all Outstanding Bonds which are Term Obligations on such Sinking Fund Installment due date; provided, however, that such payments will be reduced by any available amounts on deposit in the Sinking Fund Account which are to be applied to the redemption or payment of such Bonds on such Sinking Fund Installment due date and by the amount by which the City’s obligations to make payments with respect to such Sinking Fund Installments have been satisfied pursuant to the Indenture; (d) at least one Business Day prior to each date fixed for the redemption of Outstanding Bonds (other than from Sinking Fund Installments and other than an optional redemption of Bonds as to which a conditional notice of redemption has been sent to the Owners pursuant to the Indenture), an amount equal to the Redemption Price of the Bonds to be redeemed;
(e) on the date on which the principal of or interest on any Outstanding Bond becomes due and payable, other than as provided in clauses (a) through (d) above, the City will pay an amount in funds which are immediately available to the Trustee by 10:00 a.m. (Pacific Time) on the due date, equal to the principal of and interest on the Outstanding Bonds due on such date; (f) in the event that on any date upon which the City is to make a payment pursuant to clauses (a), (b), (c), (d), and/or (e) above and the amount of Net Revenues and the amount in the Light and Power Fund available therefor in accordance with the Indenture is not sufficient to make such payment and any payment required to be made on such date with respect to the principal and redemption premium of and interest on other Parity Obligations (including, with respect to transactions under Qualified Swap Agreements, the Net Payments due), then the City will apply the Net Revenues and amounts in the Light and Power Fund available therefor in accordance with the Indenture to the payments required by clauses (a), (b), (c), (d), and/or (e) above and such payments with respect to the other Parity Obligations ratably (based on the respective amounts to be paid), without any discrimination or preferences;
(g) on the Business Day preceding each July 1, the City will pay an amount for deposit in the Debt Service Reserve Fund, such that, after the deposit, the amount on deposit in such Fund is at least equal to the Debt Service Reserve Requirement, including the amount of any Reserve Financial Guaranties on deposit in the Debt Service Reserve Fund; and
(h) in the event that on any date upon which the City is to make a payment pursuant to clause (g) above and the amount of Net Revenues and the amount in the Light and Power Fund available therefor in accordance with the Indenture is not sufficient to make such payment and any payment required to be made on such date with respect debt service reserves for other Parity Obligations, then the City, after making the payments required by clauses (a), (b), (c), (d), (e), and (f) above, will apply the Net Revenues and amounts in Resolution No. 2022-10

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the Light and Power Fund available therefor in accordance with the Indenture to the payments required by paragraph (g) above and such payments with respect to debt service reserves for Parity Obligations ratably (based on the respective amounts to be paid), without any discrimination or preferences.

In the event that on any date all payments required to be made pursuant to the preceding paragraphs are not made in full from Net Revenues, then the City will make up any deficiency from amounts in the Light and Power Fund after setting aside in the Light and Power Fund an amount equal to the Operating Reserve. In the event that on any date all payments required to be made pursuant to the preceding clauses (a) through (h) are not made in full, then no payment will be made which has a priority lower than the delinquent payment until all delinquent payments with a higher priority have been made in full.

Rate Covenant
Pursuant to the Indenture, the City has covenanted, at all times, to fix, prescribe and collect rates and charges for the Electric Service of the Electric System during each Fiscal Year which will be at least sufficient to yield: (a) Adjusted Revenues for such Fiscal Year at least equal to the sum of the following for such Fiscal Year: (i) Operation and Maintenance Expenses; (ii) Adjusted Debt Service; and (iii) all other payments required to be paid in such Fiscal Year to meet any other obligations of the City which are charges, liens or encumbrances upon or payable from the Revenues (including Net Revenues), including all amounts owed to a Credit Provider under the terms of its Credit Support Agreement and amounts owed to a Reserve Financial Guaranty Provider under the terms of its Reserve Financial Guaranty; and (b) Adjusted Revenues less Operation and Maintenance Expenses for such Fiscal Year equal to at least 110% of Adjusted Debt Service for such Fiscal Year.

The City may make adjustments from time to time in such fees and charges and may make such classification thereof as it deems necessary, but will not reduce the rates and charges then in effect unless the Adjusted Revenues and the Adjusted Net Revenues from such reduced rates and charges will at all times be sufficient to meet the foregoing requirements.
“Adjusted Revenues” is defined in the Indenture to mean, for any period of time, the Revenues for such period less the amount of such Revenues which have been deposited in the Expense Stabilization Fund during such period plus the amount of withdrawals during such period from the Expense Stabilization Fund. “Adjusted Debt Service” is defined in the Indenture to mean, for any period of time, the Debt Service with respect to Outstanding Parity Obligations for such period minus the sum of the amount of such Debt Service to be paid during such period from the proceeds of Parity Obligations or Subordinate Obligations as set forth in a certificate of the City.

Debt Service Reserve Fund
The Debt Service Reserve Fund is required to be maintained in an amount equal to the Debt Service Reserve Requirement. Amounts in the Debt Service Reserve Fund are to be used to pay principal and Redemption Price of and interest on the Bonds then due and payable in the event of any insufficiency in the amount on deposit in the Debt Service Fund available for such payment. “Debt Service Reserve Requirement” means, as of any date of calculation, an amount equal to the least of: (a) 10% of the initial offering price to the public of the Bonds as determined under the Code; or (b) the greatest amount of Debt Service on the Outstanding Bonds in any Fiscal Year during the period commencing with the Fiscal Year in which the determination is being made and terminating with the last Fiscal Year in which any Outstanding Bond is due; or (c) 125% of the sum of the Debt Service for all Fiscal Years during the period commencing with the Fiscal Year in which such calculation is made (or if appropriate, the first full Fiscal Year following the issuance of any Bonds) and terminating with the last Fiscal Year in which any Debt Service on an Outstanding Bond is due, divided by the number of such Fiscal Years, all as computed and Resolution No. 2022-10

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determined by the City and specified in writing to the Trustee; provided, however that in determining Debt Service with respect to any Bonds that constitute Variable Rate Bonds, the interest rate on such Bonds for any period as to which such interest rate has not been established will be assumed to be: (i) with respect to Bonds which are Tax-Exempt, the ten year historical average of the SIFMA Index ending with the week preceding the date of calculation; and (ii) with respect to Bonds which are not Tax-Exempt, the ten year historical average of the One Month USD LIBOR Rate ending with the month preceding the date the calculation is made or if the One Month USD LIBOR Rate is not available for such period, another similar rate or index selected by the City. Upon the issuance of the 2022 Bonds and the refunding of the Refunded 2012 Bonds, the Debt Service Reserve Requirement will be $32,821,953.

Pursuant to the Indenture, in lieu of the required deposits and transfers of money to the Debt Service Reserve Fund, the City may cause to be deposited in the Debt Service Reserve Fund a Reserve Financial Guaranty or Guaranties in an amount equal to the difference between the Debt Service Reserve Requirement and the sums, if any, then on deposit in the Debt Service Reserve Fund or being deposited in such fund concurrently with such Reserve Financial Guaranty or Guaranties. There is currently no such Reserve Financial Guaranty in the Debt Service Reserve Fund.
“Reserve Financial Guaranty” is defined in the Indenture to mean a policy of municipal bond insurance or surety bond issued by a municipal bond insurer or a letter of credit issued by a bank or other institution if the obligations insured by such insurer or issued by such bank or other institution, as the case may be, have ratings at the time of issuance of such policy or surety bond or letter of credit in the highest rating category (without regard to qualifiers) by S&P and Moody’s and, if rated by A.M. Best & Company, also in the highest rating category (without regard to qualifiers) by A.M. Best & Company.

Pursuant to the Fifth Supplemental Indenture, the definition of “Reserve Financial Guaranty” set forth above will be amended and restated as set forth below at such time as all of the 2008A Bonds, the 2012A Bonds, the 2012B Bonds and the 2015A Bonds are no longer Outstanding:
“Reserve Financial Guaranty” means a policy of municipal bond insurance or surety bond issued by a municipal bond insurer or a letter of credit issued by a bank or other institution if the obligations insured by such insurer or issued by such bank or other institution, as the case may be, have ratings from the rating agencies then rating the Bonds at the time of issuance of such policy or surety bond or letter of credit in the same rating category (without regard to qualifiers) as the Bonds which are supported by such Reserve Financial Guaranty.” Expense Stabilization Fund
Moneys may be deposited in the Expense Stabilization Fund held by the Trustee in such amounts, at such times and from such sources as determined by the City in its sole discretion. Moneys on deposit in the Expense Stabilization Fund may be withdrawn by the City at any time that no Event of Default exists under the Indenture and applied to any lawful purpose in connection with the Electric System, including without limitation, payment of Operation and Maintenance Expenses, payment of Debt Service on the Bonds or other Parity Obligations, payment of principal or premium or interest on Subordinate Obligations, payment of costs of Capital Improvements or payment of the costs of issuance of Parity Obligations or Subordinate Obligations.

For any period of time, any amounts so withdrawn from the Expense Stabilization Fund are included in the calculation of Adjusted Revenues for such period of time. See the caption “—Rate Covenant.” If an Event of Default under the Indenture has occurred and is continuing, the Trustee will transfer all moneys in the Expense Stabilization Fund to the Interest Account and the Principal Account of the Debt Service Fund as provided in the Indenture. On November 18, 2021, the City transferred $25,000,000 from the Light and Power Fund to the Expense Stabilization Fund and, as of April 1, 2022, there was approximately $38,922,063 on deposit in the Expense Stabilization Fund.

Resolution No. 2022-10

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Outstanding Electric System Obligations
Upon the issuance of the 2022 Bonds and the refunding of the Refunded 2012 Bonds, the 2008A Bonds, the 2012B Bonds not refunded by the 2022 Bonds, the 2015A Bonds, the 2020A Bonds, the 2021A Bonds and the 2022 Bonds will be the only Parity Obligations of the City payable from the Electric System Net Revenues or amounts in the Light and Power Fund. For a description of other obligations of the City payable from Electric System Revenues, including certain “take-or-pay” obligations payable as Operation and Maintenance Expenses, see the caption “THE ELECTRIC SYSTEM—Power Supply Resources.” Additional Parity Obligations
The City has covenanted pursuant to the Indenture that it will not issue any bond, note or other evidence of indebtedness payable from or secured by the Trust Estate or any part thereof on a basis which is:
(i) in any manner prior or superior to the lien on, pledge of and security interest in the Trust Estate securing the Outstanding Bonds pursuant to the Indenture; or (ii) except for other Parity Obligations with respect to the Revenues and/or amounts in the Light and Power Fund, in any manner on a parity with the lien on, pledge of and security interest in the Revenues and amounts in the Light and Power Fund securing the Outstanding Bonds pursuant to the Indenture. Nothing in the Indenture prevents the City from issuing Subordinate Obligations.

Pursuant to the Indenture, the City may, at any time and from time to time, issue Additional Parity Obligations, provided that the City obtains or provides either:
(a) a certificate or certificates, prepared by the City or at the City’s option by an Independent Engineer, showing: (i) that the Adjusted Net Revenues for any 12 consecutive month period within the 18 consecutive months ending immediately prior to the issuance of such Additional Parity Obligations selected by the City in its sole discretion (the “Calculation Period”), amounts to at least 1.25 times the Maximum Adjusted Annual Debt Service on all Parity Obligations to be Outstanding immediately after the issuance of the proposed Additional Parity Obligations; and (ii) that the Net Revenues for such applicable Calculation Period amount to at least 1.00 times the Maximum Adjusted Annual Debt Service on all Parity Obligations to be Outstanding immediately after the issuance of the proposed Additional Parity Obligations; or (b) a certificate or certificates, prepared by the City or at the City’s option by an Independent Engineer, showing: (i) that the projected Adjusted Net Revenues during each of the five complete Fiscal Years beginning with the first Fiscal Year following the issuance of such Parity Obligations in which interest thereon is not capitalized, in whole or in part, amount to at least 1.25 times the Maximum Adjusted Annual Debt Service on all Parity Obligations to be Outstanding during such Fiscal Years; and (ii) that the projected Net Revenues during each of the five complete Fiscal Years beginning with the first Fiscal Year following the issuance of such Parity Obligations in which interest thereon is not capitalized, in whole or in part, amount to at least 1.00 times the Maximum Adjusted Annual Debt Service on all Parity Obligations to be Outstanding during such Fiscal Years.

For purposes of preparing such certificate or certificates, the City and any Independent Engineer will utilize and rely on financial statements prepared by the City which have been audited by an Independent Certified Public Accountant but may utilize and rely upon the books and records of the City or any unaudited financial statements prepared by the City if audited financial statements for the particular Calculation Period selected by the City are not available.

Notwithstanding the foregoing (and without satisfying the revenue tests above), the City may at any time but subject to the applicable requirements of the Indenture: (i) issue or enter into an obligation or commitment which is a Qualified Swap Agreement; (ii) issue Refunding Parity Obligations, provided that the Aggregate Adjusted Annual Debt Service for all Parity Obligations to be Outstanding after the issuance of such Refunding Parity Obligations will not exceed the Aggregate Adjusted Annual Debt Service for all Parity Resolution No. 2022-10

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Obligations Outstanding immediately prior to the issuance of such Refunding Parity Obligations in each Fiscal Year from the date of issuance of such Refunding Parity Obligations to the last Fiscal Year in which any Parity Obligations Outstanding immediately prior to and subsequent to the issuance of such Refunding Parity Obligations are scheduled to remain Outstanding; and (iii) enter into Credit Support Instruments or otherwise become obligated for Credit Provider Reimbursement Obligations with respect to Parity Obligations.

See Appendix B for the definition of certain terms used above.

Transfers to General Fund
As shown in the table below, in addition to its portion of the allocated administrative costs of the City payable from the Light & Power Fund as Operation and Maintenance Expenses, the City has historically transferred Net Revenues remaining after the payment of debt service on Bonds from the Light and Power Fund to the City’s General Fund in order to cover certain other services provided by the General Fund for the benefit of the Electric System. The City has covenanted in the Indenture not to transfer Net Revenues for any Fiscal Year to the City’s General Fund, including the Franchise Payment, in an amount exceeding the Net Transferable Income for such Fiscal Year, which amount will be determined at the end of such Fiscal Year; provided that so long as an Event of Default has occurred and is continuing under the Indenture, the City may not transfer any Net Transferable Income to the City’s General Fund. “Net Transferable Income” means, with respect to any Fiscal Year, the Net Revenues for such Fiscal Year less the Debt Service for such Fiscal Year; provided that, the Net Transferable Income for any Fiscal Year may not exceed the difference between: (i) 11.5% of the retail sales for such Fiscal Year; and (ii) the sum of: (A) the amount paid pursuant to clause (d) of the definition of Operation and Maintenance Expenses in such Fiscal Year; plus (B) the amount, if any, paid to the City as a Franchise Payment in such Fiscal Year.

In 2018, City voters approved a utility users’ tax (the “UUT”), including a 6% tax on industrial and commercial users of electric services which was phased in over a period from Fiscal Year 2019 through Fiscal Year 2021 and will terminate in Fiscal Year 2027. The City expects that the collection of the UUT will enable the City to reduce transfers from the Electric System to the General Fund during the period while the UUT is collected, as UUT proceeds will support General Fund activities that have historically been funded from Electric System transfers. The Electric System will continue to make Franchise Payments to the General Fund while the UUT is being collected. See the caption “—Pledge Effected by the Indenture.” Resolution No. 2022-10

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The following table shows the amount of transfers from the Light and Power Fund to the City’s General Fund for the last five Fiscal Years and the amount projected for the current Fiscal Year.

CITY OF VERNON ELECTRIC SYSTEM
Transfers to General Fund
Fiscal Year Ended
June 30
Amount of
Transfer(1)
2017 $13,121,515
2018(2) 14,344,504
2019(3) 4,239,557
2020(3) 4,582,784
2021(3) 4,781,720
2022(3) (4) 5,093,787

(1) Includes Franchise Payments; does not include City-allocated administrative expenses constituting Operation and Maintenance Expenses. See the limitation regarding Net Transferable Income above. (2) The Electric System received a transfer in from the Successor Agency to the City of Vernon Redevelopment Agency in the amount of $22,595,532 in Fiscal Year 2018 (reflecting redevelopment bond proceeds that the City elected to apply to Electric System capital projects), resulting in a net transfer in to the Light and Power Fund of $8,251,028. (3) Reflects Franchise Payments only. Reduction beginning in Fiscal Year 2019 reflects approval of UUT. (4) Projected. Subject to change.

Source: City of Vernon.

See the caption “CONSTITUTIONAL LIMITATIONS ON TAXES AND FEES—Articles XIIIC and XIIID of the State Constitution” for a discussion of certain limitations on and case decisions relating to transfers from municipal electric utility funds to general funds. The City sets its rates and its budget with the expectation that certain transfers will be made from the Electric System to the City’s General Fund in accordance with the restrictions set forth in the Indenture. In the event that transfers are further restricted, the City does not believe that any such further restrictions would have a material adverse effect on the financial position of the Electric System. However, such further restrictions on transfers may cause the City to evaluate new strategies to generate revenues to fund services provided by the City.

Limitations on Remedies
The rights of the Owners of the 2022 Bonds are subject to the limitations on legal remedies against cities in the State. Additionally, enforceability of the rights and remedies of the Owners of the 2022 Bonds, and the obligations incurred by the City, may become subject to the following: the United States Bankruptcy Code and applicable bankruptcy, insolvency, reorganization, moratorium or similar laws relating to or affecting the enforcement of creditors’ rights generally, now or later 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 appropriate 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 2022 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.

Resolution No. 2022-10

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GENERAL INFORMATION REGARDING

THE CITY AND THE SERVICE AREA
General
The City was incorporated in 1905 under the general laws of the State. City voters approved a charter in 1988 and the City thereafter became a charter city. The City has a land area of approximately 5.2 square miles and an estimated population of 295 people as of January 1, 2021. Land use in the City primarily consists of industrial development, with small areas devoted to commercial and residential uses. The City provides a wide range of services, such as public utilities (including water, gas, fiber and electric services), police protection and public works. The City contracts with the County of Los Angeles Fire Department for its fire services.

The City is located in the County of Los Angeles (the “County”), approximately 5 miles south of downtown Los Angeles. The City has extensive rail lines running through it, as well as two large intermodal freight yards at the City northern boundaries, to serve its industrial customer base. It is also located along Interstate 710 and is in close proximity to Interstates 5, 10, 105 and 110. With its location along or near these freeways, its close proximity to the Ports of Los Angeles and Long Beach and the Los Angeles International Airport, and the rail lines within the City, the City has access to a significant transportation network. The City has diversified from its origins as a hub for livestock businesses. There are currently over 1,600 industrial firms employing approximately 37,000 people within the City.

The City established its Electric System in 1933. The City operates the Electric System through its public utilities department (known as Vernon Public Utilities). The Electric System provides service to the entire 5.2 square mile geographic area of the City. The service area is largely built out and primarily encompasses industrial and commercial businesses, with small areas of residential use. In Fiscal Year 2021, industrial and commercial customers purchased approximately 99% of the electricity supplied by the City.

Because the Electric System’s customer base is primarily industrial and commercial, electricity demand is not dependent on population growth but is closely tied to regional, national and international economic conditions.

As of June 30, 2021, the City provides electric service to approximately 1,238 small industrial, 503 large industrial and 164 commercial, residential and other customers. The City’s Electric System is comprised of generation, transmission, and distribution facilities and includes approximately 4,318 poles, 8 electric substations, a combined cycle natural gas fired generating plant and its peak load of approximately 191 megawatts (“MWs”) occurred in 2021.

Governance and Management
City Council. The City is governed by a five-member City Council, the members of which are elected at large for staggered four year terms. Council members select a Mayor and Mayor Pro Tem from among the City Council. The current Mayor and City Council members and the expiration dates of their terms are set forth below.

CITY OF VERNON
Mayor and City Council Members
Name and Title Expiration of Term
Melissa Ybarra, Mayor April 2022
William “Bill” Davis, Mayor Pro Tem April 2023
Crystal Larios, Council Member April 2024
Leticia Lopez, Council Member April 2026
Judith Merlo, Council Member April 2025
Resolution No. 2022-10

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Management. The City Administrator, who is appointed by the City Council, serves as the City’s chief executive officer and is responsible for overseeing the daily operations of City departments. The City Administrator serves as an advisor to the City Council on policy matters, supports the informational and policymaking needs of the City Council, implements City Council decisions, and prepares, manages and implements the City’s annual budgets and capital improvement program.

Carlos R. Fandino, Jr. has served as the City Administrator since 2016. Mr. Fandino previously worked for the City’s Gas and Electric Department (now known as Vernon Public Utilities), where he managed the operations of the power plant and the distribution system for nearly 15 years. Mr. Fandino has served in a variety of capacities within such Department, including as General Manager. He previously served in the United States Marine Corps and is a Desert Storm/Desert Shield combat veteran. He obtained a Bachelor’s degree in Business & Management from Woodbury University in Burbank, graduating magna cum laude.

Other key personnel responsible for management of the Electric System include the Director of Finance/Treasurer and the General Manager of Public Utilities.

Scott Williams is the Director of Finance/Treasurer of the City. Mr. Williams has been with the City since 2019 and has over 20 years of financial management experience. Prior to coming to the City, Mr. Williams served as the Finance Director and Administrative Services Officer for the City of Signal Hill, California, and in various financial management positions in both the public and private sector. Mr. Williams obtained a Bachelor’s degree in Business Administration from The Master’s University, an MBA from California State University, Monterey Bay, and a Doctorate in Public Administration from California Baptist University in Riverside, California. Mr. Williams is a member of the California Society of Municipal Finance Officers, the California Municipal Treasurers Association, the Association of Certified Fraud Examiners and the Institute of Management Accountants.

Abraham Alemu is the General Manager of Public Utilities of the City. Mr. Alemu has been with the City since 1992, where for more than a dozen years he managed the Power Integrated/Resource team.

Mr. Alemu obtained a Bachelor’s degree in Electrical Engineering from California State University, Los Angeles, and a Masters in Business Administration from Woodbury University. Mr. Alemu is a Registered Professional Engineer in California and a member of the Institute of Electrical and Electronics Engineers.

The City Council also appoints a City Attorney who is responsible for advising the City Council on legal issues affecting the City.

Zaynah Moussa is the Interim City Attorney of the City, Ms. Moussa joined the Vernon City Attorney’s Office in 2013 as part of the City’s broad implementation of good governance measures and has practiced municipal law since 2009. Ms. Moussa obtained her Juris Doctor degree from Loyola Law School and a Bachelor’s degree in Political Science and Journalism from the University of Southern California, graduating cum laude.

Business and Industry Commission. In July 2014, the City established the Vernon Business and Industry Commission to advise, assist and make recommendations to the City regarding ways to make the City more attractive to employees, businesses and investors while appropriately considering the needs and concerns of the residential communities within and in close proximity to the City. The Business and Industry Commission represents the consolidation of two previously existing Ad Hoc Advisory Committees created and appointed by the City Council, one on Electric Rates and the other on Business Development. The Commission is comprised of seven members from the following categories who are appointed by the City Council: three City business representatives, two City real estate representatives, one employee of a business located in the City or who is a member of a labor union that represents workers at a business located in the City and one current City Council Member. The Business and Industry Commission meets quarterly to provide input and make recommendations to the City on a number of matters relating to or impacting business Resolution No. 2022-10

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and industrial development with the City, including electric rate adjustments. The input and recommendations provided by the Business and Industry Commission are not binding on the City.

Budget Process
The City prepares and adopts a budget on a modified accrual basis for each Fiscal Year which includes proposed expenditures and the means of financing such expenditures. Under the City’s budget procedure, the City Administrator submits a proposed budget to the City Council for the Fiscal Year commencing the following July 1. Prior to June 30 of each year, a public hearing is held and public notice is disseminated to obtain public comments and the budget is legally enacted by the City Council through the passage of a resolution. The City Council adopted the Fiscal Year 2022 budget on June 1, 2021.

Employees
As of April 1 2022, the City had approximately 208 full-time equivalent employees, of whom approximately 61 worked solely on behalf of the Electric System. These employees included 19 employees which are primarily employed with respect to the Malburg Generating Station (the “MGS”).

Certain employees of Vernon Public Utilities are represented by the International Brotherhood of Electrical Workers Local 47 (the “IBEW”) and the Teamsters Local 911 (the “Teamsters”). Relations between the City and the IBEW are governed by a Memorandum of Understanding which expires on June 30, 2022 and relations between the City and the Teamsters are governed by a Memorandum of Understanding which expires on June 30, 2022. Certain management, supervisory and professional employees are unrepresented. The City has never experienced a strike, slowdown or work stoppage.

The City provides certain pension and post-employment healthcare benefits for employees. For a discussion of the City’s long-term obligations associated with these plans, see the caption “FINANCIAL INFORMATION—Employee Benefit Obligations.”
City Insurance
The City maintains liability insurance coverage for amounts up to $20,000,000, with a $2,000,000 self-insured retention.

The City is self-insured for workers’ compensation liabilities for amounts up to $1,500,000 per occurrence and maintains excess coverage of $50,000,000.

The City maintains property insurance coverage for amounts up to $100,000,000, with a deductible of $25,000 for property damage and $250,000 for Power Generation Substations and Power Plant. Certain Electric System components, including poles and transmission lines, are not covered by property insurance.

The City does not carry earthquake coverage. See the captions “THE ELECTRIC SYSTEM—Seismic Activity and Other Natural Disasters.”
The City maintains directors and officers and employee dishonesty insurance coverage for amounts up to $1,000,000, with a $25,000 deductible.

The City maintains pollution insurance coverage for amounts up to $5,000,000, with deductibles of $25,000 for non-utility locations, divested locations and scheduled storage tanks, $50,000 for utility locations and $100,000 for natural gas pipeline.

The City has not settled any claims that exceeded its insurance coverages in the past three years.

Resolution No. 2022-10

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In addition, with respect to the MGS, the City maintains property and boiler & machinery insurance coverage for the amount up to $200,000,000 with a various deductible from $100,000 to $1,000,000, excess liability insurance coverage for the amount up to $100,000,000 with a $1,000,000 deductible and earthquake insurance coverage for the amount up to $50,000,000 with a $250,000 deductible.

The City can provide no assurance that it will maintain the above insurance coverage amounts while the 2022 Bonds are outstanding. See Appendix B under the caption “PARTICULAR COVENANTS— Insurance” for a description of insurance coverages that are required to be maintained while the 2022 Bonds are Outstanding.

Cybersecurity
The City relies on computers and technology to conduct its operations. The City and its departments face cyber threats from time to time including, but not limited to, hacking, viruses, malware and other forms of technology attacks. Recently, there have been significant cyber security incidents affecting municipal agencies, including a freeze affecting computer systems of the City of Atlanta, an attack on the City of Baltimore’s 911 system, an attack on the Colorado Department of Transportation’s computers and an attack that resulted in the temporary closure of the Port of Los Angeles’ largest terminal. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period.

The City employs a multi-level cyber protection scheme that includes firewalls, anti-virus software, anti-spam/malware software, intrusion protection and domain name system filtering software. The City also contracts with third party vendors to monitor and augment internal monitoring of the City’s computer systems.

Vernon Public Utilities recently performed an Electric System cybersecurity self-assessment, using the American Public Power Association’s Cybersecurity Scorecard (which is based on a United States Department of Energy Electricity Subsector Cybersecurity Capability Maturity Model) to assess cyber risk, plan improvements, prioritize investments and benchmark the Electric System’s security posture. The items addressed in the scorecard include maintaining an inventory of critical cyber or information technology assets, monitoring networks and assets for suspicious activities, planning for relocation of information systems, ensuring relevant employees are trained to respond to incidents, establishing emergency contact information for cyber specific incidents and planning new preventative measures. The City has also signed mutual assistance agreements with the California Utilities Emergency Association to send and receive mutual assistance for cyber security issues should they arise.

In November 2021, the City became aware that an unauthorized person or persons gained access to the email accounts of five City employees. Since becoming aware of the incident, the City initiated an investigation and retained a consultant to conduct a forensic evaluation regarding the incident as well as whether any personal identifiable information had been compromised. As of the date of this Official Statement, the evaluation is still ongoing. Neither the City nor the Electric System has suffered any material financial consequences to date as a result of the incident. No assurances can be given that the City’s security and operational control measures will be successful in guarding against all future cyber threats and attacks.

The results of any attack on the City’s computer and technology could negatively impact the Electric System’s operations, and the costs related to such attacks could be substantial.

COVID-19
The spread of the novel strain of coronavirus (and variants thereof) and the disease it causes (now known as “COVID-19”) has had significant negative impacts throughout the world, including in California. In 2020, the World Health Organization declared the COVID-19 outbreak to be a pandemic, and states of emergency have been declared by the United States, the State and numerous counties throughout the State, including in the County. The purpose behind these declarations was to coordinate and formalize emergency Resolution No. 2022-10

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actions across federal, state and local governmental agencies, and to proactively prepare for a wider spread of the virus.

On March 19, 2020, in an effort to slow the spread of COVID-19, Governor Newsom issued Executive Order N-33-20 ordering individuals living in the State to stay home or at their place of residence except for specified exceptions, including exceptions for certain sectors of the workforce that were classified as providing essential services and products, which allowed businesses and workers in such sectors to continue to operate on-site operations while Executive Order N-33-20 was effective. On June 11, 2021, Governor Newsom issued two executive orders, which became effective on June 15, 2021, which had the effect of rescinding a majority of the COVID-19-related restrictions and providing a timeline for gradually lifting certain of the other restrictions that were not fully rescinded on June 15, 2021.

A majority of the customers of the City’s Electric System operate businesses that were considered to provide essential services and products under Executive Order N-33-20 and, as a result, the City experienced a relatively stable electric load throughout the COVID-19 pandemic. The Electric System’s 20 largest customers account for approximately 61% of the Electric System’s revenues, and since the start of the COVID-19 pandemic (March 2020), such customers have remained in operation without interruption. For information regarding the City’s load requirements over the past five Fiscal Years, see the caption “THE ELECTRIC SYSTEM—Power Supply Resources.” For information regarding the types of businesses comprising the Electric System’s largest customers, see the caption “THE ELECTRIC SYSTEM—Largest Customers.” Historically, the annual write-offs for uncollectible accounts have been less than 0.2% of gross billings of the Electric System. Since the onset of the COVID-19 pandemic, write-offs for uncollectible accounts has increased to approximately 1% of gross billings for Fiscal Year 2021, which was primarily attributable to small business customers. To help mitigate the economic impact of COVID-19 and the related governmental regulations on its customers, the City implemented a payment deferral program for all customers of the City utilities, which included the suspension of the disconnection of services by City utilities for nonpayment of utility bills for a period beginning in April 2020 and extending through June 2021. When the deferral program concluded, none of the customers of the Electric System were moved into disconnection status.

The City has been allocated approximately $1.1 million under the California Department of Community Services and Development California Arrearage Payment Program (“CAPP”), to aid the accounts that have fallen behind during the period of May 4, 2020 through June 15, 2021, which in turn is expected by the City to lower the uncollectible revenue amount as funds are received. As of April 1, 2022, the City has received $670,915.75 of such funding. See also the caption “THE ELECTRIC SYSTEM—Electric Rates— Uncollectible Accounts.”
With widespread vaccination currently underway in the United States and many countries worldwide, governmental-imposed stay-at-home orders and restrictions on operations of schools and businesses implemented to respond to and control the outbreak have been eased or eliminated. However, restrictions may be re-imposed in various jurisdictions from time to time as local conditions warrant. The City cannot predict whether any reinstatement or expansion of stay-at-home orders and travel or other restrictions will occur or when a full resumption of all economic activity will be achieved. The ultimate impact of COVID-19 on the operations and finances of the City or the Electric System is unknown and there can be no assurances that COVID-19 will not materially adversely impact the financial condition of the City or the Electric System in the future. There are many variables that will continue to contribute to the economic impact of the COVID-19 pandemic and the recovery therefrom, including the effectiveness of State and federal government relief programs and the timing for containment and treatment, new coronavirus strains, vaccinations efforts and vaccine hesitancy. The City cannot predict the extent or duration of such impacts.

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THE ELECTRIC SYSTEM
General
The City established its Electric System in 1933 through the acquisition of the existing electric distribution system within the City and the construction of a diesel generating station at Station A (located at 4990 Seville Avenue, Vernon, California) (“Station A”). The City operates the Electric System through its public utilities department (known as Vernon Public Utilities), with all revenues of the Electric System being credited to, and all expenses of the Electric System being payable from, the Light and Power Fund. The Electric System serves all electric users within the City, which consist primarily of industrial customers.

During Fiscal Year 2021, the Electric System supplied approximately 1,238 small industrial, 503 large industrial and 164 commercial, residential and other customers with approximately 1,150.5 million kilowatt hours (“kWhs”) of electric energy and had a peak demand of approximately 191 MWs. See the caption “The ELECTRIC SYSTEM—Customers, Retail Energy Sales, Revenues and Demand.” The City’s Electric System is comprised of generation, transmission, and distribution facilities and includes approximately 4,318 poles, 8 electric substations, a combined cycle natural gas fired generating plant and a peak load of approximately 191 MWs, which occurred in 2021.

The City’s electricity supply in Fiscal Year 2021 was provided from the following sources: (i) the MGS, a City-owned combined cycle natural gas fired generating plant (approximately 49%); (ii) the Palo Verde Nuclear Generating Station (“PVNGS”) (approximately 7.5%) pursuant to a power sales contract (the “PVNGS Contract”) with the Southern California Public Power Authority (“SCPPA”); (iii) short-term contracts for a term of less than one year (approximately 26%); (iv) power purchase agreements relating to four renewable energy projects (approximately 15.5%); and (v) other sources (approximately 2%). See the captions “—Power Supply Resources” and “—Renewable Energy Resources.” In order to comply with certain State mandates relating to renewable energy, the City expects that its supply of electricity from renewable resources will increase in the future. See the captions “—Renewable Energy Resources,” “—Integrated Resource Plan” and “—Developments Affecting the Power Supply.” Power Supply Resources
General. The Electric System’s current long-term power supply resources consist of the following:
(1) the MGS; (2) the PVNGS Contract with respect to a portion of SCPPA’s interest in PVNGS; (3) a Contract for Electric Service (the “CES”) with the United States Department of Energy Western Area Power Administration (“Western”) with respect to power from the hydroelectric power plant of the Hoover Dam (the “Hoover Uprating Project”); (4) two 5.75 MW simple cycle gas turbine generating units (collectively, the “H. Gonzales Generating Station”) at Station A used for reserve purposes; and (5) power purchase agreements entered into with SCPPA in connection with four renewable energy projects, as described under the caption “—Renewable Energy Resources.” Prior to the City’s reacquisition of the MGS in December 2021, the City purchased the 100% of the output of the MGS pursuant to the terms of a power purchase tolling agreement (the “Former PPTA”) with the private entity that owned and operated the MGS.

The MGS resource, the PVNGS Contract, the CES for Hoover, the H. Gonzales Generating Station and the four renewable energy projects described below are collectively referred to as the “Committed Resources.” For Fiscal Year 2021, the Committed Resources provided approximately 74% of the energy supplied by the Electric System to meet customer load. In addition to the Committed Resources, the City entered into short-term contracts to satisfy the remaining 26% of the load requirements of Electric System customers in Fiscal Year 2021.

Historically, the City has used energy purchased through short-term contracts rather than energy purchased from the MGS under the Former PPTA when such energy is available at a lower cost. While the Resolution No. 2022-10

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City expects to continue utilizing short-term contracts to satisfy load requirements which are not covered by its Committed Resources as and when necessary, the City may enter into long-term power purchase contracts (other than the Committed Resources) when the City determines that it is economically advantageous to do so or in connection with satisfying renewable energy portfolio requirements. See the caption “—Developments Affecting the Power Supply.”
For Fiscal Year 2022, the City anticipates that the Committed Resources will provide approximately 74% of the energy supplied by the Electric System in such Fiscal Year to meet customer load, while short-term contracts will provide approximately 26% of the energy supplied by the Electric System in such Fiscal Year.

The power supply resources of the Electric System used to satisfy the load requirements of the Electric System’s customers for the past five Fiscal Years are described in the following table.

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CITY OF VERNON ELECTRIC SYSTEM
Resources Used to Satisfy City Load Requirements(1)
Fiscal Year Ended June 30
2017 2018 2019 2020 2021
Short-Term Contracts(2)
Actual Energy(3) 197,441 247,788 259,643 208,927 310,671 Percentage of Total Energy 17.38% 21.98% 23.20% 18.38% 25.76% MGS(4)
Actual Energy(3) 732,594 575,439 575,379 642,697 594,954 Percentage of Total Energy 64.48% 51.04% 51.41% 56.54% 49.33% PVNGS
Actual Energy(3) 92,924 93,268 90,835 91,524 90,591
Percentage of Total Energy 8.18% 8.27% 8.12% 8.05% 7.51% Hoover Uprating Project
Actual Energy(3) 20,222 21,114 20,557 19,353 22,113
Percentage of Total Energy 1.78% 1.87% 1.84% 1.70% 1.83% City-Owned Generation(5)
Actual Energy(3) 1,023 3,390 4,141 1,649 653
Percentage of Total Energy 0.09% 0.30% 0.37% 0.15% 0.05% Puente Hills Landfill Project
Actual Energy(3) 31,934 57,796 45,820 49,410 44,429
Percentage of Total Energy 2.81% 5.13% 4.09% 4.35% 3.67% Astoria II
Actual Energy(3) 25,757 61,815 58,863 58,491 61,164
Percentage of Total Energy 2.27% 5.48% 5.26% 5.15% 5.07% Antelope 1
Actual Energy(3) 34,344 66,860 63,976 64,620 62,819
Percentage of Total Energy 3.02% 5.93% 5.72% 5.69% 5.21% Desert Harvest/Maverick Solar
Actual Energy(3) ---- ---- 18,877
Percentage of Total Energy ---- ---- 1.57%
City’s Total Load Requirement
Actual Energy(3) 1,136,239 1,127,470 1,119,215 1,136,671 1,206,271 Percentage of Total Energy 100.00% 100.00% 100.00% 100.00% 100.00%

(1) Totals may not add due to rounding.
(2) Contracts for a term of less than one year and spot market purchases. (3) In megawatt hours (“MWhs”).
(4) Reflects purchase of 100% of the output from the MGS. Prior to the reacquisition of the MGS by the City, the City purchased 100% of the output from the MGS pursuant to the terms of the Former PPTA. See the caption “—Power Supply Resources—Malburg Generating Station” below.
(5) Includes resources from the H. Gonzales Generating Station.

Source: City.

The City’s current power supply resources and the obligations of the Electric System in connection therewith are described below.

Malburg Generating Station.

General. The MGS is a 120 MW base load/134 MW full load combined cycle, natural gas-fired, electric power plant located within the City. The MGS was originally developed, owned and operated by the City. The MGS achieved commercial operation in October 2005. In 2008, the City sold the MGS to a private operator. On December 14, 2021, the City reacquired the MGS.

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Description of Facility. The MGS includes two Siemens (formerly Alstom) GTXI00 natural gas-fired combustion turbine generators and a steam turbine generator. The MGS includes duct burners and evaporative inlet air coolers and filters to achieve higher levels of power output in selected modes of operation. The MGS is connected to the Electric System’s distribution facilities at the Vernon Substation, located at Station A (as hereinafter defined). Originally developed and constructed by the City, the MGS was designed to provide approximately 60% of the City’s then-expected requirements for base load electric power.

The MGS has been a base load generation resource for the City since it achieved commercial operation in October 2005, and continued as such following the initial sale of the MGS, through arrangement set for the in the Former PPTA. Prior to the reacquisition of the MGS in December 2021, the City purchased 100% of the output of the MGS pursuant to the terms of the Former PPTA. In Fiscal Year 2021, the MGS provided 594,954 MWhs of energy to the City, comprising approximately 49% of the energy needed to satisfy the City’s load requirements. The City expects that the MGS will provide approximately 614,191 MWhs of energy to the City in Fiscal Year 2022, or an estimated 48% of the total needed to satisfy the City’s estimated load requirements.

Operation of MGS. The MGS is operated and managed by the City. Following the acquisition of the MGS in December 2021, the City hired 19 employees who were previously employed by management company that was contracted to operate the MGS by the prior owner to help facilitate the transition in ownership and operation from the private operator to the City.

Major maintenance, including parts supply, parts repair and labor of the MGS’s two natural gas-fired combustion turbines and the steam turbine are currently provided pursuant to an Amended and Restated Services Agreement, dated as of September 30, 2010, as amended (the “Long-Term Services Agreement”), by and between the former private operator of the MGS and Siemens Energy, Inc. (“Siemens”). The LongTerm Services Agreement was assumed by the City upon the acquisition of the MGS.

On March 16, 2022, Siemens and the City entered into a change order to the Long-Term Services Agreement (the “Change Order”) that modified certain terms relating to costs and the scheduled termination date of the Long-Term Services Agreement. Under the Change Order, the Long-Term Services Agreement is scheduled to expire with respect to each combustion turbine upon the earlier of (i) the date the applicable combustion turbine accumulates 59,999 equivalent operating hours from March 2018, (ii) the date the applicable combustion turbine accumulates 499 equivalent operating cycle from May 2022, or (iii) September 30, 2025.

The City is in the process of evaluating the impact of the terms of the Change Order and, as a result, has not prepared projections that account for the Long-Term Services Agreement as modified by the Change Order. The City, however, does not currently expect the Change Order to increase the expenses of the Electric System. The projected expenses included in this Official Statement reflect the costs, term and scheduled termination date of the Long-Term Services Agreement prior to being modified by the Change Order.

As part of its responsibilities under the Long-Term Services Agreement, on November 11 and 12, 2021, Siemens performed a borescope inspection of the MGS’s two gas-fired combustion turbines. In a letter from Siemens to the Seller dated November 15, 2021 (the “Siemens Letter”), Siemens noted that the inspection detected oxidation to one of the two turbines (“Combustion Turbine 1”). The Siemens Letter indicated that the deterioration had not exceeded engineering expectations. The Siemens Letter recommended that a second inspection be performed after Combustion Turbine 1 had operated for an additional 2,000 equivalent operating hours. The inspection was completed on February 6 and 7, 2022. Following the inspection, Siemens issued a report recommending the continued operation of Combustion Turbine 1 through May 1, 2022, when a regularly scheduled maintenance outage is scheduled to occur. During such outage, Siemens will replace the oxidized parts.

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Natural gas for the operation of the turbines is delivered to MGS through a 10-inch lateral connected to the City’s natural gas utility system. Operation of the MGS can require delivery of up to 21,300 million British Thermal units (“MMBtus”) of natural gas per day. The City, under the terms of the Former PPTA, had been supplying the MGS with natural gas primarily through bilateral contracts and spot market purchases, and the City expects to continue to obtain natural gas for operation of MGS through bilateral contracts and spot market purchases. See also the caption “THE ELECTRIC SYSTEM—Renewable Energy Resources—Current Renewable Energy Resources—Contracts for Bio-Gas,” The City continues to monitor the market for natural gas and may, in the future, enter into additional contracts for the purchase of natural gas for the MGS if the City determines that the terms of such contracts are beneficial to the City.

In connection with its purchase of natural gas and capacity, transmission, transportation, grid management and extraordinary expenses related thereto, the City has established the Energy Cost Adjustment Billing Factor (the “ECABF”) to pass through to Electric System customers increased costs related to fuel.

See the caption “THE ELECTRIC SYSTEM—Electric Rates—Energy Cost Adjustment Billing Factor.” Reclaimed water is currently delivered to the MGS pursuant to a recycled water agreement with the Central Basin Municipal Water District (the “CBMWD Agreement”) which was executed on July 15, 2002.

The CBMWD Agreement has a term of 30 years and can be automatically extended by the City for an additional 10-year term. Recycled water is delivered to the MGS through an 18-inch diameter, 1.8-mile long pipeline connection to the Central Basin Municipal Water District system. The water is supplied for cooling tower make-up, boiler make-up, combustion turbine evaporative coolers and combustion turbine water wash.

Permits, Licenses and Approvals. The operation of the MGS is subject to a variety of federal, state and local laws and regulations. Certain permits and approvals were transferred to the City as part of the assets purchased upon the acquisition of the MGS Assets by the City under the Purchase and Sale Agreement. Other permits and governmental approvals relating to the operation of MGS were obtained by the City following the acquisition of the MGS Assets. For the permits and government approvals that the City has not yet obtained, the City has initiated the application processes and expects to be able to obtain all such permits and governmental approvals in compliance with all applicable federal, state and local regulations.

SCPPA Palo Verde Nuclear Generating Station Interest.

General. PVNGS is located approximately 50 miles west of Phoenix, Arizona. PVNGS consists of three nuclear electric generating units (numbered 1, 2 and 3), with a net maximum capacity 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’ combined design capacity is 4,003 MWs and its combined dependable capacity is 3,937 MWs. Each PVNGS generating unit has been operating under 40-year FullPower Operating Licenses granted by the Nuclear Regulatory Commission (the “NRC”). In April 2011, the NRC approved PVNGS’ license renewal application, allowing the three units to extend operation for an additional 20 years until 2045, 2046 and 2047, respectively. The co-owners of PVNGS approved such extensions. Co-owners of PVNGS include Arizona Public Service Company (“APS”), the Salt River Project Agricultural Improvement and Power District, a political subdivision of the state of Arizona, and the Salt River Valley Water Users’ Association, a corporation (together, the “Salt River Project”), Southern California Edison (“Edison”), El Paso Electric Company, Public Service Company of New Mexico, SCPPA and the City of Los Angeles. APS is the operating agent for PVNGS. SCPPA has informed the City that all other permits, licenses and approvals necessary to operate PVNGS have been secured.

SCPPA is a joint powers agency in which the City participates. SCPPA has a 5.91% ownership interest in the PVNGS. The City has entered into the PVNGS Contract with SCPPA which provides the City with a 4.90% generation entitlement interest in SCPPA’s ownership share in PVNGS (totaling approximately 11 MWs of dependable capacity). Under the PVNGS Contract, the City is obligated to pay 4.90% of SCPPA’s costs associated with PVNGS, including operation and maintenance costs and debt service on SCPPA bonds issued for the project. The City’s payment obligations under the PVNGS Contract are on a “take-or-pay” Resolution No. 2022-10

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basis, pursuant to which the City is required to make the payments whether or not the output of PVNGS is interrupted, suspended or terminated. The City’s payment obligations under the PVNGS Contract are required to be treated as Operation and Maintenance Expenses under the Indenture and any future electric revenue bond indenture or contract. The PVNGS Contract provides that under certain circumstances, the City’s entitlement share to the output of PVNGS and its related payment obligations (including its debt service payment obligation) can be increased to compensate for defaults by other SCPPA participants in their respective contracts with SCPPA in connection with PVNGS. As of June 30, 2021, SCPPA had no bonds outstanding for PVNGS.

In Fiscal Year 2021, PVNGS provided 90,951 MWhs of energy to the City. The City’s share of PVNGS costs under the PVNGS Contract for Fiscal Year June 30, 2021 was $3,290,405. The City expects that PVNGS will provide approximately 90,272 MWhs of energy to the City in Fiscal Year 2022, or an estimated 7% of the total needed to satisfy the City’s load requirements.

Nuclear Regulatory Commission Initiatives. 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. For instance, as a result of the March 2011 earthquake and tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Plant in Japan, various industry organizations developed action plans for American nuclear power plants and the NRC undertook an 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 nuclear reactors located in the United States based on the task force evaluations. The NRC issued 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. On January 4, 2013, the NRC issued guidance to enable U.S. nuclear power plant operators to perform seismic and flooding hazard assessments, which was undertaken at PVNGS in September 2014.

The NRC has required PVNGS to increase the redundancy in its power supply to emergency cooling systems, reinforce its spent fuel pool, accelerate the transfer of spent fuel from the pool to the dry cask storage, and add pipelines and associated equipment necessary for supplying additional cooling water to the reactors.

In response to such requirements, PVNGS has purchased additional diesel generators, pumps and fire trucks and has accelerated the movement of its spent fuel casks to the storage facility. In addition to these actions, PVNGS has allotted approximately $122 million (of which the City is responsible for approximately $350,000) for initiatives developed in response to the failure at the Fukushima Daiichi Nuclear Power Plant, including, among other things, fuel building modifications, an emergency equipment storage facility, temporary power connections, seismic and flood hazards validation and corresponding mitigating strategies.

Additional NRC-mandated requirements are anticipated, but the costs associated with these future projects are unknown at this time.

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 shutdown of one or more generating units, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. The increased costs resulting from penalties, a heightened level of scrutiny and implementation of plans to achieve compliance with NRC requirements may adversely affect the Electric System’s financial condition, results of operations and cash flows.

Decommissioning Costs. 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. Based Resolution No. 2022-10

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on the most recent estimate of decommissioning costs, which uses the extended license expiration date of 2047 and is the most recent estimate available, and assumed future investment earnings, the City estimates that its share of the amount required for decommissioning PVNGS relating to the City’s interest in PVNGS through SCPPA is fully funded. SCPPA’s share is $172 million, of which the City’s portion is $8.4 million. As of June 30, 2021, SCPPA’s available decommissioning funds totaled $186.4 million.

Nuclear Waste Storage and Disposal. Generally, federal and state efforts to provide adequate interim and long-term storage facilities for low-level and high-level nuclear waste have proven unsuccessful to date.

Although federal and state efforts continue with respect to such storage and disposal facilities, the City is not able to predict the schedule for the permanent disposal of radioactive wastes generated at PVNGS. APS, which currently stores PVNGS spent nuclear fuel in on-site pools near the units, has advised the City (through SCPPA) that until a permanent repository for high-level nuclear waste developed by the federal government becomes available, additional on-site spent fuel storage is required by using dry casks similar to those currently used at other nuclear plants. Since the spent fuel pools ran out of storage capacity, an independent spent fuel storage installation was built to provide additional spent fuel storage at the site while awaiting permanent disposal at a federally developed facility. The installation uses dry cask storage and was designed to accept all spent fuel generated by PVNGS during its lifetime. As of June 30, 2021, over 152 casks, each containing 24 spent fuel assemblies, have been stored. If required, the on-site storage facility can be expanded from its current size to accommodate additional waste. APS estimates that the storage facility has sufficient storage capacity to store all low-level radioactive waste produced at PVNGS until the end of operation of PVNGS.

Since the event at the Fukushima Daiichi nuclear power plant (described above under the subcaption “— Nuclear Regulatory Commission Initiatives,” PVNGS embarked on a program to accelerate the transfer of spent fuel from the spent fuel pools to the dry cask storage facility, thus reducing the heat load inside the spent fuel pools. Storage costs are partially paid using funds received by APS pursuant to a settlement agreement with the United States government relating to nuclear waste disposal fees.

APS ships all of its low-level radioactive waste to available disposal sites in Utah and South Carolina.

In August 1995, a storage facility for low-level radioactive materials was opened at PVNGS to allow temporary on-site storage in case the disposal sites are not available. APS estimates that the storage facility has sufficient storage capacity to store all low-level radioactive waste produced at PVNGS until the end of operations. This on-site storage facility remains fully available.

Hoover Uprating Project.

General. The Hoover Uprating Project consists principally of the uprating of the capacity of 17 generating units at the hydroelectric power plant (the “Hoover Plant”) of the Hoover Dam, located approximately 25 miles from Las Vegas, Nevada on the Colorado River. Modern insulation technology made it possible to “uprate” the nameplate capacity of the existing generators. The United States Bureau of Reclamation (the “Bureau of Reclamation”) owns and operates the Hoover Dam facility and Western markets the power from the facility. The Hoover Plant consists of 17 generating units and two service generating units with a total installed capacity of approximately 2,074 MWs.

The City has entered into a Contract for Electric Service (the “CES”) with Western in connection with power from the hydroelectric power plant of the Hoover Dam. Pursuant to the CES with Western, the City made an upfront payment for its share of the construction cost of the Hoover Uprating Project, and received an entitlement to approximately 22 MWs of capacity (calculated based on 1.1% of 1,951 MWs of total contingent capacity) and 28,000 MWhs of associated energy annually from the Hoover Uprating Project. As a result of the enactment of H.R. 470, “Hoover Power Allocation Act of 2011,” the City has been allocated 22 MWs of capacity and 26,600 MWhs of associated energy per year through September 2067. While the City has advanced its share of the construction funds required by the CES, the City remains liable for its share of the operating costs of the Hoover Plant. The City’s payment obligations under the CES constitute Operation and Maintenance Expenses of the Electric System.

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Drought Conditions. Because of prolonged drought conditions that have resulted in record low Colorado River water levels, the City’s capacity entitlement at the Hoover Plant has been reduced from time to time. Recent drought conditions have resulted in lower water levels and are expected to result in a material adverse effect on the Hoover Plant’s capacity entitlement in the near future. According to the Bureau of Reclamation forecasts, the lowest capacity level is expected to occur in February 2023, due to low water levels, the implementation of a drought contingency plan, procedures relating to the operation of Lake Mead, and scheduled maintenance activities. The minimum Hoover Plant capacity in February 2023 is expected to be 910 MWs with a potential maximum capacity of 1,315 MWs for the same month.

Environmental Considerations. The lower Colorado River has been included in a critical Habitat Designated Area. This required the Bureau of Reclamation to prepare and file with the United States Fish and Wildlife Service a Biological Assessment on the effect of its operations of the lower Colorado River on endangered species therein. After the Biological Assessment was filed, the United States Fish and Wildlife Service issued a Biological and Conference Opinion regarding the Bureau of Reclamation’s operations and outlined remedial actions to be taken to correct adverse effects to endangered species. Such remedial actions could affect the operation of the Hoover Plant, which would in turn affect Hoover Plant customers, including the City. The City believes that any impact on future operations will be minor; however, there is a possibility that major remediation actions could have a material impact on the Hoover Plant customers’ available capacity from the Hoover Plant. The City’s entitlement with respect to the Hoover Plant accounts for less than 2% of the Electric System’s portfolio, and any impact on the Electric System’s operations is not expected to be significant. See the table entitled “Resources Used to Satisfy City Load Requirements” under the subcaption “—General” above.

Reserve Generating Facilities.

H. Gonzales Generating Station. The City owns the H. Gonzales Generating Station, which is located at Station A and consists of two gas turbine units. Each unit has a net capacity of 5.5 MWs. The two units are used for resource adequacy and bid into the ancillary services market. As of the date of this Official Statement, one of the units is not operational and the City does not currently plan to return the unit to operation. The City bids these units on a daily basis for dispatch by California Independent System Operator Corporation (the “CAISO”) under the Market Redesign and Technology Upgrade (“MRTU”) tariff amendment. Each of the units is restricted to run on natural gas for no more than six hours per day.

Other Committed Resources.

Renewable Power Purchases. As discussed under the caption “—Renewable Energy Resources,” the City has entered into power purchase agreements through SCPPA in connection with four renewable energy projects: (i) the Puente Hills Landfill Gas-to-Energy Project (the “Puente Hills Landfill Project”); (ii) the Astoria II Solar Photovoltaic Facility (“Astoria II”); (iii) the Antelope Demand Side Response 1 Solar Project (“Antelope 1”); and (iv) the Desert Harvest/Maverick Project (the “Desert Harvest/Maverick Solar Project”). These power purchase agreements supplied approximately 16% of the City’s energy requirements in Fiscal Year 2021. Payments under these power purchase agreements constitute Operation and Maintenance Expenses of the Electric System payable prior to debt service on the City’s Electric System Bonds.

Power Purchase Agreements.

Long-Term Power Contracts. Other than the contracts for the Committed Resources which are described herein, the City currently has no other long-term power contracts with a term of one year or longer.

Short-Term Power Contracts. The City expects to provide power for the Electric System’s load requirements which are not met by the Committed Resources or from new long-term power purchase contracts through short-term power purchases. The cost of power under such contracts will vary depending upon contract requirements and the then-current market price for energy, which is driven by a variety of factors, such as the availability of generating resources in the region and weather conditions. The City’s electric rates Resolution No. 2022-10

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include an Energy Cost Adjustment Billing Factor, the ECABF, to pass through to Electric System customers changes in energy costs. See the caption “—Electric Rates—Energy Cost Adjustment Billing Factor.” For Fiscal Year 2021, short-term power contracts accounted for a total of 310,671 MWhs of energy to the Electric System (approximately 26% of all energy which was used to satisfy the load requirements to the Electric System). For Fiscal Year 2022, short-term power contracts are projected to account for a total of 337,401 MWhs of energy to the Electric System (approximately 26.4% of all energy which will be used to satisfy the load requirements of the Electric System). The City also uses short-term power contracts to meet a portion of its renewable energy resource obligations from time to time. See the caption “—Renewable Energy Resources.”
Renewable Energy Resources
In accordance with the California Renewable Energy Resources Act, which was enacted in 2011 as SBX 1-2 (“SBX 1-2”), the City was required to develop and implement a renewable energy resources plan which provides that a specified average of the Electric System’s retail sales must be procured from eligible renewable energy resources. During the first compliance period (January 1, 2011 to December 31, 2013), an average of 20% of the Electric System’s retail sales was required to be procured from eligible renewable energy resources. During the second compliance period (January 1, 2014 to December 31, 2016), the Electric System was obligated to make reasonable progress each year to ensure that it achieved 25% of retail sales from eligible renewable energy resources by December 31, 2016. With the adoption of the regulations by the California State Energy Resources and Conservation Development Commission, commonly known as the California Energy Commission (the “CEC”) to enforce SBX 1-2, during the third compliance period (January 1, 2017 to December 31, 2020), the City was required to procure eligible renewable energy resources to satisfy a total of 27% of the Electric System’s 2017 retail sales, 29% of its 2018 retail sales, 31% of its 2019 retail sales and 33% of its 2020 retail sales. Subsequent State legislation provides for increasing renewable resources requirements toward a goal of achieving 100% of retail sales of electricity in California being supplied by eligible renewable energy and zero-carbon resources by 2045 as described under the caption “— Developments Affecting the Power Supply—Senate Bill 100 – 100 Percent Clean Energy Act of 2018.” In addition to the power purchase agreements for renewable projects which are described below, the City is currently meeting its obligation under SBX 1-2 to acquire energy from renewable sources by carrying over excess renewable power procurement from prior years, by purchasing renewable energy credits and by the use of short-term contracts. See the caption “—Power Supply Resources—Power Purchase Agreements— Short-Term Power Contracts” above and the subcaption “—Renewable Energy Credits” below.

The City’s renewable power resource portfolio, as well as certain potential options for additional renewal power resources in the future, are described below.

Current Renewable Energy Resources.

Puente Hills Landfill Gas-to-Energy Project. The Puente Hills Landfill Project is a 46 MW conventional Rankine Cycle Steam Power Plant that uses landfill gas (“LFG”) as fuel to generate electricity.

LFG is fired in the plant’s boilers, producing superheated steam which drives the turbine/generator to generate electric power. The Puente Hills Landfill Project is located in the eastern area of the County approximately 15 miles from the City. It was constructed by the County Sanitation Districts of Los Angeles County (“LACSD”) and began full commercial operation in January 1987.

On behalf of certain of its members, SCPPA entered into a power purchase with LACSD for 43 MW of generating capacity from the Puente Hills Landfill Project. The City, through SCPPA, is entitled to 10 MW of renewable capacity from the Puente Hills Landfill Project. The power purchase agreement, which expires on December 31, 2030, is a take-and-pay contract under which the City’s obligation to make payments is contingent upon the City’s receipt of electrical energy.

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Astoria II Solar Photovoltaic Facility. Astoria II is a 175 MW solar project that came online in late 2016. Astoria II is located on approximately 840 acres in Kern County north of the City and interconnects with the CAISO system at Edison’s Whirlwind Substation. The City, in conjunction with five other SCPPA members, participates in a power purchase agreement with Recurrent Energy to purchase 75 MW of the output from Astoria II for 20 years. The power purchase agreement entitled the City to 20 MW of capacity from January 2017 to December 2021 and 30 MW for the remaining contract period of January 2022 to December 2036. The power purchase agreement is a take-and-pay contract under which the City’s obligation to make payments is contingent upon the City’s receipt of electrical energy.

Antelope Demand Side Response 1 Solar Project. Antelope 1 is a 50 MW solar project that was developed by Sustainable Power Group (“sPower”) and came online on January 1, 2017. Antelope 1 is located in the City of Lancaster in the northern area of the County. The City, through SCPPA, has an agreement with Antelope DSR 1 LLC (a subsidiary of sPower) that entitles the City to 50% of the capacity (25 MW nameplate) and output of the project through December 31, 2036. The agreement is a take-and-pay contract under which the City’s obligation to make payments is contingent upon the City’s receipt of electrical energy.

In addition, the City and the City of Riverside (the other purchaser of the energy produced by Antelope 1) negotiated an energy storage option in the Antelope 1 PPA which provides for the potential design, building and operation of an energy storage facility, when economically feasible.

Desert Harvest/Maverick Solar Project. The Desert Harvest/Maverick Solar Project is a solar project with a combined capacity of 650 MW that was developed by Desert Harvest II, LLC (“Desert Harvest”). The project is located in Desert Center, an unincorporated area of Riverside County approximately 175 miles east of the City. The City, through SCPPA, has an agreement with Desert Harvest that entitles the City to 12 MW of output from the Desert Harvest/Maverick Solar Project. The City Council approved the agreement with Desert Harvest and the term of the agreement continues through 2045. The agreement is a take-and-pay contract under which the City’s obligation to make payments is contingent upon the City’s receipt of electrical energy.

Renewable Energy Credits. From time to time, the City has purchased renewable energy credits as a means of satisfying its renewable energy resource procurement obligations under SBX 1-2. The City previously made purchases covering the third regulatory compliance period. In Fiscal Year 2021, the City purchased energy credits for the compliance period ending in calendar year 2024.

Potential Renewable Energy Resources. In September 2008, the City purchased approximately 30,000 acres of land in Tehachapi, California (referred to as the Jaw Bone Area), for approximately $42 million. A portion of such land adjoins two established wind-powered electric generating facilities, one of which is owned and operated by the Department of Water and Power of the City of Los Angeles (“LADWP”) and the other by NextEra (FPL). In February 2010, the City sold approximately 13,000 acres of this land to NextEra (FPL) for approximately $40 million and maintained certain transmission rights and easements on the land. The City currently continues to own and maintain two remaining sections called the East and West lands in the Jaw Bone Area. These two areas are on the east and west of the property sold to NextEra (FPL). These two areas comprise about 18,000 acres. The City continues to explore methods to monetize this land with or without outside developers and/or investors. The City believes the asset potential in such land is significant enough to warrant continued ownership for the foreseeable future, and the City is not at this time soliciting any offers to sell or lease such land. While the City does not anticipate using its own funds to develop renewable energy resources on the Jaw Bone Area land owned by the City, the City does anticipate that some renewable energy resources will be developed in the future to enable the City to recover some or all of its investment in the Tehachapi property and the potential for providing power from renewable resources for the Electric System’s renewable power resource portfolio.

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Renewable Pass-Through Charge. The City has implemented a Renewable Energy Cost Adjustment Factor (the “RECAF”), which is added to its Electric System customer bills. The RECAF is intended to recover the costs of renewable energy resources in excess of non-renewable market power. See the caption “—Electric Rates—Renewable Energy Cost Adjustment Factor.” Integrated Resource Plan
In order to provide a long-term strategy to meet the electric service needs of its customers and comply with State and federal energy policies, including the policies which are discussed under the caption “— Developments Affecting the Power Supply,” the City developed an Integrated Resource Plan (“IRP”) dated November 20, 2018. The IRP is a road map which charts a resource acquisition strategy favoring the procurement of more renewable energy resources and fewer carbon-emitting resources. Resource investment decisions were evaluated using an integrated approach to ensure reliability and environmental stewardship, and to ensure that mandated renewable resource requirements are achieved at the lowest possible cost.

Currently, for regulatory compliance purposes, renewable energy sources comprise approximately 33% of the City’s energy supply (including biofuel and renewable energy credits). The IRP establishes a goal of increasing the Electric System’s renewable energy supply mix to 56% (equivalent to a 62% renewable portfolio standard) by 2030 and decreasing the Electric System’s reliance on natural gas to 35% by 2030. In order to meet these goals, the City will need to increase its acquisition of renewable energy by an additional 7% for the upcoming compliance period ending in 2024. In order to make use of such supplies, the IRP contemplates that the City will increase its energy storage capability by approximately 1 MW per year in each of calendar years 2023 through 2027. The City expects that energy storage technology will improve over time, reducing energy storage costs.

While the IRP does not assume that electricity supplied by the natural gas-fired MGS will be part of the City’s energy portfolio after 2028 (which was the original term of the Former PPTA), the IRP does contemplate that the City will need an amount of base load generation within the Electric System service area after 2028 which is equivalent to that which is currently provided by the MGS. The City will embark on an updated IRP process beginning in 2022 that will consider generation planning after 2028, which will include generation provided by the MGS.

The IRP has been approved by the City Council and filed with the CEC. The projected operating results shown in this Official Statement reflect in part the goals that are set forth in the IRP. However, there can be no assurance that such goals will be achieved as described in the IRP or that the goals which are set forth in the current IRP will not be changed in the future. The City is required to update the IRP every five years. See the caption “—Developments Affecting the Power Supply—Senate Bill 350 – Clean Energy and Pollution Reduction Act of 2015.”
Transmission, Interconnections and Distribution Facilities The Electric System is interconnected with the Edison system at the Laguna Bell substation. The City owns the facilities within the City limits for the interconnection of the Electric System with the Edison system and the distribution of electric power. The distribution facilities include approximately 30 miles of 66 kiloVolt (“kV”) power lines (of which approximately 5% are underground), and approximately 125 miles of 7 kV power lines (of which approximately 15% are underground). The Electric System has eight active primary substations, three of which are dedicated customer substations and five are regular distribution substations.

See the caption “THE ELECTRIC SYSTEM—Capital Requirements” for a description of anticipated capital improvements to the Electric System in the next five years.

The City relies on the California transmission system controlled by the CAISO to provide for transmission of energy imported into the City and pays the associated CAISO charges. In 2007, the City sold virtually all of its major transmission facilities. When the City sold its major transmission assets, the City Resolution No. 2022-10

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retained certain transmission entitlements associated with existing transmission service contracts, which were subsequently placed under the CAISO’s operational control under a transmission control agreement. The City, as a participating transmission owner of the transmission entitlements under the CAISO’s operational control, receives revenues associated with such existing transmission service contracts with Edison and LADWP subject to the related transmission service contracts.

Developments Affecting the Power Supply
The City relied on short-term (less than one year) power purchase contracts to provide approximately 25% of the energy delivered by the Electric System in Fiscal Year 2021. The City anticipates relying on new short-term power purchase contracts to provide for current load and any growth in its customer load which is not met by Committed Resources.

A number of actions have been taken by regulatory agencies which affect the amount of power that the City must have available in order to maintain resource adequacy and the nature of the electric resources which the City must include in its resource base. Certain elements of these actions are described below.

Resource Adequacy. In 2006, the CAISO filed with the Federal Energy Regulatory Commission (“FERC”) its MRTU tariff amendment to implement a comprehensive overhaul of the electricity markets administered by the CAISO. The programs under the MRTU initiative were designed to implement market improvements to assure grid reliability and more efficient and cost-effective use of resources and to create technology upgrades that would strengthen the entire CAISO computer system. The California energy market under the MRTU includes the following features, among others, which were not part of CAISO’s previous real-time only market tariff:
 An integrated forward market for energy, ancillary services and congestion management that operates on a day-ahead basis;
 Congestion management which represents all network transmission constraints;  Congestion Revenue Rights to allow market participants to manage their costs of transmission congestion;
 Local energy prices by price nodes (approximately 3,000 nodes in total), also known as locational marginal pricing; and
 New market rules and penalties to prevent gaming and illegal manipulation of the market as well as modifications to certain existing market rules.

The MRTU became operational on April 1, 2009 and the initial MRTU tariff filed with FERC went into effect at that time. Power is scheduled on a nodal basis, rather than the previous zonal system.

Furthermore, the MRTU incorporates the California Public Utilities Commission’s (“CPUC”) resource adequacy requirements to ensure that there are adequate energy resources in critical areas. The MRTU requires that all scheduling coordinators for all load-serving entities (“LSEs”), which include the City, meet standards concerning forward capacity and energy procurements to meet their load requirements.

In September 2005, the Governor signed into law Assembly Bill 380 (“AB 380”), which requires publicly-owned utilities (“POUs”) to procure adequate resources to meet their peak demands and reserves. In October 2005, the CPUC issued a decision requiring that LSEs under its jurisdiction acquire capacity which is sufficient to serve their forecast retail customer load plus a 15-17% reserve margin. The MRTU tariff incorporates the CPUC’s resource adequacy requirements. The MRTU tariff imposes the CPUC’s resource adequacy requirements on LSEs that are not CPUC jurisdictional entities, such as the City.

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The City has historically satisfied this reserve margin requirement through its power supply resources, and the City believes that it will continue to have sufficient power resources to satisfy the system capacity requirements as required by the MRTU and AB 380.

Senate Bill 350 – Clean Energy and Pollution Reduction Act of 2015. California Senate Bill 350 (“SB 350”), signed into law in 2015, extends and increased the mandate of the State’s renewable portfolio standard (“RPS”) to a 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 by interim targets of (i) 40% of retail sales from eligible renewable energy resources by December 31, 2024; (ii) 45% of retail sales from eligible renewable energy resources by December 31, 2027; and (iii) 50% of retail sales from eligible renewable energy resources by December 31, 2030. SB 350 also provides for the doubling of energy efficiency savings by January 1, 2030. In addition, large municipal electric systems such as the City were required to adopt an IRP on or before January 1, 2019, and to update the plan at least once every five years.

See the caption “—Integrated Resource Plan” for a description of the City’s IRP.

Senate Bill 100 – 100 Percent Clean Energy Act of 2018. California Senate Bill 100 (“SB 100”), signed into law in September 2018, accelerates the State’s RPS target as established by SB 350 from 50% by 2030 to 60% by 2030 and sets a goal of 100% “clean energy” by the year 2045. SB 100 requires retail electric sellers and POUs to procure a minimum quantity of electricity products from eligible renewable energy resources so that the total kWhs of those products sold to retail end-use customers achieve (i) 44% of retail sales by December 31, 2024; (ii) 52% of retail sales by December 31, 2027; and (iii) 60% of retail sales by December 1, 2030.

SB 100 additionally establishes that it is the policy of the State that eligible renewable energy resources and zero-carbon resources supply 100% of retail sales of electricity to California end-use customers by December 31, 2045. Along with SB 100, Governor Brown signed Executive Order B-55-18 that directs the State to achieve carbon neutrality by 2045 and maintain net negative greenhouse gas (“GHG”) emissions thereafter. The goal of carbon neutrality by 2045 is in addition to existing statewide targets of reducing GHG emissions. By expanding the State’s carbon reduction goal, the State will also look to reduce carbon through sequestration in forests, soils and other natural landscapes.

In furtherance of these goals, California Senate Bill 423, signed into law in September 2021, requires the CEC, in consultation with the CAISO and the California Air Resources Board (“CARB”), to submit to the State Legislature by December 31, 2023, an assessment of firm zero-carbon resources available to support a clean, reliable and resilient electrical grid in California to achieve the State policy established by SB 100 and to ensure that a transition to a zero-carbon electric system for the State does not cause or contribute to GHG emissions increases elsewhere in the western grid.

In December 2020, the CEC adopted regulations to update its RPS enforcement procedures for POUs, including to update regulations amended by both SB 350 and SB 100, among other enacted bills. This includes implementing a provision relating to the long-term procurement of renewable resources which requires, beginning January 1, 2021, that at least 65% of renewable procurement must be for a duration of 10 years or more. The regulations implement the new RPS procurement requirements for the compliance periods between 2021 and 2030, establish soft procurement targets for the intervening years of the compliance periods to demonstrate reasonable progress in meeting the RPS procurement target for the compliance periods, and establish three-year compliance periods beginning after 2030. The regulations also define requirements for 10- year procurement contracts for purposes of satisfying the long-term procurement requirement.

Assembly Bill 32 – Global Warming Solutions Act of 2006. California Assembly Bill 32 (“AB 32”), which the Governor signed into law in 2006, requires that utilities reduce their GHG emissions to 1990 levels by the year 2020. In addition, Senate Bill 32 (“SB 32”), which the Governor signed into law in 2016, requires that statewide GHG emissions are reduced to 40% below 1990 levels by 2030.

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AB 32 tasked CARB with developing regulations for GHG emissions that became effective January 1, 2012. Emission compliance obligations under the cap-and-trade regulation (the “C&T Program”) began on January 1, 2013. The C&T Program was implemented in phases, with the first phase lasting from January 1, 2013 to December 31, 2014. This phase placed an emission cap on electricity generators, importers and large industrial sources emitting more than 25,000 metric tons of carbon dioxide-equivalent GHGs per year. In 2015, the C&T Program expanded to cover emissions from transportation fuels, natural gas, propane and other fossil fuels.

The C&T Program requires electric utilities to have GHG allowances on an annual basis to offset GHG emissions associated with generating electricity. CARB provides a free allocation of GHG allowances to each electric utility to mitigate retail rate impacts. Thereafter, the utilities are required to purchase allowances through the auction or on the secondary market to offset their associated GHG emissions. Each allowance can be used for compliance purposes in the current year or carried over for future compliance use.

Any allowance not used for current year compliance or carried over for future compliance use must be sold into the quarterly allowance auctions administered by CARB. Proceeds from the auctions must be used for the intended purposes specified in AB 32 that include but are not limited to procurement of renewable resources, energy efficiency and conservation programs and measures that provide clear GHG reduction benefits.

Assembly Bill 398 – GHG Cap-and-Trade Program Extension. Assembly Bill 398 (“AB 398”), which the Governor signed into law in 2017, extended the GHG C&T Program to December 31, 2030. This bill was also a companion bill to Assembly Bill 617 (“AB 617”; see the subcaption “—Assembly Bill 617 – Air-Quality Monitoring”). The City’s free allocation of GHG allowances is expected to be sufficient to meet the City’s direct GHG compliance obligations through 2030.

Under the C&T Program, the City is required to consign 100% of its allowances and then purchase allowances to meet its compliance obligation. Other components of AB 398 that require clarification are the banking provisions and the specific GHG revenue spending requirement for revenues generated from the sale of excess allowances. The Electric System will continue to monitor the outcome and impacts of the upcoming regulations on its service territory and ratepayers.

Assembly Bill 617 – Air Quality Monitoring. AB 617, which the Governor signed into law in 2017, was part of a legislative bill package with AB 398, which authorized the extension of the State’s C&T Program (see the subcaption “—Assembly Bill 398 – GHG Cap-and-Trade Program Extension”). AB 617 addresses the disproportionate impacts of air pollution in environmental justice communities. Both CARB and local air districts are required to take specific actions to reduce air pollution and toxic air contaminants emitted from commercial and industrial sources, including from electricity-generating facilities. The bill required CARB to prepare a statewide monitoring plan regarding technologies and reasons for monitoring air quality and, based on that plan, to identify the highest priority locations for the deployment of community level air monitoring systems. Local air districts were required to deploy the air monitoring systems in the specified communities by July 1, 2019. Additional locations for the deployment of the air monitoring systems are identified annually by CARB. CARB is also required to provide grants to community-based organizations for technical assistance and to support community participation in the programs. In turn, this effort requires local air districts to adopt a community emissions reduction program. The City is not currently located in a community identified for emissions reduction.

Additionally, AB 617 requires CARB to develop uniform reporting standards for air pollutants and toxic air contaminants for specific uses, including electricity-generating facilities. Air districts are to adopt an expedited schedule for implementing best available retrofit control technologies for the uses, while CARB will identify these technologies.

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Lastly, AB 617 imposes additional reporting requirements for qualifying facilities. For the City, the local air district is the South Coast Air Quality Management District (“SCAQMD”). CARB and SCAQMD have held and continue to hold community meetings to implement the required elements of AB 617 within the Los Angeles area. Although the City is not yet subject to reporting under AB 617, the City continues to monitor developments under AB 617.

Assembly Bill 1110 - Greenhouse Gas Emissions Intensity Reporting. Assembly Bill 1110 (“AB 1110”), which the Governor signed into law in 2016, requires GHG emissions intensity data and unbundled renewable energy credits to be included as part of retail suppliers’ power source disclosure reports and power content label (“PCL”) to their customers. GHG emissions intensity factors will need to be provided for all the retail electricity products. The inclusion of this new information requirement on the PCL began in 2021 for calendar year 2020 data. In addition to being required to post the PCL on the City’s website, AB 1110 also requires that PCL disclosures must be mailed to customers unless customers have opted for electronic notifications. In accordance with this requirement, the City posts disclosures of the PCL on its website.

Assembly Bill 2514 – Energy Storage. Assembly Bill 2514 (“AB 2514”), which the Governor signed into law on September 29, 2010, directs municipal electric utilities to consider setting targets for energy storage procurement but emphasizes that any such targets must be consistent with technological viability and cost effectiveness. The law’s main directives and their respective deadlines are to adopt an energy storage system procurement target by October 1, 2014, if determined to be appropriate, to be achieved by each utility by December 31, 2016, and a second target to be achieved by December 31, 2020. The City submitted its first adopted target compliance report to the CEC by January 1, 2017 and submitted its second adopted target compliance report to the CEC by January 1, 2021.

Energy storage (“ES”) has been advocated as an effective means for addressing the growing operational problems of integrating intermittent renewable resources, as well as contributing to other applications on and off the grid. In general, ES is a set of technologies which are capable of storing previously generated electric energy and releasing that energy at a later time. Currently, the commercially available ES technologies (or soon to be available technologies) consist of pumped hydroelectric generation, compressed air systems, batteries and thermal ES systems. The City is currently reviewing the feasibility of ES projects in the City.

Senate Bill 380 – Moratorium on Natural Gas Storage – Aliso Canyon. On October 23, 2015, a significant gas leak was discovered at the Aliso Canyon natural gas storage facility, which makes up 63% of total storage capacity of Southern California Gas Company (“SoCalGas”) and serves 17 gas fired power generation units. On May 10, 2016, the Governor signed Senate Bill 380 (“SB 380”) into law, placing a moratorium on Aliso Canyon’s natural gas storage usage until rigorous tests were performed and completed by the California Geologic Energy Management Division (“CalGEM”) as to which wells could continue to be in operation. This moratorium caused great concern regarding the reliability of natural gas supplies in the then upcoming summer and winter months. An action plan study area was initiated to review the summer and winter assessment that was conducted as a joint effort between the CPUC, CEC, CAISO and LADWP. It was considered highly plausible that the market for natural gas could be affected by curtailed gas deliveries under certain adverse low-flow gas scenarios.

Beginning June 1, 2016, SoCalGas implemented new Operational Flow Order (“OFO”) tariffs due to limitations surrounding Aliso Canyon storage injections and withdrawals. These tariff changes were put in place to reduce the probability of natural gas curtailments. These tighter OFO tariff restrictions were scheduled to conclude upon the earlier of the return of Aliso Canyon to at least 450 million cubic feet per day (“MMcfd”) of injection capacity and 1,395 MMcfd of withdrawal capacity, or March 31, 2017.

On July 19, 2017, CalGEM issued a press release to the effect that, in concurrence with the CPUC, Aliso Canyon was safe to resume injections up to 28% of the facility’s maximum capacity. On that same day, the CEC issued a different press release with a recommendation urging closure of Aliso Canyon in the longResolution No. 2022-10

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term. On July 31, 2017, SoCalGas resumed injections. Withdrawals from Aliso Canyon could then be made during emergency conditions to avoid electric load shed and/or gas curtailments to customers.

In August 2019, the CPUC approved a revision of the Aliso Canyon withdrawal policy, removing the designation “facility of last resort,” allowing SoCalGas more flexibility to withdraw from the storage field to maintain pipeline integrity. Since this change in policy, SoCalGas has been able to withdraw from the storage field more freely, thus reducing the volatility in both the volume of locally available natural gas and local natural gas pricing.

The Electric System has fulfilled its system reliability since the gas leak was discovered at the Aliso Canyon facility. The City will continue to monitor developments in this area, but does not expect curtailment of permitted withdrawals from the facility to have a significant effect on the Electric System’s ability to meet customer demand.

Wildfire Mitigation Considerations
The City believes that the risk of damage to the Electric System as a result of wildfires is very low.

The Electric System does not have any overhead powerlines located within, or near the High Fire-Threat District or Fire Threat Zones identified by the California State Department of Forestry and Fire Protection (“CalFire”) or CPUC. Furthermore, the City’s service area is not within or near any wildland-urban interface zones and more than ten miles from the nearest wild-land urban interface area.

Senate Bill 1028 (“SB 1028”), which was signed into law by the Governor in 2016, requires municipal electric utilities to construct, maintain and operate their electrical lines and equipment in a manner that will minimize the risk of catastrophic wildfire posed by those electrical lines and equipment. Senate Bill 901 (“SB 901”), which was signed into law by the Governor in 2018, addresses the response to, mitigation of and prevention of wildfires. SB 901 requires municipal electric utilities to prepare before January 1, 2020 and annually thereafter a wildfire mitigation plan. SB 901 further requires utilities to present their wildfire mitigation plan in an appropriately noticed public meeting, to accept comments on the plan from the public, other local and state agencies and interested parties and to verify that the plan complies with all applicable rules, regulations, and standards, as appropriate. SB 901 also requires the utilities 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 on the Internet and to be presented at a public meeting of the utilities’ governing boards.

While governing boards must independently make a wildfire determination based on all the relevant information, the CPUC’s Fire Threat Map is an important piece of analysis in this process. The Fire Threat Map, which was adopted by the CPUC on January 19, 2018, does not include the Electric System’s service area within a zone of elevated wildfire risk.

SB 1028 and SB 901 do not address existing legal doctrine relating to utilities’ liability for wildfires; however, any future legislation that addresses the State’s inverse condemnation and “strict liability” issues for utilities in the context of wildfires in particular could be significant for the electric utility industry, including the City.

At the request of Vernon Public Utilities, the Vernon Fire Department performed an assessment of the Electric System service territory’s risk of wildfire caused by electrical operations and equipment. The assessment considered the City’s historical fire data, geographical location, location conditions and information from the United States Forest Service’s Fire Modeling Institute, and CalFire’s Office of the State Fire Marshal. A determination was made by the Vernon Fire Department that the City’s electrical equipment and operations do not pose a risk of igniting a fire that could cause any significant or catastrophic wildfire condition. Based on this assessment, the City Council made a wildfire mitigation plan determination at the May 18, 2021 City Council meeting, determining that the City is not at risk of catastrophic wildfire resulting Resolution No. 2022-10

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from the Electric System’s electrical lines and equipment, is not near a wildland-urban interface area and is not listed as a “community at risk” by CalFire, and therefore that the Electric System does not pose a risk of igniting a fire that could cause a wildfire.

Seismic Activity and Other Natural Disasters
The occurrence of any natural disaster in the City, including, without limitation, earthquake, landslide, land subsidence, high winds, drought, fire or flood, could have an adverse material impact on the economy within the City, the Electric System and the revenues available for the payment of the 2022 Bonds. Portions of the Electric System may be at risk of damage or destruction from seismic activity. The City is not required to maintain earthquake insurance on Electric System facilities under the Indenture, and does not currently maintain such insurance. See the caption “GENERAL INFORMATION REGARDING THE CITY AND THE SERVICE AREA—City Insurance.”
The City is located in a seismically active region. Significant faults are located near the City, including the Newport-Inglewood Fault. There is potential for destructive ground shaking during the occurrence of a major seismic event. In addition, land along fault lines may be subject to liquefaction during the occurrence of such an event. In the event of a severe earthquake, there may be significant damage to both property and infrastructure within the City, including the Electric System. The City has an emergency response plan that would be implemented under such circumstances.

Newer Electric System facilities are designed to withstand earthquakes with minimal damage, as earthquake loads are taken into consideration in the design of project structures. The impact of lesser magnitude events is expected by the City to be temporary, localized and reparable. The Electric System has never sustained major damage to its facilities or experienced extended incidences of service interruptions as a result of seismic disturbances. All facilities have been designed and constructed in compliance with the City’s construction standards. The electric utility is a signatory to both APPA and CUEA Mutual Assistance agreements which would enable the City to reach out to local, regional and national utilities for any assistance necessary to restore service in a major event.

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Customers, Retail Energy Sales, Revenues and Demand
The number of customers (based on meters), retail kWh sales and revenues derived from retail sales, by classification of service, and peak demand during each of the last five Fiscal Years are listed below. The City’s customer mix is primarily large and small industrial businesses, with large industrial customers (monthly demand over 500 KW) comprising approximately 5% and small industrial customers (monthly demand of 500 KW or less) comprising approximately 95% of the total revenues from retail sales for Fiscal Year 2021.

CITY OF VERNON ELECTRIC SYSTEM
Customers, Retail Energy Sales, Revenues and Demand
Fiscal Years Ended June 30
2017 2018 2019 2020 2021
Number of Customers:

Residential 74 74 74 74 74
Small Industrial 1,210 1,218 1,223 1,231 1,238
Large Industrial 539 531 524 514 503
Other 93 93 94 93 90
Total Customers(1) 1,916 1,916 1,915 1,912 1,905
Kilowatt Hour Retail Sales (in Millions):

Residential 0.4 0.3 0.3 0.3 0.3
Small Industrial 371.4 379.6 375.9 383.5 397.8
Large Industrial 713.1 687.8 685.6 692.8 742.8
Other 10.3 10.3 11.1 9.5 9.5
Total kWh Retail Sales 1,095.2 1,078.0 1,072.8 1,086.1 1,150.5 Revenues from Retail Sale of Energy ($000’s)
Residential $ 45 $ 36 $ 35 $ 34 $ 36
Small Industrial 59,123 62,112 62,278 62,629 66,724
Large Industrial 93,742 93,675 93,048 91,537 98,707
Other 1,958 2,101 2,174 1,848 1,932
Total Revenues from Retail
Sale of Energy(2) $ 154,869 $ 157,923 $ 157,535 $ 156,048 $ 167,399 Peak Retail Demand (MWs) 190.8 184.1 182.8 191.3 191.0

(1) Some businesses have more than one meter. The City considers each meter to be a customer. (2) Excludes 2.85% AB 1890 public benefit surcharge pursuant to Section 385 of the California Public Utilities Code and RECAF, as well as the previously levied fuel cost adjustment billing factor. See the caption “—Electric Rates—Energy Cost Adjustment Billing Factor.”
Source: City.

Electric Rates
General. The Electric System’s retail rates are established by the City Council and are not subject to regulation, review or approval by the CPUC or any other State or federal agency, although the CEC is authorized to evaluate electric rate policies in furtherance of State regulatory goals and to make recommendations to the Governor, the State Legislature and publicly owned electric utilities. The Electric System provides no free service.

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Current rates are as follows:

Rate Type Rate
Domestic Customers
Customer Charge $3.48 per meter per month
Facilities Charge $0.56 per meter per month
Energy Charge 9.403 cents per kWh
Large Industrial Customers
Customer Charge $813.72 per meter per month
Automated Meter Reading Charge $13.80 per month
Demand Charge $22.13 per kilowatt per meter per month (on- and off-peak) $26.33 per kilowatt per meter per month (mid-peak)
(May, June, October)
$27.04 per kilowatt per meter per month (on- and off-peak) $31.04 per kilowatt per meter per month (mid-peak)
(July-September)
$17.53 per kilowatt per meter per month (on- and off-peak) $21.73 per kilowatt per meter per month (mid-peak)
(November-April)
Energy Charge 17.655 cents per kWh (on- and off-peak)

18.575 cents per kWh (mid-peak)
(October-June)

21.374 cents per kWh (on- and off-peak)

23.499 cents per kWh (mid-peak)
(July-September)
Small Industrial Customers(1)
Customer Charge $813.72 per meter per month
Automated Meter Reading Charge $13.80 per month
Demand Charge $22.12 per kilowatt per meter per month (on- and off-peak) $26.18 per kilowatt per meter per month (mid-peak)
(October-June)
$26.15 per kilowatt per meter per month (on- and off-peak) $30.21 per kilowatt per meter per month (mid-peak)
(July-September)
Energy Charge 18.509 cents per kWh (on- and off-peak)

19.455 cents per kWh (mid-peak)
(October-June)

22.27 cents per kWh (on- and off-peak)

24.408 cents per kWh (mid-peak)
(July-September)
Minimum Charge $246.36 per month
Commercial Customers
Energy Charge 11.97 cents per kWh
Demand Charge $26.33 per meter per month
Minimum Charge $246.36 per month

(1) Demand of less than 500 kW.

Source: City.

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In addition to the above rates, customers pay: (1) a 3% surcharge for payments in lieu of tax and franchise payments; (2) a 2.85% public benefits surcharge under California Assembly Bill 1890 (“AB 1890”); (3) the ECABF (as discussed under the subcaption “—Energy Cost Adjustment Billing Factor”); (4) the RECAF (as discussed under the subcaption “—Renewable Energy Cost Adjustment Billing Factor”); and (5) the UUT, which is described in detail under the caption “SECURITY AND SOURCES OF PAYMENT— Transfers to General Fund.”
Separate rate schedules apply to: (i) street and highway lighting services based upon factors such as the strength of the lighting used, whether the billing is metered and ownership of the lighting equipment; and (ii) electricity used for agricultural or water pumping purposes.

In addition, in 2019, the City adopted increases in Electric System rates averaging approximately

0.8% in Fiscal Year 2020, 1.9% in Fiscal Year 2021, 4% in Fiscal Year 2022 and 4% in Fiscal Year 2023. The projected operating results set forth in this Official Statement assume that such adopted rate increases will be implemented as expected, as well as additional rate increases averaging approximately 2.5% in Fiscal Year 2024 and thereafter, which have not yet been approved by the City Council. See the caption “ELECTRIC SYSTEM FINANCIAL AND RELATED INFORMATION—Projected Operating Results and Debt Service Coverage.”
Energy Cost Adjustment Billing Factor. In response to then-existing volatility in the cost of natural gas, the City in 2006 entered into a gas supply agreement with the Vernon Natural Gas Financing Authority (the “Authority”) for the purchase of a supply of prepaid natural gas to be supplied to the Authority by the gas supplier under an agreement for purchase and sale of natural gas, which Agreement was assigned from the Authority to the City. At that time, the City established a fuel cost adjustment billing factor in connection with the cost of natural gas related to power generation and purchases, which was calculated and payable on a monthly basis based on customer consumption. The fuel cost adjustment billing factor did not address other costs to the City related to the purchase of fuel. Accordingly, in 2019, the City replaced the fuel cost adjustment billing factor with the ECABF. The ECABF is calculated each month based on the City’s costs and added to all retail customer bills for the following month. The ECABF enables the City to recover changes in the amounts that the City pays for energy (other than renewable energy which is recovered through the RECAF described below), natural gas and related capacity, transmission, transportation, grid management and extraordinary expense costs.

Renewable Energy Cost Adjustment Billing Factor. To provide for the payment of additional costs associated with satisfying renewable energy portfolio standards for the Electric System (including the cost of GHG allowances associated with power generation and implementation charges under AB 32 (as discussed under the caption “—Developments Affecting the Power Supply—Assembly Bill 32 – Global Warming Solutions Act of 2006”)), the City has approved the RECAF, which is calculated based on kWh billed and payable on a monthly basis. See the caption “—Renewable Energy Resources—Renewable Pass-Through Charge.” The RECAF went into effect on January 1, 2012 and was added to all retail customer bills based on electrical consumption, although the City did not levy any charges under the RECAF until 2013. The RECAF adds an amount to each retail bill to recover the excess of the cost the City pays for renewable energy (or substitutes therefor satisfying the City’s obligations to provide energy from renewable resources such as renewable energy credits) over the cost of energy from non-renewable resources.

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Average Price. The table below sets forth the average billing price per kWh for the Electric System’s various customer classes for the periods indicated.

CITY OF VERNON ELECTRIC SYSTEM
Average Billing Price
(Cents per Kilowatt Hour)
Fiscal Year Ended June 30
2017 2018 2019 2020 2021
Residential 12.10 11.69 11.60 10.30 10.45
Small Industrial 15.92 16.36 16.57 16.33 16.77
Large Industrial 13.15 13.62 13.57 13.21 13.29
Other 19.07 20.45 19.66 19.45 20.24
Weighted Average 14.14 14.64 14.68 14.37 14.55

Source: City.

Collection Procedures. All electric bills are due and payable on the date of billing and become delinquent 20 days thereafter. Electric bills are consolidated with bills for water service. If payment is not received 20 days after billing, a second notice will be delivered and a $10 fee will be assessed. If such bills remain unpaid on the 35th day after billing, a door hanger will be hand delivered to the service address and a $10 final notice fee will be assessed. All electric services are subject to termination after 45 days (in accordance with applicable law) until all fees, charges, penalties and the entire delinquent balance have been paid. Fees associated with a delinquency include a $26 returned check fee, a late charge equal to 5% of the outstanding balance and a reconnection fee of $214.30.

Uncollectible Accounts. The City considers its write-offs for uncollectible accounts to be low by electric utility industry standards for urban areas. In recent years, the annual write-offs for uncollectible accounts had generally been less than 0.2% until Fiscal Year 2021. The City has attributed the increase in annual write-offs in Fiscal Year 2021 to the impact of the COVID-19 pandemic and the related government actions taken to mitigate the spread of COVID-19. The City has been awarded $1.1 million by the CAPP arrearage program to aid the accounts that have fallen behind during the period of May 4, 2020 through June 15, 2021, which in turn is expected by the City to lower the uncollectible revenue amount as funds are received. As of April 1, 2022, the City has received $670,915.75 of such funding.

CITY OF VERNON ELECTRIC SYSTEM
Uncollectible Accounts
Fiscal Year Ended
June 30
Uncollectible
Revenues
Percent of
Gross Billings
2017 $ 400,251 0.2%
2018 385,404 0.2
2019 287,762 0.2
2020 227,003 0.1
2021 1,769,261 1.0

Source: City.

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Largest Customers
The Electric System’s 20 largest customers (by electricity usage) for Fiscal Year 2021 accounted for approximately 61% of the Electric System’s retail energy sales for such period. No single customer accounted for more than approximately 12% of the Electric System’s retail energy sales during such period.

Customer concentration presents a risk in that if one or more of the Electric System’s largest customers were to default on their payments for retail energy sales, or were to relocate their operations outside of the City or otherwise cease their operations in the City, such failure to pay, relocation of operations or ceasing of operations could have a material impact on the Electric System’s finances. No assurances can be given by the City that any such failure to pay, relocation or cessation of operations will not occur during the term of the 2022 Bonds.

The City believes that the risk that its largest customers will depart the City is low. As shown in the second column of the table below, many of the 20 largest customers of the Electric System have been in the City for decades. In addition, the City has a low vacancy rate of less than 1% (as of the first quarter of 2022, the latest period for which such information is available), and the City believes that other businesses would quickly fill any vacant spaces upon the departure of a large customer. See also the caption “—Electric Rates— Uncollectible Accounts” for historical information with respect to writeoffs of delinquent accounts.

The customers of the Electric System which individually represented more than 1% of Electric System Revenues in Fiscal Year 2021 are described in the below table in order of kWh purchased. [Remainder of page intentionally left blank.]
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CITY OF VERNON ELECTRIC SYSTEM
Largest Customers (Fiscal Year 2021)
Business Name
Years In
Vernon Type of Business
kWhs
Purchased Revenues
Percent of
Revenues

1. Matheson Tri Gas 13 Chemical Processing 182,848,646 $20,616,793 12.32%2. Owens Illinois, Inc. 75 Container Packaging 102,821,506 12,653,307 7.563. Smithfield (Clougherty Packaging) 75 Food Processing 78,251,049 17,022,916 10.16 4. Rehrig Pacific Co. 46 Plastics 31,249,187 4,853,439 2.905. PABCO Paper Products Co. 62 Building Materials 30,488,862 4,765,155 2.856. Overhill Farms Inc. 28 Food 27,080,652 5,314,098 3.177. Crown Poly Inc. 22 Plastics 26,852,106 3,898,919 2.33 8. rPlanet Earth 4 Plastic Recycling 20,852,106 3,972,429 2.379. Command Packaging 24 Plastics 19,151,151 2,809,801 1.6810. Preferred Freezer Services Inc. 18 Cold Storage 17,240,199 2,822,519 1.6911. General Mills Inc. 38 Food Processing 15,848,737 2,571,708 1.5412. US Growers Cold Storage (Lineage) 45 Cold Storage 21,088,523 2,730,048 1.63 13. Baker Commodities 54 Environmental Recycling 13,635,190 2,277,138 1.3614. Golden West Trading 10 Food Processing 12,387,528 2,679,770 1.6015. CLW Foods LLC 8 Food Processing 11,779,710 2,016,010 1.2016. Millennium Products, Inc. 16 Food Processing 11,736,289 2,836,501 1.69 17. J&J Snack Foods Corp. 24 Food Processing 11,358,225 1,826,589 1.0918. Norton Packaging Co. 16 Plastics 10,619,012 1,660,107 0.9919. 7-UP Bottling Co. 24 Food Processing 10,346,503 2,225,634 1.3320. Camino Real Foods Inc. 39 Food Processing 10,181,372 2,015,972 1.20 TOTAL(1) 665,816,553 $101,568,853 60.7%(1) Totals may not add due to rounding. Source: City.

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Capital Requirements
The following table lists the expected annual capital requirements for the Electric System to be paid from amounts in the Light and Power Fund for Fiscal Years 2022 through 2025. Projects to be completed include substation transformer construction, upgrades, replacements and improvements and equipment purchases. The City does not currently expect to finance any such capital requirements from the proceeds of Bonds, other than the remaining proceeds of the 2020A Bonds. See the caption “PLAN OF FINANCE—MGS Acquisition Project.” See also the caption “—Integrated Resource Plan” above. Vernon’s IRP will be used in conjunction with the development of future capital improvements plans for the Electric System.

Fiscal Year Ending
June 30 Capital Requirements
2022 $ 16,527,137
2023 14,237,500
2024 14,088,326
2025 13,876,093
Total $ 58,729,056

Source: City.

Outstanding Electric System Parity Obligations
Following the issuance of the 2022 Bonds and the defeasance of all of the outstanding 2012A Bonds and a portion of the 2012B Bonds, the following obligations payable from Revenues on a parity with the 2022 Bonds will be outstanding.
2008A Bonds. In 2008, the City issued the 2008A Bonds to finance certain Electric System capital projects. The 2008A Bonds were outstanding in the aggregate principal amount of $37,895,000 as of April 2, 2022 and are payable in semiannual installments at an interest rate of 8.590%. The 2008A Bonds mature on July 1, 2038. The obligation of the City to pay the 2008A Bonds is payable from Revenues on parity with the 2022 Bonds.
2012B Bonds. In 2012, the City issued the 2012B Bonds to finance and refinance certain Electric System capital projects. The 2012B Bonds were outstanding in the aggregate principal amount of $35,100,000 (of which $23,595,000 is expected to be refunded by the 2022 Bonds) as of April 2, 2022 and are payable in semiannual installments at interest rates of between 6.250% and 6.500%. The 2012B Bonds mature on August 1, 2026. The obligation of the City to pay the 2012B Bonds is payable from Revenues on parity with the 2022 Bonds.
2015A Bonds. In 2015, the City issued the 2015A Bonds to finance and refinance certain Electric System capital projects. The 2015A Bonds were outstanding in the aggregate principal amount of $111,720,000 as of April 2, 2022 and are payable in semiannual installments at interest rates of between

4.050% and 4.850%. The 2015A Bonds mature on August 1, 2026. The obligation of the City to pay the 2015A Bonds is payable from Revenues on parity with the 2022 Bonds. 2020A Bonds. In 2020, the City issued the 2020A Bonds to finance and refinance certain Electric System capital projects. The 2020A Bonds were outstanding in the aggregate principal amount of $19,305,000 as of April 2, 2022 and are payable in semiannual installments at interest rates of 5.000%. The 2020A Bonds mature on August 1, 2037. The obligation of the City to pay the 2020A Bonds is payable from Revenues on parity with the 2022 Bonds.
2021A Bonds. In 2021, the City issued the 2021A Bonds to finance the acquisition of the MGS. The 2021A Bonds were outstanding in the aggregate principal amount of $173,815,000 as of April 2, 2022 and are Resolution No. 2022-10

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payable in semiannual installments at interest rates of 5.000%. The 2021A Bonds mature on April 1, 2028.

The obligation of the City to pay the 2021A Bonds is payable from Revenues on a parity with the 2022 Bonds.

ELECTRIC SYSTEM FINANCIAL

AND RELATED INFORMATION
Financial Statements
A copy of the audited financial statements of the Electric Fund of the City for the Fiscal Year ended June 30, 2021 (the “Financial Statements”) prepared by the City’s independent auditor, CliftonLarsonAllen LLP, Irvine, California (the “Auditor”), is set forth in Appendix A. The Auditor’s letter dated March 3, 2022 is set forth therein. The Financial Statements should be read in their entirety. The Auditor has not reviewed, audited or performed any procedures with respect to this Official Statement.

The summary operating results for the Fiscal Years ended June 30, 2017 through June 30, 2020 that are contained under the caption “—Summary of Operating Results” are derived from the Financial Statements and audited financial statements for prior Fiscal Years (excluding certain non-cash items and after certain other adjustments), and are qualified in their entirety by reference to such statements, including the notes thereto.

The summary operating results for the Fiscal Year ended June 30, 2021 that are contained under such caption have been derived from unaudited financial statements of the City’s Electric Fund. The City expects that its annual financial report of the Electric Fund containing the audited financial statements of the Electric Fund as of June 30, 2021 will be available in December 2021. The annual financial reports of the City are routinely posted on its website.

The City accounts for moneys received and expenses paid in accordance with generally accepted accounting principles applicable to public entities (“GAAP”). In certain cases, GAAP requires or permits moneys that are collected in one Fiscal Year to be recognized as revenue in a subsequent Fiscal Year and requires or permits expenses that are paid or incurred in one Fiscal Year to be recognized as expenses in a subsequent Fiscal Year. See Note 1 to the Financial Statements that are set forth in Appendix A. Except as otherwise expressly noted herein, all financial information that has been derived from the City’s audited financial statements of the Electric Fund reflects the application of GAAP.

The Electric System of the City is accounted for as within the Vernon Public Utilities Fund, a proprietary fund type (enterprise fund). In governmental accounting, enterprise funds are used to account for operations that are financed and operated in a manner similar to private business enterprises, where the intent is that the costs (expenses, including depreciation) of providing goods or services to the general public on a continuing basis are to be financed or recovered primarily through user charges, or where periodic determination of revenues earned, expenses incurred and/or net income is deemed appropriate for capital maintenance, public policy, management control, accountability or other purposes.

Proprietary funds are accounted for using the “economic resources” measurement focus and the accrual basis of accounting. Under the accrual basis of accounting, revenues are recognized in the period in which they are earned while expenses are recognized in the period in which the liability is incurred.

Proprietary funds distinguish operating revenues and expenses from non-operating items. Operating revenues, such as charges for services, result from exchange transactions associated with the principal activity of the fund. Exchange transactions are those in which each party receives and gives up essentially equal values. Non-operating revenues, such as subsidies and investment earnings, result from non-exchange transactions or ancillary activities. Operating expenses include the cost of sales and services and administrative expenses. All expenses which do not meet this definition (other than depreciation, a non-cash item which is not reflected in this Official Statement) are reported as non-operating expenses.

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Financial Policies
The City has adopted several policies which are designed to provide guidance for the prudent and effective management of City operations, including an investment policy and a debt management policy.

Further information about the City’s investment policy and debt policy are set forth below.

Investment Policy. The City invests its funds in accordance with the City’s investment policy (the “Investment Policy”), which was most recently amended on June 15, 2021. The Investment Policy sets forth the policies and procedures that are applicable to the investment of City funds and designates eligible investments. The Investment Policy also sets forth stated objectives, including the assurance of the safety of invested funds by limiting credit and market risks, the maintenance of sufficient liquidity, compliance with law and the attainment of the best yield or returns on investments. Funds are invested in the following order of priority:
 Safety of Principal;
 Liquidity; and
 Yield.

The City Council has delegated the authority to invest funds of the City to the City Treasurer, who must invest City funds in accordance with the “prudent investor standard” under California Civil Code § 2261 et seq.

The Investment Policy provides a number of permitted investment categories, including: (i) United States Treasury securities and other federal government securities with a maximum maturity of 5 years; (ii) asset-backed securities with a maximum maturity of 5 years; (iii) certificates of deposit with a maximum maturity of 5 years (limited to 30% of the portfolio); (iv) bankers’ acceptances with a maximum maturity of 180 days (limited 40% of the portfolio); (v) repurchase agreement with a maximum maturity of one year; (vi) money market mutual funds (limited to 20% of the portfolio); and (vii) the Local Agency Investment Fund of the State (limited to $75 million).

As of June 30, 2021, the City had total moneys invested in the amount of $113,911,932 in permitted investments under the Investment Policy (excluding cash and capital reserves of the Electric System, which are discussed under the caption “ELECTRIC SYSTEM FINANCIAL INFORMATION—Available Cash”). The City has not specifically allocated any portion of such amounts to the Light and Power Fund.

The City Treasurer is required to provide a quarterly report to the City Administrator and the City Council detailing the City’s investments, dates of maturity, amounts invested, current market value, rate of interest and other such information as may be required by the City Council. For additional information relating to the Investment Policy, see Note 2 to audited financial statements of the Electric Fund set forth in Appendix A.

Debt Management Policy. The City’s debt management policy addresses the matters that are required by California Government Code § 8855(i), including: (i) the purposes for which debt proceeds may be used; (ii) the types of debt that may be issued; (iii) the relationship of the debt to, and integration with, the City’s capital improvement program or budget; (iv) policy goals related to the City’s planning goals and objectives; and (v) the internal control procedures which ensure that the proceeds of each debt issuance are directed to their intended use.

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Available Cash
As of April 1, 2022, the Electric System had approximately $171,058,242 in available cash reserves, including approximately $55,523,139 in reserves that are currently allocated to future capital projects but can be reallocated to other purposes in the City’s discretion amounts and amounts on deposit in the Expense Stabilization Fund. See the caption “SECURITY AND SOURCES OF PAYMENT—Expense Stabilization Fund.” This amount is equivalent to approximately 364 days of Operation and Maintenance Expenses.

Summary of Operating Results
A summary of historical revenue, expenses, and debt service coverage for the City’s Electric System for the last five Fiscal Years is shown in the following table. The information in this summary was prepared by the City from information derived from audited annual financial statements for such Fiscal Years. The annual financial reports of the City are routinely posted on its website.

The summary below presents the calculation of Net Revenues and Debt Service coverage based upon the flow of funds required under the Indenture and not in accordance with GAAP as used in the preparation of the City’s financial statements for the Electric System. In accordance with the Indenture, depreciation, amortization and other non-cash items are not included in Operation and Maintenance Expenses. [Remainder of page intentionally left blank.]
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CITY OF VERNON ELECTRIC SYSTEM
Historical Revenues, Expenses and Debt Service Coverage Under Indenture(1)(8) Fiscal Year Ended June 30
2017 2018 2019 2020(15) 2021
Revenues
Electric Sales—Retail $153,683,228 $154,792,355 $157,112,457 $161,988,653 $162,987,498 Fuel Cost Adjustment/ECABF(2) 1,016,141 1,204,680 4,084,277 443,292 2,721,905 RECAF(3) 11,780,337 7,715,544 6,794,373 10,579,631 10,756,715 VPU Credit(4) -- -- (7,505,248) (3,685,465) (276,231)
Transmission Revenue 2,645,901 2,844,994 2,401,176 2,986,532 2,773,285 Investment Income(5) 332,982 1,151,127 1,532,262 918,236 57,190 Non-Recurring Income (Loss)(6) -- 1,121,763 12,824 -- -- Other(7) 5,386,390 5,669,963 7,756,839 5,227,203 5,588,986 Total Revenues $174,844,979 $174,500,426 $172,188,960 $178,458,082 $184,609,349 Expense Stabilization Fund Transfers
Withdrawal/Transfer from Expense
Stabilization Fund $ 2,400,000 $ 9,300,000 $ 7,400,000 $ 6,750,000 $ -- Less: Deposits of Current Revenues to
Expense Stabilization Fund -- -- -- -- --
Total Adjusted Revenues $177,244,978 $183,800,427 $179,588,960 $185,208,081 $184,609,349 Operation and Maintenance Expenses(8)
Fuel costs(9) $ 2,420,075 $ 2,895,975 $ 9,211,403 $ 5,599,650 $ 8,631,370 Costs of Renewable Resources(10) 12,603,877 13,878,758 8,454,325 13,934,096 13,079,768 Costs of Energy(11) 63,889,251 57,897,096 54,136,234 55,513,201 62,977,786 City Allocated Administrative Costs(12) 3,018,677 3,018,677 3,018,677 3,079,051 3,140,632 Other(13) 24,291,552 30,123,626 35,849,431 43,952,232 44,150,883 Total Operation and Maintenance Expenses $106,223,431 $107,814,133 $110,670,070 $122,078,230 $131,980,439 Adjusted Net Revenues
Available for Debt Service $ 71,021,547 $ 75,986,294 $ 68,918,890 $ 63,129,852 $ 52,628,910

Debt Service(14) $ 44,245,160 $ 45,312,321 $ 47,379,349 $ 47,071,332 $ 44,728,498 Debt Service Coverage Ratio 1.61 1.68 1.45 1.34 1.18
Debt Service Coverage Ratio (Excluding
Expense Stabilization Fund Transfers) 1.55 1.47 1.30 1.20 1.18 Adjusted Net Revenues Remaining
After Debt Service $ 26,776,387 $ 30,673,973 $ 21,539,541 $ 16,158,520 $ 7,900,412 Selected Balance Sheet Information
(as of June 30)
Expense Stabilization Fund $ 14,186,726 $ 27,618,339 $ 20,478,226 $ 13,913,980 $ 13,917,555 Light and Power Fund 96,699,830 101,942,893 97,986,257 108,350,186 109,567,925 Total $110,886,556 $129,561,232 $118,464,813 $122,264,166 $123,485,480

(1) Totals may not add due to rounding.
(2) In 2019, the fuel cost adjustment billing factor was replaced by the ECABF which allows for recovery of changes in costs of energy, natural gas and related capacity, transmission, transportation, grid management and extraordinary expense costs. See “THE ELECTRIC SYSTEM—Electric Rates—Energy Cost Adjustment Billing Factor.” (3) The RECAF allows for recovery of incremental costs associated with satisfying renewable resource obligations. See “THE ELECTRIC SYSTEM—Electric Rates—Renewable Energy Cost Adjustment Billing Factor.” (4) Reflects a 5% credit to customers under a program to offset an increase in the City’s user utility tax. The credit was reduced to 2% in Fiscal Year 2020 and discontinued thereafter.
(5) Does not include unrealized gain (loss) on investments or increase (decrease) in fair market value of investments. (6) Includes legal settlement and sale of emission credits. (7) Includes proceeds of 2.85% AB 1890 public benefit surcharge. See the caption “THE ELECTRIC SYSTEM—Electric Rates— General.”
(8) Operation and Maintenance Expenses excludes depreciation, amortization and certain other non-cash items. (Footnotes to table continue on next page.)
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(Footnotes to table continued from previous page.)
(9) Includes costs associated with natural gas purchased under the Supply Agreement and takes into account investment income relating to the Vernon Natural Gas Financing Authority. The term of the Supply Agreement terminated in Fiscal Year 2021.

Increase in Fiscal Year 2019 reflects increase in market price of natural gas in winter 2019 as a result of maintenance outages on SoCalGas pipelines as well as cold weather. Fiscal Year 2020 and 2021 reflect recent volatility in natural gas prices as a result of increased demand due to higher levels of liquefied natural gas exports, inclement weather, dry hydrological conditions, and interstate pipeline outages.
(10) Includes costs associated with renewable resources in accordance with RPS and regulatory requirements. (11) Represents net energy purchases and wholesale sales and capacity sales (including the Former PPTA). In Fiscal Year 2017 and 2018, also includes the Hoover Contract for Differences under which the City swapped certain economic benefits and burdens under the CES with Western for fixed energy and capacity payments. The Hoover Contract for Differences terminated in September 2017). Increase in costs of energy in Fiscal Year 2021 reflects higher natural gas and power prices due to higher levels of liquefied natural gas exports, inclement weather, dry hydrological conditions, and interstate pipeline outages. (12) Represents costs incurred for City services benefitting the Electric System. (13) Includes, among other things, transmission costs, grid management charges, ancillary services, FERC fees, maintenance service contracts and other Electric System administrative expenses. Increase in Fiscal Year 2019 reflects increases in CAISO transmission costs.
(14) Reflects debt service on outstanding Parity Obligations. (15) Increases in Revenues and Operation and Maintenance Expenses above Fiscal Year 2019 levels reflect significant increase in business operations of Matheson Tri-Gas, the Electric System’s largest customer by kWhs purchased. See “THE ELECTRIC SYSTEM—Largest Customers.” Increase in Operation and Maintenance Expenses above Fiscal Year 2019 levels also reflects higher market price for natural gas.

Source: City.

Adoption of New GASB Statement Affecting Fiscal Year 2018 The City restated the beginning balance of the Electric System’s Fiscal Year 2018 net position to retroactively reflect the implementation of Governmental Accounting Standards Board Statement No. 75, Accounting and Financial Reporting for Postemployment Benefits Other than Pensions and the corresponding adjustment to the Electric System’s share of the City’s net other post-employment benefits. As a result of this adjustment, the Electric System’s beginning net position was increased by $101,877 for Fiscal Year 2018.

Projected Operating Results and Debt Service Coverage
Set forth below are the City’s projections of Revenues, Operation and Maintenance Expenses and Debt Service coverage of the Electric System (calculated in accordance with the Indenture) for the current and next four Fiscal Years. The projected operating results are based on the City’s load forecasts, its estimated costs of power and other operating and non-operating expenses. Except for actual expenses to date for the current Fiscal Year, the City has forecasted such other operating and non-operating expenses taking into consideration the Electric System’s historical costs and trends, projected load growth and inflation. The summary below presents the calculation of Net Revenues and Debt Service coverage based upon the flow of funds required under the Indenture and not in accordance with GAAP. In accordance with the Indenture, depreciation, amortization and other non-cash items are not included in Operation and Maintenance Expenses.

Certain assumptions have been made by the City in the development of the forecasts, including the assumptions which are set forth in the footnotes to the below table. Among the assumptions made by the City are the following:

1. Economic activity by businesses within the City is assumed to result in load growth of 1% annually.

2. Renewable power costs in excess of market power will be included in customers’ bill as a RECAF.

3. Renewable energy resources are assumed to serve City load in accordance with the Statemandated RPS requirement at an estimated average cost of $33.26 per MWh from Fiscal Year 2023 through Fiscal Year 2026.

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4. Projected fuel costs are based on forecasted average monthly prices at Citygate, with natural gas prices assumed to range from $6.15 per MMBtu in Fiscal Year 2022 to $4.28 per MMBtu in Fiscal Year 2026.

5. Projected market energy purchases are based on forecasted average monthly energy prices at CAISO SP-15, with market energy prices assumed to range from $55.06 per MWh in Fiscal Year 2022 to $44.28 per MWh in Fiscal Year 2026.

While the City believes that the above assumptions are reasonable, there can be no assurance that the assumed conditions will in fact occur. The City’s projections may be affected (favorably or unfavorably) by unforeseen future events which could cause actual results to differ materially from those presented below.

Therefore, the results projected in the following table cannot be assured. [Remainder of page intentionally left blank.]
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CITY OF VERNON ELECTRIC SYSTEM
Projected Revenues, Expenses and Debt Service Coverage Under Indenture(1)(9) Fiscal Year Ending June 30
2022 2023 2024 2025 2026
Revenues
Electric Sales—Retail(2) $178,226,506 $187,829,845 $194,450,847 $201,305,240 $208,401,250 ECABF(3) 5,612,736 16,464,838 9,391,701 8,235,357 6,162,409 RECAF(4) 10,258,683 10,269,212 8,793,493 7,488,394 8,188,525 Transmission Revenue(5) 1,948,612 3,000,000 3,060,000 3,121,200 3,183,624 Investment Income(6) 300,000 306,000 312,120 318,362 324,730 Other
(7) 6,827,397 6,818,051 7,102,701 7,330,285 7,565,435
Total Revenues $203,173,934 224,687,947 223,110,863 227,798,838 233,825,973 Projected Expense Stabilization
Fund Transfers
Withdrawal/Transfer from Expense
Stabilization Fund(8) 0 7,000,000 6,500,000 7,000,000 9,000,000 Less: Deposits of Current Revenues to
Expense Stabilization Fund 0 0 0 0 0
Total Adjusted Revenues $203,173,934 $231,687,947 $229,610,863 $234,798,838 $242,825,973 Operation and Maintenance Expenses(9)
Fuel costs $ 21,835,733 $ 33,079,361 $ 29,707,933 $ 28,631,006 $ 26,651,770 Costs of Renewable Resources(10) 12,230,706 12,269,212 10,793,493 9,488,394 10,188,525 Costs of Energy(11) 59,033,557 41,971,650 38,355,689 39,427,816 42,012,362 City Allocated Administrative Costs(12) 3,203,444 3,267,513 3,332,863 3,399,520 3,467,511 Other(13) 45,435,087 51,159,269 52,470,748 53,722,493 55,113,876 Total Operation and Maintenance
Expenses $141,738,527 $141,747,005 $134,660,725 $134,669,229 $137,434,044 Adjusted Net Revenues
Available for Debt Service $ 61,435,407 $ 89,940,942 $ 94,950,138 $100,129,608 $105,391,928 Debt Service(14) $ 51,850,265 $ 69,707,353 $ 69,710,204 $ 69,706,537 $ 69,703,002 Debt Service Coverage Ratio 1.18 1.29 1.36 1.44 1.51
Debt Service Coverage Ratio (Excluding
Expense Stabilization Fund Transfers) 1.18 1.19 1.27 1.34 1.38

Adjusted Net Revenues Remaining
After Debt Service $ 9,585,142 $ 20,233,590 $ 25,239,934 $ 30,423,071 $ 35,688,926

Projected Fiscal Year End
Expense Stabilization Fund Reserve(8) $ 38,917,555 $ 31,917,555 $ 25,417,555 $ 18,417,555 $ 9,417,555

(1) Totals may not add due to rounding.
(2) Assumes load growth of 1% annually. Reflects adopted increases in Electric System rates averaging approximately 4% for Fiscal Year 2022 and 4% for Fiscal Year 2023. Also reflects additional rate increases averaging 2.5% in Fiscal Years 2024, 2025 and 2026 which have not yet been approved by the City Council. There can be no assurance that the City Council will not make further adjustments to rates that have currently been adopted. Actual rates to be effective are subject to adoption by the City Council. (3) The ECABF allows for recovery of natural gas and related capacity, transmission, transportation, grid management and extraordinary expense costs. See “THE ELECTRIC SYSTEM—Electric Rates—Energy Cost Adjustment Billing Factor.” (4) The RECAF allows for recovery of costs associated with satisfying renewable resource obligations. See “THE ELECTRIC SYSTEM—Electric Rates—Renewable Energy Cost Adjustment Billing Factor.” (5) Increase in Fiscal Year 2023 reflects proposed Edison transmission service charges effective January 1, 2022 under existing transmission service contract between Edison and the City. As a participating transmission owner in the CAISO, the City receives the revenues associated with such existing transmission service contract and pays Edison. See “THE ELECTRIC SYSTEM— Transmission, Interconnections and Distribution Facilities.” Assumes increases of approximately 2% per annum in each subsequent Fiscal Year.
(6) Assumes a 0.2% earnings rate on fund balances.
(7) Includes proceeds of 2.85% AB 1890 public benefit surcharge. See the caption “THE ELECTRIC SYSTEM—Electric Rates— General.”
(Footnotes to table continue on next page.)
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(Footnotes to table continued from previous page.)
(8) As provided in the Indenture, Adjusted Revenues includes amounts withdrawn from the Expense Stabilization Fund for any period. In each fiscal year, unspent amounts not constituting current year Revenues for such period may be returned to the Expense Stabilization Fund and made available for use in subsequent fiscal years. (9) Operation and Maintenance Expenses excludes depreciation, amortization and certain other non-cash items. (10) Includes projected costs associated with procurement of renewable resources in accordance with RPS and regulatory requirements.
(11) Includes projected costs of operating the MGS following acquisition. Includes and net energy purchases and wholesale sales and capacity sales (including costs under Hoover CES and PVNGS Contract and costs of reserve generation). Does not reflect costs under the Long-Term Services Contract as modified by the Change Order. (12) Represents costs anticipated to be incurred for City services benefitting the Electric System. Projected to increase by approximately 2% per annum.
(13) Includes, among other things, transmission costs, grid management charges, ancillary services, FERC fees, maintenance service contracts and other Electric System administrative expenses. (14) Reflects the issuance of 2021 Bonds. Assumes the delivery of the 2022 Bonds in May 2022 and the defeasance of the Refunded 2012 Bonds as described under the caption “PLAN OF FINANCE—Refunding of the 2012 Refunded Bonds.” Source: City.

Employee Benefit Obligations
Pension Obligations. Accounting and financial reporting by state and local government employers for defined benefit pension plans is governed by Governmental Accounting Standards Board (“GASB”) Statement No. 68 (“GASB 68”). GASB 68 governs the accounting treatment of defined benefit pension plans, including how expenses and liabilities are calculated and reported by state and local government employers in their financial statements. GASB 68 includes the following components: (i) unfunded pension liabilities are included on the employer’s balance sheet; (ii) pension expense incorporates rapid recognition of actuarial experience and investment returns and is not based on the employer’s actual contribution amounts; (iii) lower actuarial discount rates are required to be used for underfunded plans in certain cases for purposes of the financial statements; (iv) closed amortization periods for unfunded liabilities are required to be used for certain purposes of the financial statements; and (v) the difference between expected and actual investment returns will be recognized over a closed five-year smoothing period. GASB 68 affects the City’s accounting and reporting requirements, but it does not change the City’s pension plan funding obligations.

The City participates in a Miscellaneous plan to fund pension benefits for employees who operate the Electric System. The City’s Miscellaneous plan is administered by the California Public Employees Retirement System (“CalPERS”). CalPERS administers an agent multiple-employer public employee defined benefit pension plan for all of the City’s full-time and certain part-time employees. CalPERS provides retirement, disability and death benefits to plan members and beneficiaries and acts as a common investment and administrative agent for participating public entities within the State, including the City. CalPERS plan benefit provisions and all other requirements are established by State statute and the City Council.

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City employees are subject to different benefit levels based on their hire date. Current benefit provisions for City employees are set forth below.

CITY OF VERNON
CalPERS Miscellaneous Pension Plan – Summary of Benefit Provisions Employees Hired Before
January 1, 2013
Employees Hired On or
After January 1, 2013 (Not
Prior CalPERS Members)
Benefit Formula 2.7% @ age 55 2.0% @ age 62
Benefit Vesting 5 years of service 5 years of service
Benefit Payments Monthly for life Monthly for life
Minimum Retirement Age 50 52
Monthly Benefits as % of
Eligible Compensation 2.0% - 2.7% 1.0% - 2.5%
Employee Normal Cost 8.0%(1) 6.250%(2)
Employer Normal Cost Rate 11.380% 11.380%

(1) Employees who were hired before January 1, 2013 are required to make the full employee contribution. (2) Employees who were hired on or after January 1, 2013 who were not previously CalPERS members are required to make the full employee contribution.

Source: City.

City employees who were hired on and after January 1, 2013 and who were not previously CalPERS members receive benefits based on a 2.0% at age 62 formula; such employees are required to make the full amount of required employee contributions themselves under the California Public Employees’ Pension Reform Act of 2013 (“AB 340”), which was signed by the State Governor on September 12, 2012. AB 340 established a new pension tier: the 2.0% at age 62 formula, with a maximum benefit formula of 2.5% at age

67. Benefits for such participants are calculated on the highest average annual compensation over a consecutive 36-month period. Employees are required to pay at least 50% of the total normal cost rate. AB 340 also capped pensionable income for 2021 as noted below. Amounts are set annually, subject to Consumer Price Index increases, and retroactive benefits increases are prohibited, as are contribution holidays and purchases of additional non-qualified service credit.

CITY OF VERNON
Pensionable Income Caps for Calendar Year 2022 (AB 340 and Non-AB 340 Employees) Employees Hired Before
January 1, 2013
(Non-AB 340 Employees)
Employees Hired After
January 1, 2013
(AB 340 Employees)
Maximum Pensionable Income $305,000 $161,969
Maximum Pensionable Income if also
Participating in Social Security N/A $134,974

Source: City.

Additional employee contributions, limits on pensionable compensation and higher retirement ages for new members as a result of the passage of AB 340 are expected to reduce the City’s unfunded pension lability and potentially reduce City contribution levels in the long term.

The City is also required to contribute the actuarially determined remaining amounts necessary to fund benefits for its members. Employer contribution rates for all public employers are determined on an annual basis by the CalPERS actuary and are effective on the July 1 following notice of a change in the rate. Total plan contributions are determined through the CalPERS annual actuarial valuation process. The total Resolution No. 2022-10

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minimum required employer contribution is the sum of the plan’s employer normal cost rate (expressed as a percentage of payroll) plus the employer unfunded accrued liability contribution amount (billed monthly). The normal cost rate is the annual cost of service accrual for the upcoming Fiscal Year of active employees.

Required employer normal cost rates for Fiscal Year 2022 are 11.380% for all benefit levels, and the required employer payment of the unfunded accrued liability is $3,924,534. Required employer normal cost rates for Fiscal Year 2023 will be 11.500% for all benefit levels, and the required employer payment of the unfunded accrued liability will be $4,716,035.

The Miscellaneous plan contributions for Fiscal Years 2020 and 2021 were $4,500,718 and $4,979,905, respectively. The City currently expects its annual required contribution for the Miscellaneous plan in Fiscal Year 2022 to be approximately $5,826,164. The share of such contributions which is attributable to the Electric System is determined based on the proportion of Light and Power Fund payroll expenditures to payroll expenditures for all City employees who participate in the Miscellaneous plan. Such share was 12% in Fiscal Year 2021, and is expected to be approximately 13.9% in Fiscal Year 2022.

The City’s required contributions to CalPERS fluctuate each year and, as noted, include a normal cost component and a component equal to an amortized amount of the unfunded liability. Many assumptions are used to estimate the ultimate liability of pensions and the contributions that will be required to meet those obligations. The CalPERS Board of Administration has adjusted and may in the future further adjust certain assumptions used in the CalPERS actuarial valuations, which adjustments may increase the City’s required contributions to CalPERS in future years. Accordingly, the City cannot provide any assurances that the City’s required contributions to CalPERS in future years will not significantly increase (or otherwise vary) from any past or current projected levels of contributions. CalPERS earnings reports for Fiscal Years 2010 through 2020 report investment gains of approximately 13.3%, 21.7%, 0.1%, 13.2%, 18.4%, 2.4%, 0.6%, 11.2%, 8.6%,

6.7% and 4.7%, respectively. Preliminary returns for Fiscal Year 2021 indicate an investment gain of 21.3%.

Future earnings performance may increase or decrease future contribution rates for plan participants, including the City. The City notes that CalPERS’ earnings in Fiscal Year 2020 were below its investment targets as a result of stock market declines in the wake of the COVID-19 pandemic, which could increase future contribution rates for plan participants, including the City. See the caption “GENERAL INFORMATION REGARDING THE CITY AND THE SERVICE AREA—COVID-19.”
On December 21, 2016, the CalPERS Board of Administration voted to lower its discount rate from

7.50% to 7.00% over a three period. For public agencies such as the City, the new discount rate took effect July 1, 2017. Lowering the discount rate means that employers which contract with CalPERS to administer their pension plans will see increases in their normal costs and unfunded actuarial liabilities. Active members hired after January 1, 2013 will also see their contribution rates rise under AB 340. The reduction of the discount rate will result in average employer rate increases of approximately 1% to 3% of normal cost as a percentage of payroll for most retirement plans such as the City’s plans. Additionally, many employers will see a 30% to 40% increase in their current unfunded accrued liability payments (relative to the unfunded accrued liability payments projected in the June 30, 2015 valuation report) for pension plans. These payments are made to amortize unfunded liabilities over 20 years to bring pension funds to a fully funded status over the long-term.

The announcement on July 12, 2021 that CalPERS achieved a preliminary investment return of 21.3% for the period from July 1, 2020 through June 30, 2021 caused the CalPERS Board of Administration to lower CalPERS’ discount rate from 7.00% to 6.80% on November 15, 2021 in accordance with a risk mitigation policy that was adopted in 2015, which calls for the discount rate to be lowered if returns exceed the thencurrent discount rate by two or more percentage points. There can be no assurance as to whether or when the CalPERS Board of Administration will consider lowering the discount rate.

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Portions of the above information are primarily derived from information that has been produced by CalPERS, its independent accountants and its actuaries. The City has not independently verified such information and neither makes any representations nor expresses any opinion as to the accuracy of the information that has been provided by CalPERS.

The comprehensive annual financial reports of CalPERS are available on CalPERS’ Internet website at www.calpers.ca.gov. The CalPERS website also contains CalPERS’ most recent actuarial valuation reports and other information that concerns benefits and other matters. The textual reference to such Internet website is provided for convenience only. None of the information on such Internet website is incorporated by reference herein. The City cannot guarantee the accuracy of such information. Actuarial assessments are “forward-looking” statements that reflect the judgment of the fiduciaries of the pension plans, and are based upon a variety of assumptions, one or more of which may not materialize or be changed in the future.

The City’s Miscellaneous plan had a total net pension liability of approximately $41,962,530 for the Fiscal Year ended June 30, 2020 and approximately $46,618,461 for the Fiscal Year ended June 30, 2021. The net pension liability is the difference between the total pension liability and the fair market value of pension assets. The City’s total pension assets include funds that are held by CalPERS, and its net pension asset or liability is based on such amounts.

For Fiscal Years 2020 and 2021, the City incurred Miscellaneous plan pension expenses of $11,118,252 and $8,691,162, respectively.

A summary of principal assumptions and methods used to determine the total pension liability for Fiscal Year 2021 is shown below.

CITY OF VERNON
Actuarial Assumptions for CalPERS Miscellaneous Pension Plan Actuarial Cost Method Entry Age Normal in accordance with the requirements of GASB 68 Asset Valuation Method Market Value of Assets
Actuarial Assumptions:

Discount Rate 7.15%
Inflation 2.625%
Salary Increases Varies by entry age and service
Investment Rate of Return 7.25% net of pension plan investment and administrative expenses; includes projected inflation rate of 2.625%
Mortality Rate Table(1) Derived using CalPERS’ membership data for all funds

(1) The mortality table used was developed based on CalPERS-specific data. The table includes 15 years of mortality improvements using 90% of Scale MP-2016 published by the Society of Actuaries.

Source: City.

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Changes in the net pension liability for the City’s Miscellaneous plan in the most recent Fiscal Year for which information is available were as follows:

CITY OF VERNON
Changes in CalPERS Miscellaneous Pension Plan Net Pension Liability Increase / (Decrease)
Total
Pension Liability
Plan Fiduciary
Net Position
Net Pension
Liability / (Asset)
Balance at June 30, 2019 $175,949,364 $133,986,834 $ 41,962,530 Balance at June 30, 2020 184,953,577 138,335,116 46,618,461 Net Changes for period from July 1, 2019
through June 30, 2020 $ 9,004,213 $ 4,348,282 $ 4,655,931

Source: City.

The table below presents the net pension liability of the City’s Miscellaneous plan, calculated using the discount rate applicable to Fiscal Year 2021 (7.15%), as well as what the net pension liability would be if it were calculated using a discount rate that is 1 percentage point lower (6.15%) or 1 percentage point higher (8.15%) than the Fiscal Year 2021 rate:

CITY OF VERNON
Sensitivity of the CalPERS Miscellaneous Pension Plan Net Pension Liability to Changes in the Discount Rate
Discount Rate – 1%
(6.15%)
Applicable Discount Rate
(7.15%)
Discount Rate + 1%
(8.15%)
Plan’s Net Pension Liability/(Asset) $73,079,036 $46,618,461 $24,971,929

Source: City.

The City’s projections of Operation and Maintenance Expenses under the caption “ELECTRIC SYSTEM FINANCIAL INFORMATION—Projected Operating Results and Debt Service Coverage” do not assume unusual increases in CalPERS contributions or other labor costs in the future. However, no assurance can be provided that such expenses will not increase significantly in the future. The City does not expect that any increased funding of pension benefits will have a material adverse effect on the ability of the City to pay the 2022 Bonds.

For additional information relating to the City’s CalPERS Miscellaneous pension plan, see Note 8 to Vernon Public Utilities’ audited financial statements set forth in Appendix A.

Possible Issuance of Pension Obligation Bonds. In March 2022, the City Council approved the issuance of pension obligation bonds, the proceeds of which, if issued, would be applied to pay a portion of the City’s CalPERS Miscellaneous and Safety pension plan liability, among other things. The pension obligation bonds are currently the subject of a judicial validation proceeding and there can be no assurance that such bonds will be issued, or as to the timing or amount of any such issuance. If issued, the pension obligation bonds would not be secured by a pledge and lien on or payable from Revenues of the Electric System.

Post-Employment Benefits. In addition to the pension benefits that are described under the caption “—Pension Obligations,” the City provides certain health care benefits for retired employees and eligible dependents. Substantially all of the City’s full-time employees who are eligible for pension benefits may become eligible for such other post-employment benefits. As of June 30, 2021, 179 employees meet these eligibility requirements and 115 retirees or their beneficiaries participate in the plan, with another 29 eligible to participate but not yet doing so.

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GASB Statement No. 75 (“GASB 75”) requires governmental agencies to account for and report outstanding obligations and commitments related to post-employment benefits in essentially the same manner as for pensions. For the City, the reporting obligation began in Fiscal Year 2018.

The City retained Van Iwaarden Associates (the “Actuarial Consultant”) to calculate the City’s postemployment benefits funding status. In a report dated May 14, 2021 (the “Report”), the Actuarial Consultant concluded that, as of June 30, 2021, the City’s net liability for post-employment benefits was $20,211,850.

The Actuarial Consultant also concluded that the City’s actuarially determined contribution for Fiscal Year 2022 (the actuarial value of benefits earned during Fiscal Year 2022 plus costs to amortize the unfunded actuarial accrued liability, or “ADC”) is $1,538,693. The share of such contribution which is attributable to the Electric System is expected to be approximately 13.9% in Fiscal Year 2022. An ADC of approximately $2,692,868 and $1,931,700 was recognized for post-employment health care benefits in Fiscal Years 2020 and 2021, respectively.

Changes in the net liability for the City’s post-employment benefit plan were as follows.

CITY OF VERNON
Changes in Post-Employment Benefit Plan Liability
Increase / (Decrease)
Total
Post-Employment
Benefit Plan Liability
Plan Fiduciary
Net Position
Net Post-Employment
Benefit Plan
Liability / (Asset)
Balance at June 30, 2020 $ 26,186,840 $ 4,268,189 $ 21,918,651 Balance at June 30, 2021 27,215,028 7,003,178 20,211,850 Net Changes for period from July 1,
2020 through June 30, 2021 $ 1,028,188 $ 2,734,989 $ (1,706,801)

Source: City.

The following table presents the net liability of the City’s post-employment benefits plan, calculated using the discount rate applicable to Fiscal Year 2021 (6.25%), as well as what the net post-employment benefit liability would be if it were calculated using a discount rate that is 1 percentage point lower (5.25%) or 1 percentage point higher (7.25%) than the Fiscal Year 2021 rate:

CITY OF VERNON
Sensitivity of the Post-Employment Benefit Plan Net Liability to Changes in the Discount Rate Discount Rate – 1%
(5.25%)
Applicable Discount Rate
(6.25%)
Discount Rate + 1%
(7.25%)
Plan’s Net Liability/(Asset) $23,467,948 $20,21,850 $17,497,742

Source: City.

The City’s projections of Operation and Maintenance Expenses under the caption “ELECTRIC SYSTEM FINANCIAL INFORMATION—Projected Operating Results and Debt Service Coverage” do not assume unusual increases in post-employment benefit funding expenses in the future. However, future changes in funding policies and assumptions, including those related to assumed rates of investment return and healthcare cost inflation, could trigger increases in the City’s annual required contributions, and such increases could be material to the finances of the City. No assurance can be provided that such expenses will not increase significantly in the future. The City does not expect that any increased funding of post-employment benefits will have a material adverse effect on the ability of the City to pay the 2022 Bonds.

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For additional information relating to the post-employment benefit plan, see Note 9 to Vernon Public Utilities’ audited financial statements set forth in Appendix A.

FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY
The following discussion of legislative, regulatory and other factors affecting the electric utility industry should be considered when considering an investment in the 2022 Bonds. This discussion does not purport to be comprehensive or definitive, and these matters are subject to change subsequent to the date hereof. The electric industry has historically been subject to continuing legislative and administrative reform.

The City cannot predict at this time whether any additional legislation or rules will be enacted which will affect the finances or operations of the Electric System, but the impacts could be significant. 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 2022 Bonds should obtain and review such information. Such information is not incorporated herein by reference.

Federal Energy Legislation
Energy Policy Act of 2005. Under the federal Energy Policy Act of 2005 (“EPAct 2005”), FERC was given refund 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 (“CFTC”) 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 (the “Reliability Standards”) to increase system reliability and minimize blackouts. 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 NERC as the ERO. Many Reliability Standards have since been approved by FERC. The Reliability Standards include requirements related to cyber and physical security of systems that could affect the reliable operation of the electric grid.

The ERO or the entities to which NERC has delegated enforcement authority through an agreement approved by FERC (“Regional Entities”), such as the WECC, may enforce the Reliability Standards, subject to FERC oversight, or FERC may independently enforce them. Potential monetary sanctions include fines in excess of $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 authorized 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 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 888 also requires “non-jurisdictional utilities” that purchase transmission services from a jurisdictional utility under an open access tariff and that own or control 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 to itself.

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Section 211A of 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 its transmission facilities: (1) at rates that are comparable to those that the unregulated transmitting utility 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 which 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 Order 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 stated 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 utilities to participate in the regional processes for transmission planning and that FERC will pursue associated complaints against such utilities on a case-by-case basis.

Federal Policy on Cybersecurity
In February 2013, then-President Obama issued an Executive Order “Improving Critical Infrastructure Security” (the “Cybersecurity Order”). Among other things, the Cybersecurity Order called for improved information sharing and processing of security clearances for owners and operators of critical infrastructure.

The Cybersecurity Order further required the Secretary of Commerce to direct the National Institute of Standards and Technology (“NIST”) to lead the development of a framework (“Framework”) to reduce cyber risks to critical infrastructure. The voluntary Framework will continue to be updated and improved as industry provides feedback on implementation.

The Cybersecurity Information Sharing Act of 2015 was signed into law in December 2015. It created an industry-supported, voluntary cybersecurity information sharing program which facilitates the secure sharing of cyber-related threat information among both public and private sector entities. Participating entities share and receive information about cybersecurity threats in real time through several hubs, including the Electricity Information Sharing and Analysis Center (E-ISAC) and the National Cybersecurity and Communication Integration Center, as tools to actively manage risk related to potential cyber intrusion.

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), cybersecurity, reducing regulatory burdens, climate change and water quality. Many of these bills, if enacted into law, could have a material impact on the City and the electric utility industry 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, environmental requirements and cybersecurity is also possible. The City is unable to predict the outcome or potential impacts of any possible legislation on the City at this time.

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Environmental Issues
General. Electric utilities are subject to continuing environmental regulation. Federal, State and local standards and procedures which regulate the environmental impact of electric utilities are subject to change.

These changes may arise from new and changing legislative, regulatory and judicial action regarding such standards and procedures. Consequently, there is no assurance that any Electric System facilities or projects 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. In addition, the election of new administrations, including the President of the United States, could substantially impact current environmental standards and regulations and other matters described herein. New laws and regulations could be imposed that could impact the City’s ability to operate the Electric System or impose significant compliance costs. The inability to comply with environmental standards could result in, for example, additional capital expenditures, reduced operating levels or the shutdown of individual units which are 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 and Other 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 source and requires best available control technologies (“BACT”) 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. Under these permitting programs, as major stationary sources, combustion turbines such as the MGS are also subject to regulations imposing national emission standards for hazardous air pollutants (HAP), requiring the application of maximum achievable control technology for combustions, and new source performance standards regulating nitrogen oxides (“NOx”) and sulfur dioxide.

On October 23, 2015, the EPA, under the Obama Administration, 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 targets 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 “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 others, the D.C. Circuit vacated the Affordable Clean Energy Rule. The City cannot predict the timing or content of any new regulations that may be proposed to replace the Affordable Clean Energy Rule. At this time, the City does not expect any such regulations to have material effects on its Electric System.

Air Quality – 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 “nonattainment 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. These developments may result in stringent Resolution No. 2022-10

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permitting processes for new sources of emissions and additional state restrictions on existing sources of emissions, such as power plants. In addition, the U.S. Supreme Court found in its review of EPA v. EME Homer City Generation, LP that the EPA has authority to impose a Cross-State Air Pollution Rule (the “Transport Rule”) which curbs air pollution emitted in upwind states to facilitate downwind attainment of three NAAQS. On November 26, 2014, the EPA proposed to strengthen the stringency of the NAAQS for ozone by lowering the existing ozone standard of 75 parts per billion (“ppb”) to between 65 and 70 ppb, although the EPA also sought public comment on a standard as low as 60 ppb. On October 1, 2015, the EPA issued its final rule, lowering the ozone standard to 70 ppb. Legal challenges to the final rule have been filed by a number of states and industry groups. On March 12, 2018, a federal district judge in Northern California ordered the EPA to complete the strengthened 2015 ozone standard designations later in 2018. The EPA noticed a final rule on December 6, 2018 implementing ozone NAAQS for non-attainment areas and addressing state implementation plan requirements. That rule became effective on February 4, 2019. On July 15, 2020, the EPA announced a proposed decision to retain the existing 70 ppb ozone standard. The comment period closed on October 1, 2020. The decision was finalized on December 7, 2020. President Biden issued an executive order instructing the EPA to consider suspending, revising or rescinding the decision.

California law also mandates California ambient air quality standards (“CAAQS”), which are often more stringent than national standards. CAAQS for particulate matter became effective in June 2003. Revised CAAQS for ozone and nitrogen dioxide (NO2) went into effect in May 2006 and March 2008, respectively.

California law does not require that CAAQS be met by specified dates as is the case with NAAQS. Rather, it requires incremental progress toward attainment. In addition, attainment of the NAAQS has precedence over attainment of the CAAQS due to federal penalties for failure to meet federal attainment deadlines.

SCAQMD Air Quality Management Plan. The SCAQMD periodically prepares an overall plan, known as an Air Quality Management Plan (the “AQMP”), which includes control measures to meet federal air quality standards and incorporate the latest technical planning information. In March 2017, the SCAQMD adopted its 2016 AQMP, which is a regional and multi-agency effort. The SCAQMD held stakeholder working group meetings in connection with its development of rules and rule amendments to implement the control measures included in the 2016 AQMP, and submitted their control measure plan to the EPA in December 2019. The SCAQMD is in the early stages of the 2022 AQMP process, and is looking for a 45% reduction in NOx emissions through this plan. The City will continue to monitor development of the 2022 AQMP for any emission reduction measures that will affect power plants. At this time, AQMP working groups are primarily focusing on charging and fueling infrastructure needs and other mobile source categories.

Air Quality – Nitrogen Oxide (NOx) Emissions. In 1994, the SCAQMD implemented its Regional Clean Air Incentives Market (“RECLAIM”) NOx regulations. In accordance with these regulations, the SCAQMD established annual NOx allocations for stationary source facilities based on historical emissions with a declining emissions cap. These allocations are in the form of RECLAIM trading credits (“RTCs”).

Facilities can comply with RECLAIM by purchasing RTCs from the RECLAIM market, installing emission controls, and/or reducing operations.

In March 2017, the SCAQMD adopted the 2016 AQMP (as described above) and included a control measure to achieve an additional five tons per day NOx reduction as soon as feasible but no later than 2025, and to transition the RECLAIM program to a command-and-control regulatory structure requiring Best Available Retrofit Control Technology (“BARCT”) as soon as feasible.

In July 2017, then-Governor Brown approved AB 617 which addresses criteria pollutants (including NOx) and toxic air contaminants at stationary sources. RECLAIM facilities are subject to the BARCT requirements of AB 617.

RECLAIM working group meetings have been ongoing related to the transition from the market-based RECLAIM program to a command-and-control regulatory structure. The RECLAIM program was originally scheduled to end on December 31, 2023 but is now expected to extend past 2024 after the EPA’s approval of Resolution No. 2022-10

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the State Implementation Plan and the resolution of outstanding issues with the New Source Review (“NSR”) Program. The RECLAIM working group has been having discussions regarding the NSR Program and its applicability to major source modifications after exiting the RECLAIM Program. SCAQMD is currently reviewing the current NSR process and is considering comments from stakeholders regarding SCAQMD’s proposed changes to the NSR process. The MGS will transition from RECLAIM to a source-specific NOx rule for electric generating units that will include NOx limits reflecting BARCT. SCAQMD Rule 1135, the “command-and-control” rule for electric generating units, was adopted on November 2, 2018. Instead of receiving an annual allocation of emission credits, electric generating units will be required to meet a NOx emission limit. The NOx emission limits for simple cycle gas turbines is 2.5 parts per million (ppm) over a 60- minute rolling average. SCAQMD is hosting additional working group meetings for Rule 1135 beginning in May 2021 to amend the rule to include additional startup and shutdown provisions and ammonia slip limits.

Climate Change. Legislative and regulatory responses to climate change and the effects of climate change have impacted, and could impact in the future, the costs and operations of electric utilities, including the Electric System. A number of federal and state laws, rules and regulations that limit carbon dioxide and other GHG emissions from electric generating facilities have been enacted. Absent legislative action by the U.S. Congress, the EPA has authority to regulate carbon dioxide and other GHG emissions under the Clean Air Act, and any future administrations could promulgate new rules or rules that replace the now-vacated Affordable Clean Energy Rule. Furthermore, changes in temperatures, precipitation and the frequency and severity of extreme weather events (such as tornadoes and flooding) and other impacts of climate change could affect peak demands, the operations of the City’s Electric System and the costs of maintaining its facilities and projects. The impacts of these weather events on current and future operations cannot be predicted at this time.

Electric and Magnetic Fields. A number of studies have been conducted regarding the potential long-term health effects of exposure to electric and magnetic fields created by high voltage transmission and distribution equipment. Additional studies are being conducted to determine the relationship between electric and magnetic fields and certain adverse health effects, if any. At this time, it is not possible to predict the extent of the costs and other impacts, if any, which the electric and magnetic fields concerns may have on electric utilities, including the Electric System.

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 that are 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 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 investor-owned utilities; (g) increased competition from independent power producers and marketers, brokers and federal power marketing agencies; (h) “self-generation” or “distributed generation” (such as microturbines, fuel cells and solar installations) 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 from transmission line projects financed with outstanding tax-exempt obligations; (j) effects 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) sudden and dramatic increases in the Resolution No. 2022-10

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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 the past in California; (o) inadequate risk management procedures and practices with respect to, among other things, the purchase and sale of energy and transmission capacity; (p) other legislative changes, voter initiatives, referenda and statewide propositions; (q) effects of the changes in the economy, population and demand of customers within a utility’s service area; (r) effects of possible manipulation of the electric markets; (s) acts of terrorism or cyber-terrorism; (t) natural disasters or other physical calamities, including, but not limited to, earthquakes, floods and wildfires, and potential liabilities of electric utilities in connection therewith; (u) changes to the climate; and (v) adverse impacts to the market for insurance relating to recent wildfires and other calamities, leading to higher costs or prohibitively expensive coverage, or limited or unavailability of coverage for certain types of risk. Any of these factors (as well as other factors) could have an adverse effect on the financial condition of any given electric utility and likely will affect individual utilities in different ways.

CONSTITUTIONAL LIMITATIONS ON TAXES AND FEES
Articles XIIIC and XIIID of the State Constitution
Proposition 218, a State ballot initiative known as the “Right to Vote on Taxes Act,” was approved by the voters of the State on November 5, 1996. Proposition 218 added Articles XIIIC and XIIID to the State Constitution. Article XIIID creates additional requirements for the imposition by most local governments (including the City) of general taxes, special taxes, assessments and “property-related” fees and charges.

Property-related fees include many utility charges such as water rates but Article XIIID explicitly exempts fees for the provision of electric service from its provisions. Nevertheless, Proposition 218 could indirectly affect some municipally-owned electric utilities. For example, to the extent that Proposition 218 reduces a city’s general fund revenues, that city could seek to increase the transfers from its electric utility to its general fund.

For information on the Indenture provisions limiting the City’s authority to transfer moneys from the Light and Power Fund to the General Fund, see the caption “SECURITY AND SOURCES OF PAYMENT—Transfers to General Fund” and the discussion of Proposition 26 below.

Article XIIIC expressly extends the people’s initiative power to reduce or repeal previouslyauthorized local taxes, assessments and fees and charges. The terms “fees and charges” are not defined in Article XIIIC, although the State Supreme Court held in Bighorn-Desert View Water Agency v. Verjil, 39 Cal.4th 205 (2006), that the initiative power described in Article XIIIC may apply to a broader category of fees and charges 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 electric rates are subject to the initiative power. Thus, even electric service charges (which are expressly exempted from the provisions of Article XIIID) might be subject to the initiative provisions of Article XIIIC, thereby subjecting such fees and charges imposed by the City to reduction by the electorate. The City 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 electric rates and charges in a manner adversely affecting the payment of the 2022 Bonds by virtue of the “impairment of contracts clause” of the United States and State Constitutions.

Proposition 26 was approved by the voters of the State on November 2, 2010. Proposition 26 amended Articles XIIIA and XIIIC of the State Constitution to impose a two-thirds voter approval requirement for the imposition of certain fees and charges by the State. It also imposes a majority voter approval requirement on local governments with respect to fees and charges for general purposes and a two-thirds voter approval requirement with respect to fees and charges for special purposes. The initiative, according to its supporters, was intended to prevent the circumvention of tax limitations imposed by the voters pursuant to Proportion 13, approved in 1978, and other measures, such as Proposition 218, through the use of non-tax fees and charges. Proposition 26 expressly excludes from its scope “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.” The City believes that the initiative was not intended to and would not apply to Electric System rates so long as such rates do not Resolution No. 2022-10

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exceed the reasonable costs to the City of providing electric service; however, the City is unable to predict how Proposition 26 will be interpreted by the courts to apply to the provision of utility services by local governments such as the electric service provided by the Electric System.

In Citizens for Fair REU Rates v. City of Redding, the Court of Appeal of California, Third Appellate District, held, in an opinion filed January 20, 2015 and modified February 19, 2015, that a municipal utility’s recurring budget transfer from its electric utility fund to its general fund, referred to therein as a payment in lieu of taxes, constitutes a tax under Proposition 26 unless it can be shown that the transferred amount reflects the reasonable costs borne by the city to provide governmental services to the electric utility. The City of Redding appealed the decision to the State Supreme Court, which reversed the judgment of the Court of Appeal on August 27, 2018. The State Supreme Court determined that the budgetary transfer from the City of Redding electric utility to its general fund is not the type of exaction that is subject to Article XIIIC of the State Constitution. The State Supreme Court reasoned that it is only the City of Redding electric utility rate, not the payment in lieu of taxes, that is imposed on customers for electric service. The State 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 payment to the General Fund) 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 annually transfers certain amounts from the Light and Power Fund to the City’s General Fund as discussed under the caption “SECURITY AND SOURCES OF PAYMENT—Transfers to General Fund,” and sets its rates and its budget with the expectation that certain transfers will be made to the City in accordance with the restrictions that are set forth in the Indenture. In the event that General Fund transfers are further restricted, the City does not believe that any such further restrictions would have a material adverse effect on the financial position of the Electric System. However, any such further restrictions on transfers may cause the City to evaluate new strategies to generate revenues to fund services provided by the City.

Future Initiatives
Articles XIIIC and XIIID limit the ability of governmental agencies to increase certain fees and charges. Such articles were adopted pursuant to measures which qualified for the ballot pursuant to the State’s Constitutional initiative process. While the City believes that Articles XIIIC and XIIID do not affect the Electric System’s rates and charges so long as the rates do not exceed the reasonable costs to the City of providing the utility services, from time to time other initiative measures could be adopted by State voters.

The adoption of any such initiatives might place limitations on the ability of the City and its Electric System to increase revenues.

APPROVAL OF LEGAL PROCEEDINGS
The valid, legal and binding nature of the 2022 Bonds is subject to the approval of Stradling Yocca Carlson & Rauth, a Professional Corporation, acting as Bond Counsel. The form of such legal opinion is attached hereto as Appendix C, and such legal opinion will be attached to each 2022 Bond. Certain legal matters will be passed upon for the City by Stradling Yocca Carlson & Rauth, a Professional Corporation, as Disclosure Counsel, and by the City Attorney, for the Underwriter by its counsel, Chapman and Cutler LLP, and for the Trustee by its counsel.

LITIGATION
At the time of delivery of and payment for the 2022 Bonds, the City will certify substantially to the effect that there is no action, suit, proceeding, inquiry or investigation, at law or in equity, before or by any court, regulatory agency, public board or body, pending or, to the knowledge of the City, threatened against the City affecting the existence of the City or the titles of its directors or officers to their respective offices or seeking to restrain or to enjoin the sale or delivery of the 2022 Bonds, the application of the proceeds thereof in accordance with the Indenture, or in any way contesting or affecting the validity or enforceability of the 2022 Resolution No. 2022-10

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Bonds, the Indenture, or any action of the City contemplated by any of said documents, or in any way contesting the completeness or accuracy of this Official Statement or any amendment or supplement thereto, or contesting the powers of the City or its authority with respect to the 2022 Bonds, or any action of the City contemplated by any of said documents, nor to the knowledge of the City, is there any basis therefor.

TAX MATTERS
In the opinion of Stradling Yocca Carlson & Rauth, a Professional Corporation, Newport Beach, California, Bond Counsel, under existing statutes, regulations, rulings and judicial decisions, and assuming the accuracy of certain representations and compliance with certain covenants and requirements described herein, interest (and original issue discount) on the 2022 Bonds is excluded from gross income for federal income tax purposes and is not an item of tax preference for purposes of calculating the federal alternative minimum tax imposed on individuals. In the further opinion of Bond Counsel, interest (and original issue discount) on the 2022 Bonds is exempt from State of California personal income tax.

Bond Counsel’s opinion as to the exclusion from gross income for federal income tax purposes of interest (and original issue discount) on the 2022 Bonds is based upon certain representations of fact and certifications made by the City and others and is subject to the condition that the City comply with all requirements of the Internal Revenue Code of 1986 (the “Code”) that must be satisfied subsequent to the issuance of the 2022 Bonds to assure that interest (and original issue discount) on the 2022 Bonds will not become includable in gross income for federal income tax purposes. Failure to comply with such requirements of the Code might cause interest (and original issue discount) on the 2022 Bonds to be included in gross income for federal income tax purposes retroactive to the date of issuance of the 2022 Bonds. The City has covenanted to comply with all such requirements.

In the opinion of Bond Counsel, the difference between the issue price of a 2022 Bond (the first price at which a substantial amount of the 2022 Bonds of a maturity is to be sold to the public) and the stated redemption price at maturity of such 2022 Bond constitutes original issue discount. Original issue discount accrues under a constant yield method, and original issue discount will accrue to a Beneficial Owner before receipt of cash attributable to such excludable income. The amount of original issue discount deemed received by a Beneficial Owner will increase the Beneficial Owner’s basis in the applicable 2022 Bond. The amount of original issue discount that accrues to the Beneficial Owner of a 2022 Bond is excluded from the gross income of such Beneficial Owner for federal income tax purposes, is not an item of tax preference for purposes of the federal alternative minimum tax imposed on individuals, and is exempt from State of California personal income tax.

The amount by which a 2022 Bondowner’s original basis for determining loss on sale or exchange in the applicable 2022 Bond (generally, the purchase price) exceeds the amount payable on maturity (or on an earlier call date) constitutes amortizable bond premium, which must be amortized under Section 171 of the Code; such amortizable bond premium reduces the 2022 Bondowner’s basis in the applicable 2022 Bond (and the amount of tax-exempt interest received with respect to the 2022 Bonds), and is not deductible for federal income tax purposes. The basis reduction as a result of the amortization of bond premium may result in a 2022 Bondowner realizing a taxable gain when a 2022 Bond is sold by the Owner for an amount equal to or less (under certain circumstances) than the original cost of the 2022 Bond to the Owner. Purchasers of the 2022 Bonds should consult their own tax advisors as to the treatment, computation and collateral consequences of amortizable bond premium.

The Internal Revenue Service (the “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 2022 Bonds will be selected for audit by the IRS. It is also possible that the market value of the 2022 Bonds might be affected as a result of such an audit of the 2022 Bonds (or by an audit of similar municipal obligations). No assurance can be given that in the course of an audit, as a result of an audit, or otherwise, Congress or the IRS might not change the Code (or interpretation thereof) subsequent to the issuance of the 2022 Bonds to the extent that it Resolution No. 2022-10

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adversely affects the exclusion from gross income of interest (and original issue discount) on the 2022 Bonds or their market value.

SUBSEQUENT TO THE ISSUANCE OF THE 2022 BONDS THERE MIGHT BE FEDERAL,

STATE OR LOCAL STATUTORY CHANGES (OR JUDICIAL OR REGULATORY CHANGES TO OR

INTERPRETATIONS OF FEDERAL, STATE OR LOCAL LAW) THAT AFFECT THE FEDERAL, STATE OR LOCAL TAX TREATMENT OF THE 2022 BONDS, INCLUDING THE IMPOSITION OF

ADDITIONAL FEDERAL INCOME OR STATE TAXES ON OWNERS OF TAX-EXEMPT STATE OR LOCAL OBLIGATIONS, SUCH AS THE 2022 BONDS. THESE CHANGES COULD ADVERSELY AFFECT THE MARKET VALUE OR LIQUIDITY OF THE 2022 BONDS. NO ASSURANCE CAN BE GIVEN THAT SUBSEQUENT TO THE ISSUANCE OF THE 2022 BONDS STATUTORY CHANGES

WILL NOT BE INTRODUCED OR ENACTED OR JUDICIAL OR REGULATORY INTERPRETATIONS WILL NOT OCCUR HAVING THE EFFECTS DESCRIBED ABOVE. BEFORE PURCHASING ANY OF THE 2022 BONDS, ALL POTENTIAL PURCHASERS SHOULD CONSULT THEIR TAX ADVISORS

REGARDING POSSIBLE STATUTORY CHANGES OR JUDICIAL OR REGULATORY CHANGES OR INTERPRETATIONS, AND THEIR COLLATERAL TAX CONSEQUENCES RELATING TO THE 2022 BONDS.

Bond Counsel’s opinions with respect to the 2022 Bonds may be affected by actions taken (or not taken) or events occurring (or not occurring) after the date hereof. Bond Counsel has not undertaken to determine, or to inform any person, whether any such actions or events are taken or do occur. The Indenture and the Tax Certificate relating to the 2022 Bonds permits certain actions to be taken or to be omitted if a favorable opinion of Bond Counsel is provided with respect thereto. Bond Counsel expresses no opinion as to the effect on the exclusion from gross income of interest (and original issue discount) for federal income tax purposes with respect to any 2022 Bond if any such action is taken or omitted based upon the advice of counsel other than Stradling Yocca Carlson & Rauth, a Professional Corporation.

Although Bond Counsel has rendered an opinion that interest (and original issue discount) on the 2022 Bonds is excluded from gross income for federal income tax purposes provided that the City continues to comply with certain requirements of the Code, the ownership of the 2022 Bonds and the accrual or receipt of interest (and original issue discount) on the 2022 Bonds may otherwise affect the tax liability of certain persons. Bond Counsel expresses no opinion regarding any such tax consequences. Accordingly, before purchasing any of the 2022 Bonds, all potential purchasers should consult their tax advisors with respect to collateral tax consequences relating to the 2022 Bonds.

Should interest (and original issue discount) on the 2022 Bonds become includable in gross income for federal income tax purposes, the 2022 Bonds are not subject to early redemption and will remain outstanding until maturity or until redeemed in accordance with the Indenture.

Copies of the proposed form of the opinion of Bond Counsel is attached hereto as Appendix C.

RATINGS
S&P Global Ratings (“S&P”) and Moody’s Ratings, Inc. (“Moody’s”) have assigned the 2022 Bonds the ratings of “BBB+” and “Baa1”, respectively. S&P’s rating outlook with respect to the 2022 Bonds is “stable.” Moody’s rating outlook with respect to the 2022 Bonds is “stable.” There is no assurance that any credit rating that is given to the 2022 Bonds will be maintained for any period of time or that a rating may not be lowered or withdrawn entirely by the applicable rating agency if, in the judgment of such rating agency, circumstances so warrant. Any downward revision or withdrawal of a rating may have an adverse effect on the market price of the 2022 Bonds. The ratings reflect only the views of S&P and Moody’s, respectively, and an explanation of the significance of such ratings may be obtained from S&P or Moody’s, as applicable.

Generally, a rating agency bases its ratings on the information and materials that are furnished to it (which may include information and material from the City that is not included in this Official Statement) and on investigations, studies and assumptions of its own.

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The City will covenant in a Continuing Disclosure Agreement to file notices of any rating changes on the 2022 Bonds with EMMA. See the caption “CONTINUING DISCLOSURE” and Appendix E.

Notwithstanding such covenant, information relating to rating changes on the 2022 Bonds may be publicly available from the rating agencies prior to such information being provided to the City and prior to the date by which the City is obligated to file a notice of rating change. Purchasers of the 2022 Bonds are directed to the rating agencies and their respective websites and official media outlets for the most current ratings with respect to the 2022 Bonds after the initial issuance of the 2022 Bonds.

In providing a rating on the 2022 Bonds, S&P or Moody’s may have performed independent calculations of debt service coverage ratios using their own internal formulas and methodology, which may not reflect the provisions of the Indenture. The City makes no representations as to any such calculations, and such calculations should not be construed as a representation by the City as to past or future compliance with any financial covenants, the availability of particular revenues for the payment of debt service or for any other purpose.

MUNICIPAL ADVISOR
The City has retained BLX Group LLC as municipal advisor (the “Municipal Advisor”) in connection with the issuance of the 2022 Bonds. The Municipal Advisor has not undertaken to make an independent verification or to assume responsibility for the accuracy, completeness, or fairness of the information contained in this Official Statement. The Municipal Advisor is an independent advisory firm and is not engaged in the business of underwriting, trading or distributing municipal or other public securities.

UNDERWRITING
The 2022 Bonds will be purchased by Goldman Sachs & Co. LLC (the “Underwriter”), pursuant to a Forward Delivery Purchase Contract, dated December 7, 2021 (the “Purchase Contract”), by and between the City and the Underwriter. Under the Purchase Contract, the Underwriter has agreed, subject to the satisfaction of certain terms and conditions, certain of which are described under the caption “FORWARD DELIVERY OF THE 2022 BONDS,” to purchase all, but not less than all, of the 2022 Bonds on or about May 5, 2022 (the “Settlement Date”) for an aggregate purchase price of $62,006,024.62 (representing the principal amount of the 2022 Bonds, less an Underwriter’s discount of $243,932.48, plus a net original issue premium of $10,179,957.10). The Purchase Contract provides that the Underwriter will purchase all of the 2022 Bonds if any are purchased, the obligation to make such a purchase being subject to certain terms and conditions set forth in the Purchase Contract, the approval of certain legal matters by counsel and certain other conditions.

The initial public offering prices stated on the inside cover page of this Official Statement may be changed from time to time by the Underwriter. The Underwriter may offer and sell the 2022 Bonds to certain dealers (including dealers depositing 2022 Bonds into investment trusts), dealer banks, banks acting as agents and others at prices lower than said public offering prices.

The Underwriter and its affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and nonfinancial activities and services. The Underwriter has provided, and may in the future provide, a variety of these services to the City and to persons and entities with relationships with the City, for which they received or will receive customary fees and expenses.

In the ordinary course of their various business activities, the Underwriter and its affiliates, officers, directors and employees may purchase, sell or hold a broad array of investments and actively trade securities, derivatives, loans, commodities, currencies, credit default swaps and other financial instruments for their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to assets, securities and/or instruments of the City (directly, as collateral securing other obligations or otherwise) and/or persons and entities with relationships with the City. The Underwriter and its affiliates may Resolution No. 2022-10

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also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such assets, securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.

FORWARD DELIVERY OF THE 2022 BONDS
General
The Underwriter has agreed to purchase the 2022 Bonds, subject to the satisfaction of the terms and conditions of a Forward Delivery Purchase Contract, certain of which are described in the following subsections.

Certain Terms Concerning Forward Delivery
Under the Forward Delivery Purchase Contract, the Underwriters are not required to purchase the 2022 Bonds if, among other conditions, (1) there has been a Change in Law (as defined below); (2) the House of Representatives or the Senate of the Congress of the United States, or a committee of either, shall have pending before it, or shall have passed or recommended favorably, legislation which, if enacted in the form as introduced or as amended, would have the purpose or effect of imposing federal income taxation upon revenues or other income of the general character to be derived by the Electric System or by any similar body or upon interest received on the 2022 Bonds, or obligations of the general character of the 2022 Bonds, or causing interest on the 2022 Bonds, or obligations of the general character of the 2022 Bonds, to be includable in gross income for purposes of federal income taxation; (3) any legislation, regulation, ruling, order, release, court decision or judgment or action by the U.S. Department of the Treasury, the Internal Revenue Service, or any agency of the State is either enacted, issued, effective, or adopted, that would have the purpose or effect of imposing federal income taxation upon revenues or other income of the general character to be derived by the Electric System or by any similar body or upon interest received on the 2022 Bonds, or obligations of the general character of the 2022 Bonds, or causing interest on the 2022 Bonds, or obligations of the general character of the 2022 Bonds, to be includable in gross income for purposes of federal and State income taxation ; (4) legislation shall be enacted, or a decision by a court of the United States shall be rendered, or any action shall be taken by, or on behalf of, the Securities Exchange Commission which has the effect of requiring the 2022 Bonds to be registered under the Securities Act of 1933, as amended, or requires the qualification of the Indenture under the Trust Indenture Act of 1939, as amended; (5) a general banking moratorium has been declared by federal, New York or California authorities and it is in effect as of the Settlement Date; (6) an order, decree or injunction of any court of competent jurisdiction shall be rendered, or any order, ruling , regulation or official statement by the U.S. Securities and Exchange Commission shall be issued which has the effect of making the issuance and sale of the 2022 Bonds to be in violation of the federal securities laws, as amended; (7) this Official Statement, as of its date and as of the Settlement Date, contained or contains any untrue statement of a material fact or omitted or omits to state a material fact required to be stated therein or necessary to make the statements therein, in light of the circumstances under which they were made, not misleading; (8) an event of default, technical or otherwise, has occurred and is continuing on the Settlement Date under the Indenture; (9) evidence of then current ratings on the 2022 Bonds from S&P and Moody’s as reflected in the Updated Official Statement is not delivered; and (10) there has been a material adverse change in the business, properties, assets, results of operations, financial position or affairs of the Electric System or the City (and affecting the Electric System) that, in the reasonable judgment of the Underwriter, materially adversely affects the market price or the marketability of the 2022 Bonds.

A “Change in Law” means (i) any change in or addition to applicable federal or State law, whether statutory or as interpreted by the courts or by federal or State agencies, including any changes in or new rules, regulations or other pronouncements or interpretations by federal or State agencies, (ii) any legislation enacted by the Congress of the United States (if such enacted legislation has an effective date that is on or before the date of Settlement), (iii) any law, rule or regulation enacted by any governmental body, department or agency (if such enacted law, rule or regulation has an effective date that is on or before the date of Settlement) or Resolution No. 2022-10

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(iv) any judgment, ruling or order issued by any court or administrative body, which in any case would, (A) as to the Underwriter, prohibit the Underwriter from completing the underwriting of the 2022 Bonds or selling the Bonds or beneficial ownership interests therein to the public or, (B) as to the City, would make the completion of the issuance, sale or delivery of the 2022 Bonds illegal.

Certain Considerations
Issuance and delivery of the 2022 Bonds will be dependent on receipt by the City of the opinion of Bond Counsel to the effect set forth in Appendix C on the Settlement Date and of certain other documents required by the Forward Delivery Purchase Contract, and payment of the purchase price by the Underwriter in accordance with the Forward Delivery Purchase Contract on the Settlement Date.

Bond Counsel could be prevented from rending its opinion on the Settlement Date with respect to the 2022 Bonds as a result of (i) changes or proposed changes, prior to the Settlement Date, in federal or California state laws, court decisions, regulations or proposed regulations, or rulings of administrative agencies or (ii) the failure of the City to provide closing documents, satisfactory to Bond Counsel, of the type customarily required in connection with the issuance of tax-exempt bonds, such as certificates to the effect that the proceedings of the City with respect to the issuance of the 2022 Bonds have not been amended or repealed, in a manner detrimental to holders of the 2022 Bonds, by executive, legislative or administrative action.

Pursuant to the Forward Delivery Purchase Contract, the City agreed to deliver this Official Statement, which has been updated since the Official Statement delivered on December 7, 2021, as supplemented by a supplement to the Official Statement dated January 7, 2022, in connection with the sale of the 2021A Bonds and the 2022 Bonds, and to provide a reasonable number of copies of this Official Statement, if any, to the Underwriter. With this exception, the City and the Underwriter have not agreed to, nor are they obligated to provide updates to the information contained in this Official Statement during the period of time between the date of sale of the 2022 Bonds and the Settlement Date.

Rating Risk
S&P and Moody’s have each issued their rating for the 2022 Bonds. See “RATINGS” above. No assurance can be given that at the Settlement Date of the 2022 Bonds, such ratings will continue to be in effect.

The Underwriter may not terminate its obligation to purchase the 2022 Bonds unless evidence of then current ratings on the 2022 Bonds from S&P and Moody’s as reflected in the Updated Official Statement is not delivered. The ratings in effect as of the Settlement Date need not be the same ratings that were expected as of the issuance of the 2022 Bonds.

Secondary Market Risk
The Underwriter is not obligated to make a secondary market in the 2022 Bonds and no assurance can be given that a secondary market will exist for the 2022 Bonds.

Market Value Risk
The market value of the 2022 Bonds as of the Settlement Date may be affected by a variety of factors including, without limitation, general market conditions, the ratings then assigned to the 2022 Bonds, the financial condition and business operations of the City and federal and state income tax and other laws. Thus, the market value of the 2022 Bonds on the Settlement Date could be greater or less than the agreed purchase price to be paid by the initial purchasers of the 2022 Bonds, and that difference could be substantial. Neither the City nor the Underwriter make any representation as to the market value of the 2022 Bonds as of the Settlement Date.

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Federal Tax Proposals
The Forward Delivery Purchase Contract obligates the City to deliver and the Underwriter to acquire the 2022 Bonds if, among other things, the City delivers an opinion of Bond Counsel substantially in the form set forth in Appendix C hereto to the effect that the interest on the 2022 Bonds is excluded from gross income for federal income tax purposes under Section 103 of the Code. It is possible that certain bills could be introduced (or that bills previously introduced could be amended) in the U.S. Congress that, if adopted, would reform the system of federal taxation. Those bills could (i) eliminate the tax exemption granted under Section 103 of the Code to interest payable on “state or local bonds” such as the 2022 Bonds, or (ii) diminish the value of the federal tax exemption granted interest on such bonds under the current system of federal income taxation. If, however, legislation only diminishes the value of the tax exemption, and the City satisfies the requirements for the delivery of the 2022 Bonds set forth in the Forward Delivery Purchase Contract, then the Underwriter would still be required to accept delivery of the 2022 Bonds at the Settlement Date. Prospective purchasers of the 2022 Bonds are encouraged to consult their tax advisors regarding the likelihood that such bills would be introduced or amended or enacted and the consequences of such enactment to the purchasers.

CONTINUING DISCLOSURE
The City will covenant in a Continuing Disclosure Agreement, dated the date of delivery of the 2022 Bonds (the “Continuing Disclosure Agreement”), by and between the City and The Bank of New York Mellon Trust Company, N.A., as dissemination agent (the “Dissemination Agent”) for the benefit of the holders and Beneficial Owners of the 2022 Bonds to provide certain financial information and operating data relating to the City by not later than April 1 following the end of the City’s Fiscal Year (currently its Fiscal Year ends on June 30) (the “Annual Report”), commencing on April 1, 2023 with the report for the Fiscal Year ended June 30, 2022, and to provide notices of the occurrence of certain enumerated events. The Annual Report and the notices of enumerated events will be filed by the City with EMMA, which is maintained on the Internet at http://emma.msrb.org/.

The specific nature of the information to be contained in the Annual Report and the notices of enumerated events is set forth in Appendix E. These covenants have been made in order to assist the Underwriter in complying with subsection (b)(5) of Rule 15c2-12 adopted by the Securities and Exchange Commission (the “Rule”).

The City has not failed to comply in all material respects with its continuing disclosure undertakings in the past five years. In order to ensure compliance with its continuing disclosure undertakings under the Rule in the future, the City has appointed the Dissemination Agent to coordinate, on behalf of the City, the preparation and filing of Annual Reports by the City.

FINANCIAL INTERESTS
The fees being paid to the Underwriter, Bond Counsel and Disclosure Counsel are contingent upon the issuance and delivery of the 2022 Bonds.

MISCELLANEOUS
Insofar as any statements made in this Official Statement involve matters of opinion or of estimates, whether or not expressly stated, they are set forth as such and not as representations of fact. No representation is made that any of such statements made will be realized. Neither this Official Statement nor any statement which may have been made verbally or in writing is to be construed as a contract with the Owners of the 2022 Bonds.

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

CITY OF VERNON
Resolution No. 2022-10

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By /s/ Carlos R. Fandino, Jr.

City Administrator
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APPENDIX A

FINANCIAL STATEMENTS
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APPENDIX B

SUMMARY OF CERTAIN PROVISIONS OF THE INDENTURE
This Appendix includes summaries of certain provisions of the Indenture, which are in addition and complementary to the summaries found under “INTRODUCTION,” “THE 2022 BONDS,” “PLAN OF FINANCE” and “SECURITY AND SOURCES OF PAYMENT” in the Official Statement. The following summaries are qualified in their entirety by reference to the Indenture, a copy of which can be obtained from the City.

The 2022 Bonds are issued under the Indenture, dated as of September 1, 2008, as amended and supplemented (the “Indenture”), including as supplemented by the Seventh Supplemental Indenture dated as of December 1, 2021 (the “Seventh Supplemental Indenture”). The Indenture, which is summarized under the caption “THE MASTER INDENTURE,” includes definitions of terms and other provisions specific to the 2022 Bonds and the provisions applicable to all of the Bonds. The terms of the Seventh Supplemental Indenture are summarized under the caption “THE SEVENTH SUPPLEMENTAL INDENTURE” below and include provisions specific to the 2022 Bonds.

MASTER INDENTURE

DEFINITIONS AND AUTHORITY
Definitions. Unless the context otherwise requires, the following terms, for all purposes of the Master Indenture and, unless otherwise provided therein with respect to such Supplemental Indenture or any Series of Bonds authorized by such Supplemental Indenture, any Supplemental Indenture, have the meanings set forth below:
“Accountant’s Certificate” means a certificate signed by an Independent Certified Public Accountant selected by the City.
“Accreted Value” means, with respect to any Capital Appreciation Obligation and as of any date, the Initial Amount thereof plus the interest accrued thereon from its delivery date, compounded at the approximate interest rate with respect to such Capital Appreciation Obligation specified in or pursuant to the Issuing Instrument authorizing the issuance of such Capital Appreciation Obligation on each date specified therein.

The applicable Accreted Value at any date will be the amount set forth in the Accreted Value Table as of such date, if such date is a compounding date, and if not, will be determined by straight-line interpolation with reference to such Accreted Value Table.
“Accreted Value Table” means, with respect to Capital Appreciation Obligations, the table denominated as such in, and to which reference is made in, the Issuing Instrument authorizing the issuance of such Capital Appreciation Obligations.
“Additional Bonds” means Bonds issued in accordance with the terms and conditions of the Indenture for the purposes set forth in the Indenture.
“Additional Parity Obligations” means Parity Obligations, including Additional Bonds, issued for the purposes set forth in the Indenture and satisfying the conditions set forth in the Indenture. “Adjusted Debt Service” means, for any period of time, the Debt Service for such period minus the sum of the amount of such Debt Service with respect to Outstanding Parity Obligations to be paid during such period from the proceeds of Parity Obligations, Subordinate Obligations or other funds as set forth in a certificate of the City.

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“Adjusted Net Revenues” means, with respect to a certificate to be delivered in connection with Additional Parity Obligations pursuant to the Indenture, for any Calculation Period, as calculated by the City or an Independent Engineer, the Adjusted Revenues for such Calculation Period less the Operation and Maintenance Expenses for such Calculation Period, plus at the option of the City, any or all of the following:
(i) an allowance for any estimated increase in Revenues from any additions or improvements to or extensions of the Electric System, made but not in service during the applicable Calculation Period or to be made with the proceeds of any Additional Parity Obligations with respect to which such certificate relates, with the proceeds of other Obligations theretofore issued by the City and available for such purpose or with other available funds of the City reserved by the City for such purpose, such allowance to be in an amount equal to the estimated additional average annual Net Revenues to be derived from such additions, improvements and extensions during the twelve month period after placing each such addition, improvement or extension in service, all as shown by a certificate of the City or an Independent Engineer; and (ii) an allowance for any increases in rates and charges for the Electric Service of the Electric System which have been approved by the City Council but which during all or any part of the applicable Calculation Period were not in effect, such allowance to be in an amount equal to 75% of the amount by which the Revenues for the applicable Calculation Period would have increased if such increase in rates and charges had been in effect for that portion of such Calculation Period during which such increase was not in effect.
“Adjusted Revenues” means, for any period of time, the Revenues for such period less the amount of such Revenues which have been deposited in the Expense Stabilization Fund during such period plus the amount of withdrawals during such period from the Expense Stabilization Fund. “Advance Refunded Municipal Securities” means any bonds or other obligations of any state of the United States of America or of any agency, instrumentality or local government unit of any such state:
(i) which are rated “Aaa” by Moody’s and “AAA” by S&P (provided, however, if the issue is only rated by S&P (i.e., there is no Moody’s rating), then the pre-refunded bonds must have been pre-refunded with cash, direct U.S. or U.S. guaranteed obligations, or “AAA” rated pre-refunded municipals to satisfy the foregoing condition); (ii) which are not callable prior to maturity or as to which irrevocable instructions have been given to the trustee, fiscal agent or other fiduciary for such bonds or other obligations by the obligor to give due notice of redemption and to call such bonds or other obligations for redemption on the date or dates specified in such instructions; (iii) which are secured as to principal and interest and redemption premium, if any, by a fund consisting only of cash or bonds or other obligations of the character described in clause (i) of the definition of Defeasance Securities which fund may be applied only to the payment of such principal of and interest and redemption premium, if any, on such bonds or other obligations on the maturity date or dates thereof or the redemption date or dates specified in the irrevocable instructions referred to in clause (ii) above, as appropriate; and (iv) as to which the principal of and interest on the bonds and obligations of the character described in clause (i) of the definition of Defeasance Securities which have been deposited in such fund, along with any cash on deposit in such fund, have been verified by an Accountant’s Certificate as being sufficient to pay principal of and interest and redemption premium, if any, on such bonds or other obligations on the maturity date or dates thereof or on the redemption date or dates specified in the irrevocable instructions referred to in clause (ii) above, as applicable.
“Aggregate Adjusted Annual Debt Service” means for any Fiscal Year the aggregate amount of Adjusted Debt Service on all Outstanding Parity Obligations payable in such Fiscal Year. For purposes of calculating Aggregate Adjusted Annual Debt Service, the determination of Debt Service on the Outstanding Parity Obligations coming due in each Fiscal Year will be subject to the Debt Service Adjustments and Assumptions.
“Applicable Parity Obligations” means, with respect to a certificate to be delivered in connection with Additional Parity Obligations pursuant to the Indenture and as of the date of such certificate, all of the Parity Obligations Outstanding on such date plus the Additional Parity Obligations proposed to be issued.

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“Authorized Denominations” means, with respect to Bonds of any Series, the denomination or denominations designated as such in the Supplemental Indenture authorizing such Bonds. “Authorized City Representative” means the City Administrator of the City, and any other officer of the City duly authorized to act as an Authorized City Representative for purposes of the Indenture by the City Council or written authorization of the City Administrator of the City. “Balloon Indebtedness” means, with respect to any Series of Obligations 25% or more of the principal of which matures on the same date or within a 12-month period (with Sinking Fund Installments on Term Obligations deemed to be payments of matured principal), that portion of such Series of Obligations which matures on such date or within such 12-month period. For purposes of the foregoing definition, the principal amount maturing on any date will be reduced by the amount of such indebtedness which is required, by the documents governing such indebtedness, to be amortized by prepayment or redemption prior to its stated maturity date.
“Beneficial Owner” means, with respect any Book-Entry Bond, the beneficial owner of such Bond as determined in accordance with the applicable rules of the Securities Depository for such Book-Entry Bonds. “Bond” means any of the City of Vernon Electric System Revenue Bonds authorized pursuant to the Indenture and a Supplemental Indenture.
“Bond Counsel” means an attorney or firm of attorneys of recognized national standing in the field of law relating to municipal securities and to exclusion of interest thereon from income for federal income tax purposes selected by the City.
“Bond Debt Service” means, for any period of time, the sum of: (i) the interest payable during such period on all Outstanding Bonds, assuming that all Outstanding Bonds which are Serial Obligations are retired as scheduled and that all Outstanding Bonds which are Term Obligations are redeemed or paid from Sinking Fund Installments as scheduled; (ii) that portion of the principal amount of all Outstanding Bonds which are Serial Obligations maturing on each principal payment date during such period, including the Final Compounded Amount of any Bonds which are Capital Appreciation Obligations and Serial Obligations; and (iii) that portion of the principal amount of all Outstanding Bonds which are Term Obligations required to be redeemed or paid from Sinking Fund Installments during such period (together with the redemption premiums, if any, thereon).
“Bond Ordinance” means the City of Vernon Municipal Facilities Revenue Bond Law, enacted as Ordinance No. 1004 of the City (codified as Article XI of the City Code of the City of Vernon). “Bond Register” means the registration books for the ownership of Bonds maintained by the Trustee pursuant to the Indenture.
“Bondowner” or “Owner” means, with respect to a Bond, the registered owner of such Bond as set forth in the Bond Register.
“Book-Entry Bonds” means Bonds registered in the name of a nominee of DTC or any successor Securities Depository for the Bonds, or a nominee thereof, as the registered owner thereof pursuant to the terms and provisions of the Indenture.
“Budget” means, as of any date, the budget for the Electric System prepared by the City pursuant to the Indenture in effect as of such date.
“Business Day” means, with respect to each Series of Bonds, unless otherwise provided with respect to a Series of Bonds in the Supplemental Indenture authorizing the issuance of such Series, any day of the year Resolution No. 2022-10

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other than: (i) a Saturday; (ii) a Sunday; (iii) any day which is in Los Angeles, California or New York, New York a legal holiday or a day on which banking institutions are authorized or required by law or other government action to close; and (iv) any day on which the banks are authorized or required by law or other government action to close in the State of New York or State of California or any city in which the Principal Office of any Paying Agent or any Credit Provider for such Series of Bonds is located. “Calculation Period” means, with respect to any certificate to be provided pursuant to the Indenture, any twelve consecutive month period within the eighteen consecutive months ending immediately prior to the issuance of the Additional Parity Obligations to which such certificate relates. “Capital Appreciation Obligations” mean any Obligations the interest on which is compounded and not scheduled to be paid until the maturity or prior redemption of such Obligations. “Capital Improvement” means, to the extent chargeable to a capital account of the Electric System, or otherwise eligible for amortization, under Generally Accepted Accounting Principles any land, improvement, facility, equipment and other property of any nature whatsoever which is used in the Electric System including but not limited to: (i) any addition, betterment, replacement, renewal, extension or improvement of or to the Electric System, including, without limitation, capacity rights in electric generation resources, rights to the transmission capability of electric transmission resources, acquisition of emission credits or other environmental assets for facilities of the Electric System, land or any interests therein; and (ii) capital costs for the extension, reinforcement, enlargement or other improvement of facilities or property, or the acquisition of interests therein, not included as part of the Electric System, determined by the City to be necessary or convenient in connection with the utilization of the Electric System. “Charter” means the Charter of the City of Vernon.
“City” means the City of Vernon, California and its successors. “City Administrative Code” means the Code of the City of Vernon. “City Council” means the City Council of the City established pursuant to the Charter. “Code” means the Internal Revenue Code of 1986, as amended from time to time. Each reference to a section of the Code in the Indenture will be deemed to include the applicable United States Treasury Regulations thereunder and also includes all amendments and successor provisions unless the context clearly requires otherwise.
“Collateral Requirement” means, with respect to a Qualified Swap Agreement, that such Qualified Swap Agreement includes provisions to the effect that: (i) if the counterparty’s (or, if applicable, the counterparty’s guarantor’s) ratings fall below “Aa” by Moody’s or “AA” by S&P, or are suspended or withdrawn, the counterparty will provide collateral in the form of cash or Defeasance Securities, or a combination thereof; (ii) the collateral is to be held by the City or a third party custodian acceptable to the City; (iii) the City has a perfected security interest in the collateral; (iv) the amount of the collateral is at least equal to 100% of the amount, if any, that the counterparty would be obligated to pay the City in the event of the early termination of the transactions under the Qualified Swap Agreement; (v) there may be deducted from the amount of the collateral a threshold amount of not more than $1,000,000, except that if the counterparty’s (or, if applicable, the counterparty’s guarantor’s) ratings fall below “A” by Moody’s or “A” by S&P, or are suspended or withdrawn, the threshold amount will be zero; and (vi) the amount of the required collateral and the value of the collateral posted will be valued no less frequently than monthly. “Commercial Paper Program” means a program of short-term Obligations having the characteristics of commercial paper in that such Obligations have a stated maturity not later than 270 days from their date of Resolution No. 2022-10

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issue and that maturing Obligations of such program may be paid with the proceeds of renewal short-term Obligations.
“Cost” means, with respect to any Capital Improvement, to the extent permitted under the Bond Ordinance, all costs and expenses of planning, designing, acquiring, constructing, installing and financing such Capital Improvement, placing such Capital Improvement in operation, disposal of such Capital Improvement, and obtaining governmental approvals, certificates, permits and licenses with respect to the applicable Capital Improvement paid or incurred by the City. Payment of Cost does include the reimbursement to the City for any of the costs included in the definition of Cost paid by the City and not previously reimbursed to the City and which are not to be reimbursed from contributions in aid of construction. The term Cost includes, but is not limited to: (i) costs of preliminary investigation and development, the performance or acquisition of feasibility and planning studies, and the securing of regulatory approvals, as well as costs for land and land rights, engineering and contractors’ fees, labor, materials, equipment, utility services and supplies, legal fees and financing expenses; (ii) working capital and reserves therefor in such amounts as determined by the City; (iii) interest accruing in whole or in part on Parity Obligations prior to and during the acquisition, construction and installation of a Capital Improvement, or any portion thereof, and for such additional period as the City may determine; (iv) the deposit or deposits from the proceeds of the Bonds in any funds or accounts required by the Indenture or any Supplemental Indenture; (v) the payment of principal, premium, if any, and interest when due (whether at the maturity of principal or at the due date of interest or upon redemption or otherwise) of any note or other evidence of indebtedness the proceeds of which were applied to any of the costs of the applicable Capital Improvement described in the definition of Cost; (vi) training and testing costs which are properly allocable to the acquisition, placing in operation, or construction of a Capital Improvement; (vii) all costs of insurance applicable to the period of the acquisition, construction, installation and placing the Capital Improvement in operation; (viii) all costs relating to injury and damage claims arising out of the acquisition, construction, installation and placing the Capital Improvement in operation less proceeds of insurance; (ix) legally required or permitted federal, state and local taxes and payments in lieu of taxes applicable to the acquisition, construction, installation and placing the Capital Improvement in operation, or any portion thereof; (x) amounts due the United States of America as rebate of investment earnings with respect to the proceeds of Parity Obligations the proceeds of which were applied, in whole or in part, to the Capital Improvement or as penalties in lieu thereof; (xi) amounts payable with respect to capital costs for the expansion, reinforcement, enlargement or other improvement of facilities, whether or not such facilities constitute a part of the Electric System, determined by the City to be necessary in connection with the utilization of the applicable Capital Improvement and the costs associated with the removal from service or reductions in service of any facilities as a result of the expansion, reinforcement, enlargement or other improvement of such facilities or the acquisition, construction, installation or placing in service of the Capital Improvement; (xii) Costs of Issuance of any Parity Obligations the proceeds of which were applied, in whole or in part, to the Capital Improvement; (xiii) fees and expenses pursuant to any lending or credit facility or agreement applicable to the period of the acquisition, construction, installation and placing in operation the Capital Improvement; and (xiv) to the extent chargeable to a capital account of the Electric System under Generally Accepted Accounting Principles, all other costs incurred by the City, properly allocable to the acquisition, construction, or installation of the Capital Improvement, or any portion thereof, or the placing of the Capital Improvement or any portion thereof in operation.
“Costs of Issuance” means, to the extent permitted by the Bond Ordinance, all items of expense directly or indirectly payable by or reimbursable to the City and related to the original authorization, execution, sale and delivery of Parity Obligations, including but not limited to advertising and printing costs, costs of preparation and reproduction of documents, including disclosure documents and documents relating to the sale of such Parity Obligations, initial fees and charges (including counsel fees) of any fiscal agent, any paying agent and any Credit Provider, legal fees and charges, financial advisor fees and expenses, fees and expenses of other consultants and professionals, rating agency fees, fees and charges for preparation, execution, transportation and safekeeping of Parity Obligations and any other cost, charge or fee in connection with the authorization, issuance, sale or original delivery of Parity Obligations.

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“Credit Provider” means any municipal bond insurance company, bank or other financial institution or organization which is performing in all material respects its obligations under any Credit Support Instrument for some or all of the Parity Obligations.
“Credit Provider Bonds” means any Bonds paid as to principal, Redemption Price, Purchase Price and/or interest with funds provided under a Credit Support Instrument for so long as such Bonds are held by or for the account of, or are pledged to, the applicable Credit Provider or any assignee thereof in accordance with the applicable Credit Support Agreement.
“Credit Provider Reimbursement Obligations” means obligations of the City to pay from the Net Revenues and amounts in the Light and Power Fund (other than the Operating Reserve) available for such payment in accordance with the Indenture amounts due under a Credit Support Agreement, including without limitation amounts advanced by a Credit Provider pursuant to a Credit Support Instrument as credit support or liquidity for Parity Obligations and the interest with respect thereto. “Credit Support Agreement” means, with respect to any Credit Support Instrument, the agreement or agreements (which may be the Credit Support Instrument itself) between the City and the applicable Credit Provider, as originally executed or as it may from time to time be replaced, supplemented or amended in accordance with the provisions thereof, providing for the reimbursement to the Credit Provider for payments under such Credit Support Instrument or for extensions of credit made to the City by the Credit Provider, and the interest thereon, and includes any subsequent agreement pursuant to which a substitute Credit Support Instrument is provided, together with any related pledge agreement, security agreement or other security document.
“Credit Support Instrument” means a policy of insurance, a letter of credit, a stand-by purchase agreement, revolving credit agreement or other credit arrangement pursuant to which a Credit Provider provides credit and/or liquidity support with respect to the payment of interest, principal, Redemption Price or Purchase Price of any Parity Obligations but does not include a Reserve Financial Guaranty. “Debt Service” means, for any period of time, the sum of: (i) the interest payable during such period on all Outstanding Parity Obligations, assuming that all Outstanding Serial Parity Obligations are retired as scheduled and that all Outstanding Term Parity Obligations are redeemed or paid from Sinking Fund Installments as scheduled; (ii) that portion of the principal amount of all Outstanding Serial Parity Obligations maturing on each principal payment date during such period, including the Final Compounded Amount of any Capital Appreciation Obligations; and (iii) that portion of the principal amount of all Outstanding Term Parity Obligations required to be redeemed or paid from Sinking Fund Installments becoming due during such period (together with the premiums, if any, thereon).
“Debt Service Adjustments and Assumptions” means, for purposes of determining Aggregate Adjusted Annual Debt Service and Maximum Adjusted Annual Debt Service, the following adjustments and assumptions to be made with respect to Debt Service: (i) in determining the amount of Debt Service constituting principal due in each Fiscal Year, principal payments with respect to Parity Obligations which are or upon issuance will be, part of a Commercial Paper Program, but which would not constitute Balloon Indebtedness, will be treated as if such Parity Obligations were to be amortized with substantially level annual Debt Service payments over a term of 40 years commencing on the date the calculation of Aggregate Adjusted Annual Debt Service or Maximum Adjusted Annual Debt Service is made; (ii) if all or any portion or portions of the Parity Obligations constitute, or upon issuance would constitute, Balloon Indebtedness, then, for purposes of determining Aggregate Adjusted Annual Debt Service and Maximum Adjusted Annual Debt Service, each maturity which constitutes, or upon issuance would constitute, Balloon Indebtedness will be treated as if it were to be amortized with substantially level annual Debt Service payments over a term of 40 years commencing on the date which is the first anniversary of the initial issuance of such Parity Obligations; (iii) if any Outstanding Parity Obligations constitute Tax-Exempt Variable Rate Indebtedness (except to the extent clause (vii) applies), the interest rate on such Parity Obligations for any period as to which such interest Resolution No. 2022-10

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rate has not been established will be assumed to be the ten year historical average of the SIFMA Index ending with the week preceding the date of calculation; (iv) if any Outstanding Parity Obligations constitute Variable Rate Indebtedness which is not Tax-Exempt (except to the extent clause (vii) applies), the interest rate on such Parity Obligations for any period as to which such interest rate has not been established will be assumed to be the ten year historical average of the One Month USD LIBOR Rate ending with the month preceding the date the calculation of Aggregate Adjusted Annual Debt Service or Maximum Adjusted Annual Debt Service is made or if the One Month USD LIBOR Rate is not available for such period, another similar rate or index selected by the City; (v) if the Parity Obligations proposed to be issued will be Tax-Exempt Variable Rate Indebtedness (except to the extent clause (viii) applies), then the interest rate on such Parity Obligations will be assumed to be the ten year historical average of the SIFMA Index ending with the week preceding the date the calculation of Aggregate Adjusted Annual Debt Service or Maximum Adjusted Annual Debt Service is made; (vi) if the Parity Obligations proposed to be issued will be Variable Rate Indebtedness which is not TaxExempt (except to the extent clause (viii) applies) then the interest rate on such Parity Obligations will be assumed to be the ten year historical average of the One Month USD LIBOR Rate ending with the month preceding the date the calculation is made, or if the One Month USD LIBOR Rate is not available for such period, another similar rate or index selected by the City; (vii) if a Qualified Swap Agreement has been entered into in connection with any Outstanding Parity Obligations, the interest rate on such Outstanding Parity Obligations for each Fiscal Year or portion thereof during which payments are to be exchanged by the parties under such Qualified Swap Agreement will be determined for purposes of calculating Aggregate Adjusted Annual Debt Service and Maximum Adjusted Annual Debt Service by adding: (1) the amount of Debt Service paid or to be paid by the City as interest on the Outstanding Parity Obligations during such Fiscal Year or portion thereof (determined as provided in clauses (iii) or (iv), as applicable, if such Outstanding Parity Obligations constitute Variable Rate Indebtedness); and (2) the net amount (which may be a negative amount) paid or to be paid by the City under the Qualified Swap Agreement (after giving effect to payments made and received, and to be made and received, by the City under the Qualified Swap Agreement) during such Fiscal Year or portion thereof, and for such purpose any variable rate of interest agreed to be paid under the Qualified Swap Agreement will be deemed to be the rate at which the related Outstanding Parity Obligations constituting Variable Rate Indebtedness is assumed to bear interest; (viii) if a Qualified Swap Agreement has been entered into, or upon issuance of such Parity Obligation will be entered into, by the City with respect to any Parity Obligations proposed to be issued, the interest on such proposed Parity Obligations for each Fiscal Year or portion thereof during which payments are to be exchanged under the Qualified Swap Agreement will be determined for purposes of calculating Aggregate Adjusted Annual Debt Service and Maximum Adjusted Annual Debt Service by adding: (1) the amount of Debt Service to be paid by the City as interest on such Parity Obligations during such Fiscal Year or portion thereof (determined as provided in clauses (v) or (vi), as applicable, if such Parity Obligations are to constitute Variable Rate Indebtedness); and (2) the net amount (which may be a negative amount) to be paid by the City under the Qualified Swap Agreement (after giving effect to payments to be made and received by the City under the Qualified Swap Agreement) during such Fiscal Year or portion thereof, and for such purpose any variable rate of interest agreed to be paid under the Qualified Swap Agreement will be deemed to be the rate at which the related Parity Obligations which are to constitute Variable Rate Indebtedness will be assumed to bear interest; and (ix) if any of the Parity Obligations are, or upon issuance will be, Paired Obligations, the interest thereon will be the resulting linked rate or effective fixed rate to be paid with respect to such Paired Obligations. “Debt Service Fund” means the City of Vernon Electric System Debt Service Fund established pursuant to the Indenture.
“Debt Service Reserve Fund” means the City of Vernon Electric System Debt Service Reserve Fund established pursuant to the Indenture.
“Debt Service Reserve Requirement” means, as of any date of calculation, an amount equal to the least of: (i) 10% of the initial offering price to the public of the Bonds as determined under the Code; or (ii) the greatest amount of Bond Debt Service in any Fiscal Year during the period commencing with the Fiscal Year in which the determination is being made and terminating with the last Fiscal Year in which any Bond is due; Resolution No. 2022-10