$92,130,000. Revenue Refunding Bonds, Series 2012-A (Electric Distribution System Refunding)

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1 NEW ISSUE BOOK-ENTRY ONLY CREDIT RATINGS S&P: AAFitch: AA(See CREDIT RATINGS herein) In the opinion of Fulbright & Jaworski L.L.P., Los Angeles, California, Bond Counsel, under existing law interest on the Bonds is exempt from personal income taxes of the State of California and, assuming compliance with the tax covenants described herein, interest on the Bonds is excluded pursuant to section 103(a) of the Internal Revenue Code of 1986 from the gross income of the owners thereof for federal income tax purposes and is not an item of tax preference for purposes of the federal alternative minimum tax. See, however, TAX EXEMPTION herein regarding certain other tax considerations. $92,130,000 Anaheim Public Financing Authority Revenue Refunding Bonds, Series 2012-A (Electric Distribution System Refunding) Dated: Date of Delivery Due: October 1, as set forth on the inside front cover The Anaheim Public Financing Authority (the Authority ) is issuing its Revenue Refunding Bonds, Series 2012-A (Electric Distribution System Refunding) (the Bonds ) (i) to refund, together with other available funds, all of its outstanding Revenue Bonds, Series 2002-A (City of Anaheim Electric System Distribution Facilities); (ii) to fund a Debt Service Reserve Fund for the Bonds; and (iii) to pay costs of issuance. See PLAN OF REFUNDING and ESTIMATED SOURCES AND USES OF FUNDS herein. Capitalized terms used on this cover page and not otherwise defined shall have the meanings set forth herein. The Bonds will be issued pursuant to an Indenture of Trust, dated as of September 1, 2012, by and among the Authority, the City of Anaheim, California (the City ) and The Bank of New York Mellon Trust Company, N.A., as trustee. Interest on the Bonds is payable on April 1 and October 1 of each year, commencing April 1, The Bonds are special, limited obligations of the Authority, payable solely from Project Revenues which consist primarily of purchase payments (the Purchase Payments ) to be made by the City under an Installment Purchase Agreement, dated as of September 1, 2012 (the Installment Purchase Agreement ), between the Authority and the City, and other sources described herein. Pursuant to the Installment Purchase Agreement, the City s obligation to make Purchase Payments is payable from and secured by Surplus Revenues of the City s Electric System in the Qualified Obligations Account of the Surplus Revenue Fund until the date that certain operating and financial criteria with respect to the City s Distribution System are met as described herein (the Crossover Date ) and thereafter from Distribution System Net Revenues in the Distribution System Debt Service Fund, all as defined herein. See SECURITY AND SOURCES OF PAYMENT FOR THE BONDS herein. Until the Crossover Date, the Purchase Payments are payable from Surplus Revenues on a parity with each other and the City s purchase payments in connection with other Qualified Obligations, currently outstanding in the aggregate principal amount of $587,795,000 (of which $96,210,000 in aggregate principal amount will be refunded with proceeds of the Bonds), and any other Qualified Obligations payable on a parity therewith that may hereafter be incurred by the City. The Purchase Payments and the purchase payments relating to such parity Qualified Obligations are payable from the net revenues of the Electric System on a basis junior and subordinate to (i) any voter-approved electric revenue bonds, notes or other evidences of indebtedness of the City that may be issued in the future pursuant to the City Charter ( Senior Bonds ) and (ii) maintenance and operation expenses of the Electric System, including the City s take-or-pay obligations with respect to certain joint powers agency contracts. There are no Senior Bonds currently authorized or outstanding. The City has no ability to issue Senior Bonds (other than bonds issued to refund any Senior Bonds) without authorization by the electorate of the City. See SECURITY AND SOURCES OF PAYMENT FOR THE BONDS herein. The Bonds are being issued as fully registered bonds without coupons, registered in the name of Cede & Co., as nominee for The Depository Trust Company ( DTC ). DTC will act as Securities Depository for the Bonds. Purchases of beneficial ownership interests in the Bonds will be made in book-entry form only. Purchasers ( Beneficial Owners ) of Bonds will not receive physical certificates representing their ownership interests. So long as Cede & Co. is the registered owner of the Bonds, references herein to Bondholders or registered owners shall mean Cede & Co. and shall not mean the Beneficial Owners of the Bonds. See DESCRIPTION OF THE BONDS General and APPENDIX E BOOKENTRY ONLY SYSTEM herein. The Bonds are subject to optional, mandatory and extraordinary redemption prior to maturity as described herein. See DESCRIPTION OF THE BONDS herein. THE OBLIGATION OF THE CITY TO MAKE PURCHASE PAYMENTS UNDER THE INSTALLMENT PURCHASE AGREEMENT IS PAYABLE SOLELY FROM SURPLUS REVENUES IN THE QUALIFIED OBLIGATIONS ACCOUNT UNTIL THE CROSSOVER DATE, IF AND WHEN IT OCCURS, AND THEREAFTER SOLELY FROM DISTRIBUTION SYSTEM NET REVENUES, UNLESS OTHERWISE PAID FROM OTHER SOURCES OF LEGALLY AVAILABLE FUNDS. THE BONDS SHALL NOT IN ANY WAY BE CONSTRUED AS A DEBT OF THE CITY, THE STATE OF CALIFORNIA OR ANY POLITICAL SUBDIVISION THEREOF IN CONTRAVENTION OF ANY CONSTITUTIONAL OR STATUTORY DEBT LIMITATION, NOR SHALL ANYTHING CONTAINED IN THE INSTALLMENT PURCHASE AGREEMENT OR THE INDENTURE BE CONSTRUED AS A PLEDGE OF GENERAL REVENUES, FUNDS OR MONEYS OF THE CITY OR THE AUTHORITY OR AN OBLIGATION OF THE CITY FOR WHICH THE CITY IS OBLIGATED TO LEVY OR PLEDGE ANY FORM OF TAXATION OR FOR WHICH THE CITY HAS LEVIED OR PLEDGED ANY FORM OF TAXATION. THE AUTHORITY HAS NO TAXING POWER. This cover page contains certain information for general reference only. It is not intended to be a summary of the security or terms of this issue. Investors are advised to read the entire Official Statement to obtain information essential to making an informed investment decision. The Bonds are offered by the Underwriters when, as and if issued, subject to approval of legality by Fulbright & Jaworski L.L.P., Los Angeles, California, Bond Counsel. Certain legal matters will be passed upon for the Authority and the City by the City Attorney, and for the Underwriters by Stradling Yocca Carlson & Rauth, a Professional Corporation, Newport Beach, California, Underwriters Counsel. It is expected that the Bonds in definitive form will be available for delivery through the facilities of the DTC book-entry system on or about September 19, Citigroup The date of this Official Statement is September 6, De La Rosa & Co.

2 Maturity Date (October 1) MATURITY SCHEDULE $92,130,000 Serial Bonds Principal Amount Interest Rate Yield 2021 $ 1,455, % 2.060% QW ,205, QX ,015, * QY ,210, * QZ ,470, * RA ,750, * RB ,695, * RC ,025, RD ,800, * RE ,425, * RF ,080, * RG4 CUSIP (03255M) CUSIP is a registered trademark of the American Bankers Association. CUSIP data herein is provided by CUSIP Global Services, managed by Standard & Poor s Financial Services LLC on behalf of The American Bankers Association. This data is not intended to create a database and does not serve in any way as a substitute for the CUSIP Services. None of the Authority, the City or the Underwriters is responsible for the selection or correctness of the CUSIP numbers set forth herein. * Yield to the optional redemption date of October 1, 2022 at par.

3 ANAHEIM PUBLIC FINANCING AUTHORITY MEMBERS OF THE AUTHORITY BOARD AND THE CITY COUNCIL Harry Sidhu, Vice Chairman of the Authority and Mayor Pro Tem Lorri Galloway, Authority Board and Council Member David M. Morgan, Vice Chairperson Pat Carroll, Member Susan Faessel, Member Tom Tait Chairman of the Authority and Mayor Gail E. Eastman, Authority Board and Council Member Kristine Murray, Authority Board and Council Member CITY PUBLIC UTILITIES BOARD Jordan Brandman Chairperson Bob Hernandez, Member John Machiaverna, Member Charles Peltzer, Member OFFICIALS OF THE AUTHORITY AND THE CITY Bob Wingenroth, Authority Executive Director and City Manager Deborah A. Moreno, Authority Financial Advisor and City Finance Director Cristina L. Talley, Authority Counsel and City Attorney Linda N. Andal, Authority Secretary and City Clerk Henry W. Stern, Authority Treasurer and City Treasurer CITY PUBLIC UTILITIES DEPARTMENT Marcie L. Edwards, General Manager Edward P. Zacherl, Assistant General Manager Finance & Administration Dukku Lee, Assistant General Manager Electric Services Donald C. Calkins, Assistant General Manager Water Services Stephen J. Sciortino, Assistant General Manager Joint Services BOND COUNSEL AND DISCLOSURE COUNSEL Fulbright & Jaworski L.L.P. Los Angeles, California FINANCIAL ADVISOR Public Financial Management, Inc. Los Angeles, California TRUSTEE The Bank of New York Mellon Trust Company, N.A. Los Angeles, California VERIFICATION AGENT The Arbitrage Group, Inc. Houston, Texas

4 No dealer, broker, salesperson or other person has been authorized by the Authority, the City or the City s Public Utilities Department (the Department ) to give any information or to make any representations, other than as contained in this Official Statement, and if given or made, such other information or representations must not be relied upon as having been authorized by the Authority, the City or the Department. This Official Statement does not constitute an offer to sell or the solicitation of an offer to buy, nor shall there be any sale of, the Bonds by any person in any jurisdiction in which it is unlawful for such person to make such offer, solicitation or sale. This Official Statement is not to be construed as a contract with the purchasers of the Bonds. Statements contained in this Official Statement which involve estimates, forecasts, or matters of opinion, whether or not expressly so described herein, are intended solely as such and are not to be construed as representation of facts. The Underwriters have provided the following sentence for inclusion in this Official Statement. The Underwriters have reviewed the information in this Official Statement in accordance with, and as part of, their respective responsibilities to investors under the federal securities laws as applied to the facts and circumstances of this transaction, but the Underwriters do not guarantee the accuracy or completeness of such information. The information set forth herein has been obtained from official sources and other sources which are believed to be reliable, but is not guaranteed as to accuracy or completeness, and is not to be construed as a representation by the Authority, the City or the Department. The information and expressions of opinion contained herein are subject to change without notice and neither the delivery of this Official Statement nor any sale made hereunder shall, under any circumstances, create any implication that there has been no change in the affairs of the Authority, the City or the Department since the date hereof. This Official Statement is submitted with respect to the sale of the Bonds referred to herein and may not be reproduced or used, in whole or in part, for any other purpose, unless authorized in writing by the Authority, the City and the Department. All summaries of the documents and laws are made subject to the provisions thereof and do not purport to be complete statements of any or all such provisions. This Official Statement, including any supplement or amendment hereto, is intended to be deposited with one or more repositories. Certain statements included or incorporated by reference in this Official Statement constitute forwardlooking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. Such statements are generally identifiable by the terminology used such as plan, project, expect, anticipate, intend, believe, estimate, budget or other similar words. The achievement of certain results or other expectations contained in such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements described to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Except as specifically set forth herein, the City does not plan to issue any updates or revisions to those forward-looking statements if or when its expectations or events, conditions or circumstances on which such statements are based occur. IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVERALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE BONDS AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.

5 TABLE OF CONTENTS Page INTRODUCTION... 1 Purpose of the Bonds... 1 Other Information and Definitions... 1 DESCRIPTION OF THE BONDS... 2 General... 2 Redemption of the Bonds... 2 Redemption Procedures... 3 Transfer and Exchange of the Bonds... 3 SECURITY AND SOURCES OF PAYMENT FOR THE BONDS... 4 Purchase Payments... 4 Electric System Flow of Funds... 5 Electric System Funds and Accounts... 5 Electric System Surplus Revenues... 6 Crossover Date... 8 Distribution System Flow of Funds... 9 Distribution System Funds and Accounts... 9 Distribution System Surplus Revenues Rate Covenants Debt Service Reserve Fund Insurance Additional Qualified Obligations Additional Distribution System Parity Obligations Take-or-Pay Obligations Limited Recourse on Default PLAN OF REFUNDING ESTIMATED SOURCES AND USES OF FUNDS DEBT SERVICE SCHEDULE CONSTITUTIONAL AND CHARTER LIMITATIONS Constitutional Limitations on Governmental Spending Proposition Proposition Future Initiatives City Charter Revenue Bond Limitations THE ELECTRIC SYSTEM History of the Electric System Principal Facilities Customers and Energy Sales Electric Rates and Charges Cost of Power and Non-Firm Power Capital Improvements Plan City-Owned Resources Non-City Owned Resources Anaheim s CAISO Arrangements Historical Financial Results Accounting Policies Joint Powers Agency Contracts Labor Relations Retirement Programs i

6 TABLE OF CONTENTS (continued) Page DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS State Legislation Future Regulation Impact of Developments on the City OTHER FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY Federal Energy Legislation CAISO FERC Filings Environmental Issues Other Factors THE CITY S PUBLIC UTILITIES DEPARTMENT General Description Management of the Public Utilities Department Public Utilities Board THE AUTHORITY LITIGATION CREDIT RATINGS TAX EXEMPTION CERTAIN LEGAL MATTERS FINANCIAL STATEMENTS FINANCIAL ADVISOR VERIFICATION OF MATHEMATICAL COMPUTATIONS UNDERWRITING CONTINUING DISCLOSURE MISCELLANEOUS APPENDIX A CITY OF ANAHEIM ELECTRIC UTILITY FUND AUDITED FINANCIAL STATEMENTS FISCAL YEARS ENDED JUNE 30, 2011 AND JUNE 30, A-1 APPENDIX B GENERAL INFORMATION REGARDING THE CITY... B-1 APPENDIX C SUMMARY OF PRINCIPAL LEGAL DOCUMENTS... C-1 APPENDIX D FORM OF CONTINUING DISCLOSURE AGREEMENT... D-1 APPENDIX E BOOK-ENTRY ONLY SYSTEM... E-1 APPENDIX F FORM OF OPINION OF BOND COUNSEL... F-1 ii

7 OFFICIAL STATEMENT $92,130,000 Anaheim Public Financing Authority Revenue Refunding Bonds, Series 2012-A (Electric Distribution System Refunding) INTRODUCTION This Official Statement, which includes the cover page and attached appendices, provides certain information in connection with the issuance and sale of $92,130,000 in aggregate principal amount of the Anaheim Public Financing Authority Revenue Refunding Bonds, Series 2012-A (Electric Distribution System Refunding) (the Bonds ). This Introduction is not a summary of this Official Statement, and is qualified by more complete and detailed information contained in the entire Official Statement. A full review should be made of the entire Official Statement, including the cover page and attached appendices. The offering of Bonds to potential investors is made only by means of the entire Official Statement. The Bonds will be issued pursuant to an Indenture of Trust, dated as of September 1, 2012 (the Indenture ), by and among the Anaheim Public Financing Authority (the Authority ), the City of Anaheim, California (the City or Anaheim ) and The Bank of New York Mellon Trust Company, N.A., as trustee (the Trustee ). The Bonds will be special, limited obligations of the Authority, payable solely from Project Revenues which consist primarily of purchase payments (the Purchase Payments ) to be made by the City pursuant to an Installment Purchase Agreement, dated as of September 1, 2012 (the Installment Purchase Agreement ), by and between the Authority and the City, and other sources described herein. Purpose of the Bonds The Authority will use proceeds of the Bonds (i) to refund, together with certain other available funds, all of its outstanding Revenue Bonds, Series 2002-A (City of Anaheim Electric System Distribution Facilities); (ii) to fund a Debt Service Reserve Fund in an amount sufficient to satisfy the Reserve Requirement (as defined herein); and (iii) to pay costs of issuance. See PLAN OF REFUNDING and ESTIMATED SOURCES AND USES OF FUNDS herein. Other Information and Definitions This Official Statement includes brief descriptions of the Bonds and the City s electric system (the Electric System ), and summaries of the Indenture, the Installment Purchase Agreement, certain provisions of the Charter and other agreements for the supply of power and energy and the collection of revenues for the payment of the Bonds and other indebtedness related to the Electric System. The summaries of and references to all documents, statutes, reports and other instruments referred to herein do not purport to be complete, comprehensive or definite, and each such summary and reference is qualified in its entirety by reference to each such document, statute, report or instrument. Forward looking statements in this Official Statement are subject to risks and uncertainties, including particularly those relating to the cost and availability of coal, nuclear fuel and natural gas, wholesale and retail electric energy and capacity prices, federal and State legislation and regulations, competition and industry restructuring, and the economy of the Electric System s service area. Terms capitalized but not defined herein have the meanings set forth in the Indenture or the Installment Purchase Agreement. See APPENDIX C SUMMARY OF PRINCIPAL LEGAL DOCUMENTS Definitions for the Indenture and Definitions for the Installment Purchase Agreement. For the definition of Crossover Date see SECURITY AND SOURCES OF PAYMENT FOR THE BONDS Crossover Date herein. 1

8 DESCRIPTION OF THE BONDS General The Bonds will be issued in the form of fully registered bonds without coupons and in Authorized Denominations of $5,000 and any integral multiple thereof. The Bonds will be dated the date of delivery and will bear interest at the rates per annum and will mature, subject to redemption provisions set forth below, on the dates and in the principal amounts, all as set forth on the inside cover page hereof. Interest on the Bonds will be payable on April 1 and October 1 of each year, commencing April 1, 2013 (the Interest Payment Dates ). Interest on the Bonds will be computed on the basis of a 360-day year consisting of twelve 30-day months. The Bonds will be registered in the name of Cede & Co., as initial nominee of The Depository Trust Company, New York, New York ( DTC ). DTC will act as Securities Depository for the Bonds. Ownership interests in the Bonds may be purchased in book-entry form only, in the denominations hereinabove set forth. In the event (i) DTC determines not to continue to act as Securities Depository for the Bonds, or (ii) the Authority determines that continuation of the book-entry system is not in the best interest of the Owners, then the Authority will discontinue the book-entry system with DTC. The Authority may replace DTC with another qualified Securities Depository. If the Authority fails to identify another qualified Securities Depository to replace DTC, then the Bonds will be registered in whatever name or names the Owners transferring or exchanging such Bonds shall designate, in accordance with the provisions of the Bonds. See APPENDIX E BOOK-ENTRY ONLY SYSTEM. Principal of, premium, if any, and interest on the Bonds will be paid by the Trustee. Principal is payable upon presentation of such Bonds by the Owners thereof. Interest on the Bonds will be payable on each Interest Payment Date by the Trustee by check mailed on the date on which interest is due to the Owners of the Bonds at the close of business on the fifteenth calendar day of the month preceding such Interest Payment Date at the addresses of Owners as they appear on the registration books maintained by the Trustee; provided that for Owners of more than $1,000,000 in principal amount of Bonds who, prior to the fifteenth calendar day of the month preceding any Interest Payment Date, have provided the Trustee with wire transfer instructions, interest payable on such Bonds will be paid in accordance with the wire transfer instructions provided by such Owners. Notwithstanding the foregoing, so long as records of ownership of the Bonds are maintained through the DTC book-entry system described above, all payments to the Beneficial Owners of the Bonds will be made in accordance with the procedures described in Appendix E hereto. Redemption of the Bonds Optional Redemption. The Bonds maturing on or after October 1, 2023 are subject to redemption at the option of the Authority in whole or in part in integral multiples of $5,000, on any date on or after October 1, 2022, from any source of funds, upon notice as provided in the Indenture, at a price equal to the principal amount to be redeemed, plus accrued but unpaid interest to the Redemption Date, without premium. Extraordinary Redemption. The Bonds are subject to redemption prior to maturity, at the option of the Authority, in whole or in part on any date, at the principal amount of such Bonds to be redeemed, without premium, plus accrued but unpaid interest to the Redemption Date, (i) from the net proceeds of insurance received by the Authority in the event of damage to or destruction of the Distribution System or, prior to the Crossover Date, the Electric System, if the Authority determines, in accordance with the Installment Purchase Agreement, not to apply such proceeds of insurance to the Distribution System or, prior to the Crossover Date, the Electric System, and/or (ii) from the net proceeds of any condemnation award or proceeds received in lieu of condemnation if the Authority determines, in accordance with the Installment Purchase Agreement, not to apply such proceeds to the Distribution System or, prior to the Crossover Date, the Electric System. 2

9 Redemption Procedures Notice of Redemption. The Trustee on behalf and at the expense of the Authority shall mail (by first-class mail) notice of any redemption to the Owners of any Bonds designated for redemption, at their respective addresses appearing on the Registration Books under the Indenture, and to the Securities Depositories and to the Information Services, at least twenty (20) but not more than sixty (60) days prior to the date fixed for redemption; provided, however, that neither failure to receive any such notice so mailed nor any defect therein shall affect the validity of the proceedings for the redemption of such Bonds or the cessation of the accrual of interest thereon. Such notice shall state the date of the notice, the Redemption Date, the redemption place and the redemption price and shall designate the CUSIP numbers, the Bond numbers (but only if less than all of the Outstanding Bonds are to be redeemed) and the maturity or maturities in the event of redemption of less than all of the Bonds, and shall require that such Bonds be then surrendered at the Corporate Trust Office of the Trustee for redemption at the redemption price, giving notice also that further interest on such Bonds will not accrue from and after the Redemption Date and with regard to optional redemption in the event that funds required to pay the redemption price are not on deposit under the Indenture at the time the notice of redemption is sent, a statement to the effect that the redemption is conditioned upon the receipt of the appropriate funds required to pay the redemption price by the Trustee on or prior to the redemption date. Any such notice may be rescinded by the Authority, in which case the Trustee shall notify the Owners of the affected Bonds of such rescission. Selection of Bonds for Redemption. Whenever provision is made for the redemption of less than all of the Bonds, the Authority shall select the Bonds to be redeemed to correspond to the Principal Components of the Purchase Payments prepaid by the City in accordance with the Installment Purchase Agreement and by lot within a maturity; provided, that in the case of any redemption of any Bond, or portion thereof, prior to its maturity, the Trustee shall first select those Bonds previously acquired by the Authority and designated by the Authority as satisfying Purchase Payments, which the Authority has delivered to the Trustee, in lieu of making such redemption, and then the Trustee shall select by lot within a maturity the other Bonds to be redeemed. Any selection of such Bonds by the Trustee shall be binding upon the Owners. For purposes of such selection, all Bonds shall be deemed to be comprised of separate $5,000 portions and such portions shall be treated as separate Bonds which may be separately redeemed. Partial Redemption of Bonds. In the event only a portion of any Bond is called for redemption, then upon surrender of such Bond the Authority shall execute and the Trustee shall authenticate and deliver to the Owner thereof, at the expense of the Authority, a new Bond of the same maturity date, of Authorized Denominations in an aggregate principal amounts equal to the unredeemed portion of the Bond to be redeemed. Effect of Redemption. From and after the date fixed for redemption, if funds available for the payment of the principal of and interest (and premium, if any) on the Bonds so called for redemption shall have been duly provided, such Bonds so called shall cease to be entitled to any benefit under the Indenture other than the right to receive payment of the principal, interest accrued to the Redemption Date, and premium, if any, and no interest shall accrue thereon from and after the Redemption Date specified in such notice. Transfer and Exchange of the Bonds Any Bond may, in accordance with its terms, be transferred, upon the Registration Books under the Indenture, by the person in whose name it is registered, in person or by his attorney duly authorized in writing, upon surrender of such Bond for cancellation at the Corporate Trust Office of the Trustee, accompanied by delivery of a written instrument of transfer in a form approved by the Trustee, duly executed by the registered owner or his duly authorized attorney and upon payment by the registered owner of any charges the Trustee may make under the Indenture. Whenever any Bond shall be surrendered for transfer, the Authority shall execute and the Trustee shall authenticate and deliver to the transferee a new Bond of like tenor, maturity and aggregate principal amount. The Trustee is not required to transfer either (a) any Bonds during the period established by the Trustee for the selection of such Bonds for redemption or (b) any Bonds selected for redemption pursuant to the Indenture. The Bonds may be exchanged upon surrender thereof at the Corporate Trust Office of the Trustee upon payment by the registered 3

10 owner of any charges the Trustee may make for an equal aggregate principal amount of Bonds of other Authorized Denominations and of the same tenor and maturity. Purchase Payments SECURITY AND SOURCES OF PAYMENT FOR THE BONDS The Bonds will be payable from and secured by, among other things, the Purchase Payments, to be made by the City under the Installment Purchase Agreement. Pursuant to the Indenture, the Authority will assign and transfer in trust to the Trustee substantially all of its rights in and to the Installment Purchase Agreement, including the right to receive the Purchase Payments thereunder and any and all of the other rights of the Authority under the Installment Purchase Agreement as may be necessary to enforce the payment of such Purchase Payments pursuant to the Installment Purchase Agreement. Pursuant to the Installment Purchase Agreement, the City is obligated to make Purchase Payments solely from Surplus Revenues in the Qualified Obligations Account of the Electric System Surplus Revenue Fund (a special fund of the City held by the Treasurer of the City and created pursuant to Ordinance No of the City Council) until the Crossover Date. The Purchase Payments are payable from Surplus Revenues on a parity with each other and with the purchase payments relating to other Qualified Obligations (as hereinafter defined) that are currently outstanding and that may be issued in the future. The Purchase Payments are junior and subordinate in priority of payment to (i) any Senior Bonds (of which none are currently outstanding) and (ii) the City s take-or-pay obligations with respect to certain joint powers agency contracts (see Take-or-Pay Obligations below and THE ELECTRIC SYSTEM Joint Powers Agency Contracts ). Nothing in the Installment Purchase Agreement precludes the City from making Purchase Payments from other lawfully available moneys of the City. Subject to the limitations set forth in the preceding paragraph, the obligation of the City to make the Purchase Payments required by the Installment Purchase Agreement is absolute and unconditional, and is not to be abated, rebated, set-off, reduced or otherwise modified in any manner or to any extent whatsoever while any Purchase Payments remain unpaid, regardless of any contingency, act of God, event or cause whatsoever, including, without limiting the generality of the foregoing, any acts or circumstances that may constitute failure of consideration, eviction or constructive eviction, taking by eminent domain of or destruction of or damage to the Distribution System Assets purchased under the Installment Purchase Agreement or the commercial frustration of purpose, any change in the laws of the United States or the State of California or any political subdivision of either or the rules or regulations of any governmental authority or any failure of the Authority or the Trustee to perform and observe any agreement, duty, liability or obligation arising out of or connected with the Installment Purchase Agreement or Indenture. The Installment Purchase Agreement is deemed to constitute a net contract pursuant to which the City will pay absolutely net amounts of the Purchase Payments payable thereunder and all other payments required thereunder, regardless of any rights of set-off, recoupment, abatement or counterclaim the City might otherwise have against the Authority, the Trustee or any other party. The City has covenanted in the Installment Purchase Agreement to take such action as may be necessary to include and maintain the Purchase Payments due thereunder in its budget for the appropriate Fiscal Year or pursuant to a separate resolution of the City Council and to make the appropriations necessary for the payment of all such Purchase Payments required under the Installment Purchase Agreement. The performance of this covenant by the City is to be deemed and understood under the Installment Purchase Agreement to be a ministerial duty. From and after the Crossover Date, the Purchase Payments will no longer be payable from Surplus Revenues but will instead be payable solely from Distribution System Net Revenues as Distribution System Parity Obligations under the Installment Purchase Agreement. Several conditions must be satisfied in order for the Crossover Date to occur, including the operation of the generation and distribution components of the Electric System as separate enterprises for an entire Fiscal Year. See Crossover Date herein. THE OBLIGATION OF THE CITY TO MAKE PURCHASE PAYMENTS UNDER THE INSTALLMENT PURCHASE AGREEMENT IS PAYABLE SOLELY FROM SURPLUS REVENUES IN THE 4

11 QUALIFIED OBLIGATIONS ACCOUNT UNTIL THE CROSSOVER DATE, IF AND WHEN IT OCCURS, AND THEREAFTER SOLELY FROM DISTRIBUTION SYSTEM NET REVENUES, UNLESS OTHERWISE PAID FROM OTHER SOURCES OF LEGALLY AVAILABLE FUNDS. THE BONDS SHALL NOT IN ANY WAY BE CONSTRUED AS A DEBT OF THE CITY, THE STATE OF CALIFORNIA OR ANY POLITICAL SUBDIVISION THEREOF IN CONTRAVENTION OF ANY APPLICABLE CONSTITUTIONAL OR STATUTORY DEBT LIMITATION, NOR SHALL ANYTHING CONTAINED IN THE INSTALLMENT PURCHASE AGREEMENT OR THE INDENTURE BE CONSTRUED AS A PLEDGE OF GENERAL REVENUES, FUNDS OR MONEYS OF THE CITY OR THE AUTHORITY OR AN OBLIGATION OF THE CITY FOR WHICH THE CITY IS OBLIGATED TO LEVY OR PLEDGE ANY FORM OF TAXATION OR FOR WHICH THE CITY HAS LEVIED OR PLEDGED ANY FORM OF TAXATION. THE AUTHORITY HAS NO TAXING POWER. Electric System Flow of Funds Until the Crossover Date, the City is required by the Installment Purchase Agreement to pay, on or before each Purchase Payment Date, from the Qualified Obligations Account of the Surplus Revenue Fund to the Trustee for deposit in the Purchase Payment Fund, the amount of the Purchase Payments due thereunder on the next succeeding Interest Payment Date. For a description of the Surplus Revenue Fund and other funds and accounts relating to the City s Electric System, see Electric System Funds and Accounts below. See APPENDIX C SUMMARY OF PRINCIPAL LEGAL DOCUMENTS The Installment Purchase Agreement Flow of Gross Revenues and Flow of Surplus Revenues. Electric System Funds and Accounts Pursuant to the Installment Purchase Agreement and the proceedings of the City relating to its Senior Bonds, all rates, fees and charges for providing electric service to persons and real property and all other fees, rents and charges and other income derived by the City from the ownership, operation, use or services of the Electric System (the Gross Revenues ) are to be deposited as received by the City to the Revenue Account in the Electric Revenue Fund held by the Treasurer of the City (the Treasurer ) until the Crossover Date. On or before the 20th day of each calendar month, the Finance Director of the City is required, so long as any Senior Bonds or Qualified Obligations remain outstanding, to withdraw the entire amount on deposit in the Revenue Account and allocate and deposit such amount in the funds and accounts, in the order of priority listed below. First, to the Bond Service Account, one-sixth of the interest which will become due and payable (less any interest which has already been provided for) on the outstanding Senior Bonds within the next six month period and one-twelfth of the principal amount which will mature and be payable on the outstanding Senior Bonds within the next twelve month period and, to the Bond Sinking Account, the amount required with respect to any term Senior Bonds to provide for mandatory sinking fund installments. Senior Bonds means any voter-approved revenue bonds, revenue notes or other similar evidences of indebtedness of the City heretofore or hereafter issued pursuant to the City Charter for the acquisition, construction and financing or refinancing of extensions of, additions to, repairs and replacements to, renewals of, and improvements of the Electric System, payable out of Gross Revenues on a basis senior to the Qualified Obligations. At present, there are no Senior Bonds outstanding and no authorized but unissued Senior Bonds. Second, to the Maintenance and Operation Account, an amount sufficient for the payment of the Maintenance and Operation Expenses of the Electric System as said expenses become due and payable. Maintenance and Operation Expenses means the reasonable and necessary current expenses of maintaining, repairing and operating the Electric System, including City administrative expenses directly 5

12 attributable to Electric System functions, but excluding depreciation, interest and amortization, all computed in accordance with sound accounting principles and consistent with existing accounting practices of the City. Included in this definition are the City s take-or-pay obligations with respect to certain joint powers agency contracts. Third, so long as any of the Senior Bonds are outstanding, to the Reserve Fund, the amount required, if any, for such Fund to equal the Maximum Annual Debt Service as defined in Resolution No. 86R-89 of the City Council, adopted October 31, 1986 (the 1986 Bond Resolution ) with respect to the Senior Bonds. Fourth, so long as any of the Senior Bonds or Qualified Obligations are outstanding, to the Renewal and Replacement Account, an amount equal to one percent of the Gross Revenues received in the preceding calendar month until a balance is established or reestablished therein equal to two percent of the depreciated book value of the land, general plant and equipment which constitute the net utility plant of the Electric System. The moneys contained in the Renewal and Replacement Account may be used for extraordinary maintenance and repairs, renewals and replacements to the Electric System, but not for additions to or extensions of the Electric System. As of July 1, 2012, the Renewal and Replacement Account is fully funded in an amount equal to two percent of the depreciated book value of the land, general plant and equipment which currently constitute the net utility plant of the Electric System. Fifth, so long as any of the Senior Bonds or Qualified Obligations are outstanding, to the Rebate Account, the amount required with respect to Senior Bonds in accordance with the Internal Revenue Code of Sixth, to the Surplus Revenue Fund, all moneys in the Revenue Account remaining after the above transfers have been made and all covenants required by the resolutions relating to the Senior Bonds have been performed. The moneys in the Surplus Revenue Fund constitute the Surplus Revenues. Electric System Surplus Revenues Prior to the Crossover Date, so long as any Qualified Obligations (including the Purchase Payments) or Second Lien Qualified Obligations are outstanding, promptly after the deposit in any month to the Surplus Revenue Fund, the entire amount of the Surplus Revenues in the Surplus Revenue Fund shall be transferred to the following accounts in the order of priority listed below. First, to the Qualified Obligations Account, the amount of Qualified Obligation Service with respect to such calendar month (to the extent not already transferred to such Account in such month) or, if less, the entire amount of Surplus Revenues then available for transfer to such Account. Qualified Obligation Service means, with respect to any period, the amount of principal and interest or other payments accrued or to accrue in such period with respect to all outstanding Qualified Obligations (excluding the amount of proceeds of Qualified Obligations held in any fund or account for the payment of Qualified Obligation Service accrued or to accrue during such period). For purposes of accrual under this definition, all payments with respect to Qualified Obligations accrued in a calendar month are to be deemed accrued on the first day of such calendar month. Qualified Obligations means, without duplication, (i) the 1999 Purchase Payments; (ii) the 2002-A Purchase Payments (to be refunded by the Series 2012-A Bonds); (iii) the 2002-B Purchase Payments; (iv) the 2003-A Purchase Payments; (v) the 2003-B Purchase Payments; (vi) the 2007-A Purchase Payments; (vii) the 2009-A Purchase Payments; (viii) the 2011-A Purchase Payments; (ix) the Purchase Payments; and (x) additional Bonds and Obligations which at the time of initial delivery thereof satisfy the requirements set forth in the Installment Purchase Agreement for the issuance of additional Qualified Obligations (see Additional Qualified Obligations ). Bonds in clause (x) above is defined to include any revenue bond, revenue note, warrant or other evidence of indebtedness issued, incurred or delivered for the financing, or refinancing of extensions of, additions to, repairs and replacements to, renewals of, and improvements of, the Electric System, designated by the City at the initial delivery thereof as payable from Surplus Revenues in the Qualified Obligations Account to the extent that the payments under such revenue bond, revenue note, 6

13 warrant or other evidence of indebtedness are payable from Surplus Revenues in the Qualified Obligations Account, but does not include any Obligation. Obligations in clause (x) above means any contract, instrument or other agreement for the purchase, acquisition or lease of facilities, properties, structures or equipment for the Electric System, designated by the City at the initial delivery thereof as payable from Surplus Revenues in the Qualified Obligations Account to the extent that payments under such contract, instrument or agreement are payable from Surplus Revenues in the Qualified Obligations Account, and the final payments under which are due more than one year following the incurrence thereof. Obligations does not include any Bonds. The aggregate principal amount of Qualified Obligations currently outstanding is $587,795,000, of which $96,210,000 in aggregate principal amount will be refunded with proceeds of the Bonds. See PLAN OF REFUNDING. Second, to the Second Lien Qualified Obligations Account the amount of Second Lien Qualified Obligation Service with respect to such calendar month (to the extent not already transferred to such Account in such month), or the entire amount of Net Surplus Revenues then available for transfer to the Second Lien Qualified Obligations Account, whichever is less. Second Lien Qualified Obligation Service means, with respect to any period, the amount of principal and interest or other payments accrued or to accrue in such period with respect to all outstanding Second Lien Qualified Obligations (excluding the amount of proceeds of Second Lien Qualified Obligations held in any fund or account for the payment of Second Lien Qualified Obligation Service accrued or to accrue during such period). For purposes of accrual under this definition, all payments with respect to Second Lien Qualified Obligations due in a calendar month are to be deemed due on the first day of such calendar month. Second Lien Qualified Obligations means, without duplication, (i) the 2004 Purchase Payments and (ii) additional Bonds and Obligations which at the time of initial delivery thereof satisfy the requirements set forth in the Installment Purchase Agreement for the issuance of additional Second Lien Qualified Obligations (see Additional Second Lien Qualified Obligations ). Bonds is defined to include any revenue bond, revenue note, warrant or other evidence of indebtedness issued, incurred or delivered for the financing, or refinancing of extensions of, additions to, repairs and replacements to, renewals of, and improvements of, the Electric System, designated by the City at the initial delivery thereof as payable from Net Surplus Revenues in the Second Lien Qualified Obligations Account. Bonds does not include any Obligations. Obligations means any contract, instrument or other agreement for the purchase, acquisition or lease of facilities, properties, structures or equipment for the Electric System, designated by the City at the initial delivery thereof as payable from Net Surplus Revenues in the Second Lien Qualified Obligations Account, and the final payments under which are due more than one year following the incurrence thereof. Obligations does not include any Bonds. The aggregate principal amount of Second Lien Qualified Obligations currently outstanding is $113,960,000. Third, to the ERAN Account, the amount required to be transferred thereto in such month for the payment of the principal of and interest on the Electric Revenue Anticipation Notes to the extent required by the ordinance(s) and resolution(s) pursuant to which the Electric Revenue Anticipation Notes are issued (to the extent not already transferred to such Account in such month), or, if less, the entire amount of Net Surplus Revenues then available for transfer to such Account. Pursuant to the City s Ordinance No. 5032, the principal amount of Electric Revenue Anticipation Notes which may be outstanding at any time shall not exceed 25% of the gross revenue earned by the Electric System during the immediately preceding Fiscal Year as set forth in the audited financial statements of the Electric System for such year or the maximum aggregate amount of the revolving Electric System Credit available to the City as described in such a revolving credit agreement or other loan agreement, whichever is less. No Electric Revenue Anticipation Notes are currently outstanding. Fourth, to the Remaining Surplus Account, all remaining Net Surplus Revenues, to be used for any lawful purpose of the City, provided, however, that in the event of any deficiency in the Qualified Obligations Account, the Second Lien Qualified Obligations Account or the ERAN Account, moneys in the Remaining Surplus Account shall be transferred to such Accounts in the order of priority indicated above to cover such deficiency. 7

14 Pursuant to the Installment Purchase Agreement, the City is obligated to make certain additional purchase payments (the Additional Purchase Payments ) for the payment of certain taxes and assessments, costs, fees and expenses of the Authority, the Trustee and any accountants, consultants, attorneys and other experts engaged by the Authority or the Trustee to perform services required in connection with the Installment Purchase Agreement and the Indenture and any rebate amounts. Prior to the Crossover Date, such Additional Purchase Payments are required to be made by the City from Surplus Revenues in the Remaining Surplus Account. As described above, prior to the Crossover Date (i) the payment of Qualified Obligations, including Purchase Payments, ranks junior to payment of the Senior Bonds and the City s take-or-pay obligations with respect to certain joint powers agency contracts; (ii) the payment of Qualified Obligations, including Purchase Payments, ranks senior to the payment of Second Lien Qualified Obligations and Electric Revenue Anticipation Notes; and (iii) the payment of Additional Purchase Payments ranks junior to the payment of the Electric Revenue Anticipation Notes. Crossover Date The City may take action in the future to unbundle its electricity generation, transmission and distribution operations in response to certain State and federal legislative and regulatory changes affecting the electric utility industry, and in particular the market for electricity generation. See DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS. Until this unbundling takes place, the City will not formally recognize or account for assets, liabilities, revenues or expenses specifically attributable to the Distribution System. The Crossover Date cannot occur sooner than the end of the first full Fiscal Year after any such unbundling takes place. The City cannot predict if or when it will unbundle its Electric System operations and operate the Distribution System as a separate enterprise. Nothing in the Installment Purchase Agreement or the Indenture shall be construed to require the City to operate the Distribution System as a separate enterprise. Furthermore, certain other conditions must be satisfied before the Crossover Date can occur, as described below. Neither the City nor the Authority can predict if or when the Crossover Date will occur. On the date that each of the following conditions is satisfied (the Crossover Date ), the Installment Purchase Agreement provides that the Purchase Payments will no longer be secured by any pledge of Surplus Revenues or amounts on deposit in the Qualified Obligations Account, but instead will be secured solely by a prior pledge of Distribution System Net Revenues: (i) the Distribution System has been operated as an enterprise separate and distinct from the rest of the Electric System for at least one full Fiscal Year, and Distribution System assets, liabilities, revenues and expenses have been determined and reported in accordance with sound accounting principles; (ii) no Senior Bonds remain outstanding; (iii) no Qualified Obligations (other than the Purchase Payments and any other obligations secured by a crossover pledge of Distribution System Net Revenues) remain Outstanding; (iv) no Second Lien Qualified Obligations (other than obligations secured by a crossover pledge of Distribution System Net Revenues) remain outstanding; (v) no Electric Revenue Anticipation Notes or other obligations secured by the Remaining Surplus Account remain outstanding; and (vi) the pro forma ratio of Distribution System Net Revenues to Maximum Annual Distribution System Service for the prior two Fiscal Years is not less than 1.10 to

15 Distribution System Flow of Funds From and after the Crossover Date, the Purchase Payments are to be made from the Distribution System Debt Service Fund (a special fund of the City to be held by the Treasurer of the City and created pursuant to Resolution No. 99R-190 of the City Council adopted on September 14, 1999 (the 1999 Resolution )). The City is required by the Installment Purchase Agreement to pay, on or before each Purchase Payment Date, from the Distribution System Debt Service Fund to the Trustee for deposit in the Purchase Payment Account, the amount of the Purchase Payments due on the next succeeding Interest Payment Date. Additional Purchase Payments are to be made from the Distribution System Provider Fund. See APPENDIX C SUMMARY OF PRINCIPAL LEGAL DOCUMENTS The Installment Purchase Agreement Purchase Price; 2012-A Purchase Payments and Flow of Distribution System Gross Revenues. Distribution System Funds and Accounts Pursuant to the Installment Purchase Agreement and the 1999 Resolution, from and after the Crossover Date all fees, rents and charges and other income derived by the City from the ownership, operation, use or services of the Distribution System (the Distribution System Gross Revenues ) are to be deposited as received by the City to the Distribution System Revenue Fund to be held by the Treasurer. From and after the Crossover Date, on or before the 20th day of each calendar month, the Finance Director of the City is required, so long as any Distribution System Parity Obligations are Outstanding, to withdraw the entire amount on deposit in the Distribution System Revenue Fund and allocate and deposit such amount in the funds and accounts, in the order of priority listed below. First, to the Distribution System O&M Fund, an amount sufficient for the payment of the Distribution System O&M Expenses as said expenses become due and payable. Distribution System O&M Expenses means the reasonable and necessary current expenses of maintaining, repairing and operating the Distribution System, including City administrative expenses directly attributable to Distribution System functions, but excluding depreciation, interest and amortization, and excluding such current expenses paid or payable from any income, revenue or receipts received or receivable by the City, or any other person or entity, from any source, including income, revenue or receipts which would otherwise constitute Distribution System Gross Revenues, which are pledged, dedicated or to be set aside for payment, prepayment, or making provision for the payment or prepayment of those Above-Market Costs relating to assets or obligations of the Electric System ( Distribution System Receipts Pledged to Above-Market Costs ), all determined in accordance with sound accounting principles and consistent with the then existing accounting practices of the City. Second, to the Distribution System Debt Service Fund, one-sixth of the interest becoming due and payable (less any interest which has already been provided for) on the Outstanding Distribution System Parity Obligations within the next six-month period and one-twelfth of the principal amount which will be payable on the Outstanding Distribution System Parity Obligations within the next twelve-month period, due to maturity, mandatory sinking fund redemption or otherwise. Third, to the Distribution System Reserve Fund, the amount required, if any, pursuant to the terms of the agreements providing for the issuance of such Distribution System Parity Obligations or any related conduit obligations. Fourth, to the Distribution System Provider Fund, an amount sufficient for the payment of fees and expenses of bond insurers, letter of credit banks and other providers of credit enhancement or liquidity with respect to Distribution System Parity Obligations, to the extent set forth in agreements with the City, as said fees and expenses become due and payable. From and after the Crossover Date, Additional Purchase Payments due under the Installment Purchase Agreement are required to be made by the City from Distribution System Net Revenues in the Distribution System Provider Fund. 9

16 Fifth, to the Distribution System Rebate Fund, the amount required with respect to Distribution System Parity Obligations in accordance with the Internal Revenue Code of 1986, as amended. Sixth, to the Distribution System Surplus Revenue Fund, all moneys in the Distribution System Revenue Fund remaining after the above transfers have been made and all covenants required by the agreements relating to the Distribution System Parity Obligations have been performed. The moneys in the Distribution System Surplus Revenue Fund constitute the Distribution System Surplus Revenues. Distribution System Surplus Revenues Moneys in the Distribution System Surplus Revenue Fund may be used at any time for any lawful purpose of the City, subject to the provisions of any future resolution or resolutions of the City specifying the use of such moneys. Rate Covenants Pursuant to the Installment Purchase Agreement, the City has agreed until the Crossover Date to prescribe, revise and collect such charges for the services and facilities of the Electric System so that, in each Fiscal Year, the Surplus Revenues shall at least equal the sum of (i) 1.25 times the amount of Qualified Obligation Service with respect to such Fiscal Year; (ii) 1.00 times the principal of and interest on the outstanding Electric Revenue Anticipation Notes due and payable and to be paid from Surplus Revenues in such Fiscal Year; and (iii) 1.00 times all other payments required to be made from Surplus Revenues in such Fiscal Year. Pursuant to the Installment Purchase Agreement, from and after the Crossover Date, the City has agreed to prescribe, revise and collect such charges for the services and facilities of the Distribution System so that, in each Fiscal Year, the Distribution System Net Revenues shall at least equal the sum of (i) 1.10 times the amount of Distribution System Service with respect to such Fiscal Year and (ii) 1.00 times all other payments required to be made from Distribution System Net Revenues in such Fiscal Year. Debt Service Reserve Fund Pursuant to the Indenture, a Debt Service Reserve Fund is created which is to be held by the Trustee and used to make payments of principal and interest with respect to the Bonds, to the extent that amounts in the Interest Account or Principal Account are not sufficient to pay in full the interest or principal on the such Bonds when due. The Debt Service Reserve Fund is required to be funded in an amount equal to the Reserve Requirement, which is defined under the Indenture to mean, as of any calculation date in a Bond Year, an amount equal to the least of (i) ten percent of the sale proceeds (within the meaning of section 148 of the Code) of the Bonds; (ii) 125% of average annual debt service on the Bonds for that and every succeeding Bond Year; or (iii) Maximum Annual Debt Service for the Bonds; provided, however, that in no event shall the Reserve Requirement exceed the amount thereof calculated on the Delivery Date. See APPENDIX C SUMMARY OF PRINCIPAL LEGAL DOCUMENTS The Indenture Debt Service Reserve Fund. On the Delivery Date, the Reserve Requirement for the Bonds will be $10,101, Upon prior written notification to Fitch and S&P, the Reserve Requirement may be satisfied by crediting to the Debt Service Reserve Fund moneys or a Qualified Reserve Fund Credit Instrument or any combination thereof, which in the aggregate make funds available in the Debt Service Reserve Fund in an amount equal to the Reserve Requirement. In any case where the Debt Service Reserve Fund is funded with a combination of cash and a Qualified Reserve Fund Credit Instrument, the Trustee shall deplete all cash balances before drawing on the Qualified Reserve Fund Credit Instrument. Thereafter, any available moneys provided by the Authority or the City to replenish the Debt Service Reserve Fund shall be used first to reinstate the Qualified Reserve Fund Credit Instrument and second, to replenish the cash in such Debt Service Reserve Fund. 10

17 Insurance The City agrees in the Installment Purchase Agreement to maintain at all times with responsible insurers all such insurance on the Electric System as is customarily maintained by similar utilities systems with respect to works and properties of like character against accident to, loss of, or damage to, such works or properties and against loss of revenues. The City further agrees that any useful parts of the Electric System that are damaged or destroyed shall be restored to use. Proceeds of insurance against accident, loss or damage shall be used for repairing or rebuilding the lost, damaged or destroyed works and properties, and, to the extent not so used, shall be applied, prior to the Crossover Date, to the retirement of outstanding Senior Bonds and Qualified Obligations, and from and after the Crossover Date, to the retirement of outstanding Distribution System Parity Obligations. Moneys collected from any loss of revenues insurance shall be deposited in the Revenue Account. The City is permitted under the Installment Purchase Agreement to satisfy the foregoing covenant through a self-insurance program or to provide such insurance as part of any blanket coverages maintained by the City. Additional Qualified Obligations The City has agreed pursuant to the Installment Purchase Agreement, after the date on which the Bonds are delivered pursuant to the Indenture to the original purchasers thereof and prior to the Crossover Date, not to issue, incur or deliver any Bonds or Obligations payable from the Surplus Revenues in the Qualified Obligations Account unless, at the initial delivery thereof, the Surplus Revenues, calculated on sound accounting principles, as shown by the books of the City for each of the last two completed Fiscal Years prior to the adoption of the resolution approving the delivery of such Bonds or Obligations (as shown by an audit certificate or opinion of an independent certified public accountant or firm of certified public accountants employed by the City), plus, at the option of the City, the allowance for earnings described in the following paragraph, shall have amounted to at least 1.25 times the Maximum Annual Qualified Obligation Service on all Qualified Obligations to be outstanding immediately subsequent to the initial delivery of such Bonds or Obligations. Notwithstanding the foregoing, the City may issue Bonds or Obligations to refund outstanding Qualified Obligations if, after giving effect to the application of the proceeds thereof, either (i) total Qualified Obligation Service will not be increased in any Fiscal Year in which Qualified Obligations (outstanding on the date of issuance or incurrence of such refunding Bonds or Obligations, but excluding such refunding Bonds or Obligations) not being refunded are outstanding, or (ii) the Surplus Revenues, calculated on sound accounting principles, as shown by the books of the City for each of the last two completed Fiscal Years prior to the adoption of the resolution approving the delivery of such Bonds or Obligations (as shown by an audit certificate or opinion of an independent certified public accountant or firm of certified public accountants employed by the City), plus, at the option of the City, the allowance for earnings described in the following paragraph, shall have amounted to at least 1.25 times total Qualified Obligation Service in the Fiscal Year next succeeding the Fiscal Year in which such Bond or Obligation is initially delivered. For the purpose of applying the restrictions set forth in the preceding paragraph, the following allowance may be added to the Surplus Revenues: an allowance for earnings arising from any increase in the charges made for service from the Electric System which has become effective prior to the initial delivery of such Bonds or Obligations but which, during all or any part of said last two completed Fiscal Years, was not in effect, in an amount equal to 95% of the amount by which the Surplus Revenues would have been increased if such increase in charges had been in effect during the whole of said last two completed Fiscal Years, as shown by the certificate or opinion of an independent certified accountant or firm of certified public accountants employed by the City. The City has also agreed pursuant to the Installment Purchase Agreement that the Surplus Revenues will not be mortgaged, encumbered, sold, leased, pledged, any charge placed thereon, or disposed of or used except as permitted by such Installment Purchase Agreement. 11

18 Additional Distribution System Parity Obligations The City has agreed pursuant to the Installment Purchase Agreement, that from and after the Crossover Date, it will not issue, incur or deliver any Bonds or Obligations payable from the Distribution System Net Revenues in the Distribution System Revenue Fund unless, at the initial delivery thereof, the Distribution System Net Revenues, calculated on sound accounting principles, as shown by the books of the City for each of the last two completed Fiscal Years prior to the adoption of the resolution approving the delivery of such Bonds or Obligations (as shown by a certificate of the City), plus, at the option of the City, the allowance for earnings described in the following paragraph, shall have amounted to at least 1.10 times the Maximum Annual Distribution System Service on all Distribution System Parity Obligations to be outstanding immediately subsequent to the initial delivery of such Bonds or Obligations. For purposes of this provision, the conversion of any Bonds or Obligations to a different interest rate mode shall be deemed a delivery of Bonds or Obligations. Notwithstanding the foregoing, the City may issue Bonds or Obligations to refund outstanding Distribution System Parity Obligations if, after giving effect to the application of the proceeds thereof, either (i) total Distribution System Service will not be increased in any Fiscal Year in which Distribution System Parity Obligations (outstanding on the date of issuance or incurrence of such refunding Bonds or Obligations, but excluding such refunding Bonds or Obligations) not being refunded are outstanding, or (ii) the Distribution System Net Revenues, calculated on sound accounting principles, as shown by the books of the City for each of the last two completed Fiscal Years prior to the adoption of the resolution approving the delivery of such Bonds or Obligations (as shown by a certificate of the City), plus, at the option of the City, the allowance for earnings described in the following paragraph, shall have amounted to at least 1.10 times total Distribution System Service in the Fiscal Year next succeeding the Fiscal Year in which such Bond or Obligation is initially delivered. For the purpose of applying the restrictions set forth in the preceding paragraph, the following allowance may be added to the Distribution System Net Revenues: an allowance for earnings arising from any increase in the charges made for service from the Distribution System which has become effective prior to the initial delivery of such Bonds or Obligations but which, during all or any part of said last two completed Fiscal Years, was not in effect, in an amount equal to 95% of the amount by which the Distribution System Net Revenues would have been increased if such increase in charges had been in effect during the whole of said last two completed Fiscal Years, as shown by the certificate of the City. The City has also agreed pursuant to the Installment Purchase Agreement that the Distribution System Net Revenues will not be mortgaged, encumbered, sold, leased, pledged, any charge placed thereon, or disposed of or used except as permitted by the Installment Purchase Agreement. Take-or-Pay Obligations The City has entered into certain power sales and transmission service contracts and other agreements for the payment of its share of the costs of certain projects in which it participates. See THE ELECTRIC SYSTEM Non-City Owned Resources and Joint Powers Agency Contracts herein. The City s obligations under certain of these contracts constitute a portion of the Maintenance and Operations Expenses of the Electric System or the Distribution System and thus are payable from Gross Revenues prior to the payment of Qualified Obligations or Distribution System Parity Obligations, including the Purchase Payments. The City could enter into additional contracts the obligations under which constitute Maintenance and Operation Expenses, subject to the rate covenants described above. Limited Recourse on Default If the City defaults under the Installment Purchase Agreement, the Trustee, as assignee of the Authority pursuant to the Indenture, may exercise any right to enforce such Installment Purchase Agreement provided therein or by law. In the event of such default, the Installment Purchase Agreement does not provide any remedy of acceleration of the Purchase Payments due over the term of the Installment Purchase Agreement, and the Trustee is not empowered to sell the Distribution System Assets or any portion thereof and use the proceeds of such sale to prepay any obligations in respect of the Bonds. The City will only be liable for Purchase Payments on an annual 12

19 basis, and the Trustee would be required to seek a separate judgment for each year s defaulted Purchase Payments. Any such suit for money damages would be subject to limitations on legal remedies against cities in California, including a limitation on enforcement of judgments against funds and property needed to serve the public welfare and interest. PLAN OF REFUNDING A portion of the proceeds of the Bonds, together with certain other funds, will be used to redeem all of the Authority s outstanding Revenue Bonds, Series 2002-A (City of Anaheim Electric System Distribution Facilities) (hereinafter, the Refunded Bonds ), and will also prepay the City s obligation to make 2002-A Purchase Payments with respect to the Refunded Bonds. The Authority and the City will effect the redemption of the Refunded Bonds by causing a portion of the proceeds of the Bonds, together with certain other funds, to be deposited into an escrow fund for the Refunded Bonds (the Escrow Fund ) created under an Escrow Agreement, dated as of September 1, 2012, by and among the Authority, the City and The Bank of New York Mellon Trust Company, N.A., as escrow agent (the Escrow Agent ). Amounts in the Escrow Fund are to be invested in U.S. Treasury Securities generating cash flow sufficient to pay all principal, interest and redemption price due with respect to the Refunded Bonds on and before their redemption date of October 19, The Arbitrage Group, Inc., certified public accountants, will deliver a report stating that the firm has verified the mathematical accuracy of certain computations relating to the adequacy of the maturing principal of and interest on the investments in the Escrow Fund and the other moneys in the Escrow Fund to pay, when due, the redemption price of and interest on the Refunded Bonds. See VERIFICATION OF MATHEMATICAL COMPUTATIONS. ESTIMATED SOURCES AND USES OF FUNDS The estimated sources and uses of funds in connection with the issuance of the Bonds are as follows: SOURCES: Principal Amount of Bonds... $ 92,130, Net Bond Premium... 9,253, Transfers from Funds and Accounts relating to the Refunded Bonds... 8,050, Total Sources... $109,433, USES: Deposit to Escrow Fund... $ 98,846, Deposit to Debt Service Reserve Fund... 10,101, Costs of Issuance (1) , Total Uses... $109,433, (1) Includes Underwriters discount, fees and expenses of Bond Counsel, Disclosure Counsel, the Financial Advisor, the Verification Agent and the Trustee, rating agency fees and printing costs. DEBT SERVICE SCHEDULE The following table indicates the debt service on the outstanding Qualified Obligations through June 30, See SECURITY AND SOURCES OF PAYMENT FOR THE BONDS and PLAN OF REFUNDING. 13

20 TABLE A Electric System Qualified Obligations Debt Service Requirements Fiscal Years 2013 through 2040 (1) For Year Ending June 30 Outstanding Qualified Obligations (2) Principal Bonds Debt Service Interest Total Bonds Debt Service Total Qualified Obligations Debt Service 2013 $ 39,588,578 - $2,083,590 $ 2,083,590 $41,672, ,484,481-3,906,731 3,906,731 43,391, ,500,650-3,906,731 3,906,731 43,407, ,471,175-3,906,731 3,906,731 43,377, ,236,013-3,906,731 3,906,731 45,142, ,195,563-3,906,731 3,906,731 45,102, ,173,575-3,906,731 3,906,731 45,080, ,377,298-3,906,731 3,906,731 36,284, ,425,798-3,906,731 3,906,731 36,332, ,074,388 $ 1,455,000 3,870,356 5,325,356 35,399, ,114,013 1,205,000 3,803,856 5,008,856 35,122, ,436,919 5,015,000 3,648,356 8,663,356 35,100, ,441,500 5,210,000 3,392,731 8,602,731 35,044, ,446,125 5,470,000 3,125,731 8,595,731 35,041, ,281,781 5,750,000 2,845,231 8,595,231 41,877, ,665,903 7,695,000 2,509,106 10,204,106 41,870, ,706,069 11,025,000 2,144,466 13,169,466 41,875, ,424,181 15,800,000 1,656,200 17,456,200 41,880, ,440,325 16,425,000 1,011,700 17,436,700 41,877, ,460,856 17,080, ,600 17,421,600 41,882, ,858, ,858, ,854, ,854, ,855, ,855, ,857, ,857, ,850, ,850, ,611, ,611, ,542, ,542, ,546, ,546,288 Total $816,921,366 $92,130,000 $61,686,775 $153,816,775 $970,738,141 (1) Totals may not add due to rounding. (2) Qualified Obligations debt service excludes Refunded Bonds and Second Lien Qualified Obligations, Series CONSTITUTIONAL AND CHARTER LIMITATIONS Constitutional Limitations on Governmental Spending Article XIIIA of the California Constitution limits the taxing powers of California public agencies. Article XIIIA provides that the maximum ad valorem tax on real property cannot exceed one percent of the full cash value of the property, and effectively prohibits the levying of any other ad valorem property tax except for taxes above that level required to pay debt service on voter-approved general obligation bonds. Full cash value is defined as the County Assessor s valuation of real property as shown on the 1975/76 tax bill under full cash value or, thereafter, the appraisal value of real property when purchased, newly constructed, or a change in ownership has occurred after the 1975 assessment. The full cash value is subject to annual adjustment to reflect inflation at a rate not to exceed two percent or a reduction in the consumer price index or comparable local data, or declining property value caused by damage, destruction or other factors. The foregoing limitation does not apply to ad valorem taxes or special assessments to pay the interest and redemption charges on any indebtedness approved by the voters before July 1, 1978 or any bonded indebtedness for the acquisition or improvement of real property approved by two-thirds of the votes cast by the voters voting on the proposition. 14

21 Under Article XIIIB of the California Constitution, state and local government entities have an annual appropriations limit which limits their ability to spend certain moneys called appropriations subject to limitation, which consist of tax revenues, certain state subventions and certain other moneys, including user charges to the extent they exceed the costs reasonably borne by the entity in providing the service for which it is levying the charge. The City is of the opinion that the electric service and use charges imposed by the City do not exceed the costs the City reasonably bears in providing the electric service. In general terms, the appropriations limit is to be based on certain 1978/79 expenditures, and is to be adjusted annually to reflect changes in the consumer price index, population, and services provided by these entities. Among other provisions of Article XIIIB, if an entity s revenues in any year exceed the amount permitted to be spent, the excess would have to be returned by revising tax rates or fee schedules over the subsequent two years. Proposition 218 Proposition 218, a State ballot initiative known as the Right to Vote on Taxes Act, was approved by the voters of the State of California on November 5, 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. Article XIIID explicitly exempts fees for the provision of electric service from the provisions of such article. Nevertheless, Proposition 218 could indirectly affect some California municipally-owned electric utilities. For example, to the extent Proposition 218 reduces a city s general fund revenues, such city could seek to increase the transfers from its electric utility to its general fund. See, however, Proposition 26 below. Article XIIIC expressly extends the people s initiative power to reduce or repeal previously authorized local taxes, assessments, and fees and charges. The terms fees and charges are not defined in Article XIIIC, although the California 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, electric service charges (which are expressly exempted from the provisions of Article XIIID) may be subject to the initiative provisions of Article XIIIC, thereby subjecting such fees and charges imposed by the City to reduction by the electorate. The City has been advised 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 materially and adversely affecting the payment of the Bonds by virtue of the impairments clause of the United States Constitution. Proposition 26 Proposition 26 was approved by the electorate at the November 2, 2010 election and amended California Constitution Articles XIIIA and XIIIC. The proposition imposes a two-thirds voter approval requirement for the imposition of 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. Proposition 26, according to its supporters, is intended to prevent the circumvention of tax limitations imposed by the voters in California Constitution Articles XIIIA, XIIIC and XIIID pursuant to Proposition 13, approved in 1978, Proposition 218, approved in 1996, and other measures 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 cost to the State or local government of providing the service or product to the payor. Proposition 26 may, however, be interpreted to limit fees and charges for electric utility services charged by governmental entities such as the City to preclude future transfers of electric utility generated funds to a local government s general fund, if applicable, and/or to require stricter standards for the allocation of costs among customer classes. The City is unable to predict at this time how Proposition 26 will be interpreted by the courts or what its ultimate impact will be. 15

22 Future Initiatives Article XIIIA, Article XIIIB and Articles XIIIC and XIIID were each adopted as measures that qualified for the ballot pursuant to the State s initiative process. From time to time, other initiatives have been, and could be, proposed, and if qualified for the ballot, could be adopted affecting the City s revenues or the City s ability to expend revenues. The City is unable to predict either the likelihood of qualification for ballot or passage of these measures or the nature and impact of these measures on the operations of the Electric System. City Charter Revenue Bond Limitations Section 1210 of the Charter of the City of Anaheim (the Charter ) provides that bonds of the City that are payable out of revenues specified in such bonds may be issued when the City has established by ordinance a procedure for the issuance of such bonds, provided that such bonds cannot be issued without the assent of a majority of the voters voting upon the proposition for the issuance of such bonds at an election at which such proposition has been submitted to the qualified voters. The Charter also provides for the issuance of certain revenue bond anticipation notes to be issued in anticipation of any electric revenue bonds authorized by the voters. In addition, the Charter makes provision for the issuance of certain revenue anticipation notes in anticipation of the receipt of revenues of the Electric System; provided that the aggregate principal amount of such revenue anticipation notes outstanding in accordance with their terms at any one time cannot exceed an amount equal to 25% of the gross revenue earned by the Electric System during the immediately preceding Fiscal Year as set forth in the audited financial statements of the Electric System for such year. The City has no outstanding or authorized but unissued electric revenue bonds. History of the Electric System THE ELECTRIC SYSTEM The Electric System was established in The original City-owned generating plant was placed in service in 1895 and consisted of a steam-driven generator of 500 lights capacity. By 1896, the maximum capacity of the original generating plant had been reached and Anaheim voters authorized bonds for the combined rebuilding of both the electric light plant and the City water system. In 1916, the City entered into an agreement to purchase electricity at wholesale rates from Southern California Edison ( Edison ) rather than generate its own power. In 1934, the City, working with the federal Public Works Administration, rebuilt and expanded the distribution system sufficiently to serve the needs of its citizens until the end of World War II. The City has since continued to expand its distribution system to meet the growing demands of its customers. From 1916 through 1982, the City met substantially all of its electric capacity and energy requirements by purchases from Edison. In the mid-1970s, the City instituted a program to meet its electric capacity and energy requirements from its own resources and by long-term purchases from sources other than Edison, taking the first capacity and energy from such resources in As a result of this program, beginning in the Fiscal Year ended June 30, 2001, the City purchased none of its energy requirements from Edison. For the Fiscal Year ended June 30, 2011, the average number of customers of the Electric System was 114,662 and the total MWh sold was 2,976,014. The City is in the process of changing the resource mix of its power portfolio, decreasing its reliance on nuclear power and increasing its use of natural gas-generated power and renewable energy resources. The following table sets forth historical Electric System loads and resources: 16

23 TABLE 1 HISTORICAL RESOURCES (MW) Fiscal Year Ended June Preliminary City-Owned Resources Combustion Turbine Plant San Juan, Unit SONGS (1) Non-City Owned Resources Hoover IPP Magnolia Canyon Power Project Non-City Owned Renewable Resources Brea Power Partners (Ridgewood) PPM Energy Raser Technologies MWD Hydro Ormat Technologies Total Resources (1) The City sold its ownership interest in the San Onofre Nuclear Generating Station effective December 29, See City- Owned Resources below. Principal Facilities As of June 30, 2011, the principal facilities of the Anaheim Electric System consisted of transmission and distribution lines aggregating 1,188 circuit miles, 12 distribution substations, the City s 10.04% ownership interest in Unit 4 of the San Juan Generating Station ( San Juan ) and the City s Kraemer Combustion Turbine Plant ( Kraemer CT Plant ). See City-Owned Resources below. The capacity available to Anaheim from San Juan Unit 4 is approximately 50 MW. The Kraemer CT Plant became commercial in The capacity available from the Kraemer CT Plant is 48 MW in the winter and 46 MW in the summer. 17

24 The following tables set forth information relating to the assets, production capacity and production costs, per category of resource, of the Electric System for the five Fiscal Years shown: TABLE 2 ELECTRIC SYSTEM STATISTICS ($000) Fiscal Year Ended June 30, Investment in Utility Plants: Production (1) $ 117,978 $ 115,477 $ 112,697 $ 110,666 $ 103,450 Transmission 91,022 89,895 89,438 88,489 59,757 Distribution 780, , , , ,316 General 107, ,714 85,694 84,670 75,483 Gross utility plant (2) 1,097,041 1,035, , , ,006 Less accumulated depreciation (1) (350,483) (319,103) (284,690) (261,401) (235,359) Net plant in service 746, , , , ,647 Land (2) 35,671 35,671 35,671 35,009 33,974 Construction work in progress 35,498 40,508 35, , ,831 Total utility plant $ 817,727 $ 793,040 $ 777,129 $ 754,923 $ 672,452 Production Costs Owned Generation (3) $ 31,149 $ 38,693 $ 37,531 $ 37,672 $ 47,496 Purchased Power (4) 175, , , , ,376 Total Production Costs $ 206,512 $ 222,559 $ 210,600 $ 220,436 $ 200,872 Transmission-69 kv Circuit Miles Distribution Overhead Circuit Miles Underground Circuit Miles Transformer Capacity (in kva) 220 kv to 69 kv 1,808,000 1,808,000 1,808,000 1,808,000 1,120, kv to 12 kv (5) 1,135,400 1,135,400 1,135,400 1,108,200 1,088, kv to Customer (5) 1,557,040 1,559,932 1,560,258 1,402,320 1,394,886 (1) Production plant and accumulated depreciation reflect the transfer of the City s interest in SONGS effective December 29, (2) Land has been reclassified from utility plant; however, total utility plant remains the same. (3) Information includes debt service on facilities during the fiscal period. (4) Excludes transmission costs and gas sold and includes debt service in connection with certain take-or-pay obligations with respect to joint powers agency contracts. See THE ELECTRIC SYSTEM Joint Powers Agency Contracts. (5) Transformer capacity changes reflect more up to date information derived from the City s geographic information system. The electric resources of the City currently consist of power from the City s ownership interests in San Juan and the Kraemer CT Plant, purchases of firm power under entitlements in the Intermountain Power Project, the Hoover Uprating Project and the Magnolia Power Project and firm power purchases and non-firm energy purchases from other utilities. The City has also acquired an entitlement to 100% of the capacity and energy of the Canyon Power Project, a 200 MW natural gas-fired peaking power plant owned by the Southern California Public Power Authority ( SCPPA ), a joint powers agency in which the City is a member. The Canyon Power Project is operated and maintained by the City. The Canyon Power Project began commercial operation in September In the Fiscal Year ended June 30, 2011, the City generated and purchased a total of approximately 3,168,201 megawatthours ( MWh ) of electricity. Combined customer electric requirements created the historic distribution system peak demand of 593 MW on July 24, The following table sets forth the total Electric System energy generated and purchased and electric distribution system peak demand during the five Fiscal Years shown: 18

25 TABLE 3 TOTAL MEGAWATT HOURS (MWh) GENERATED AND PURCHASED (000) AND PEAK DEMAND (MW) Fiscal Year Ended June Preliminary Owned Generation: San Onofre Nuclear Generating Station (SONGS) (1) San Juan Combustion Turbine Subtotal Firm Purchases: Intermountain Power Project (3)... 1,338 1,485 1,903 1,841 1,904 1,960 Hoover Magnolia Canyon Power Project CAISO and PX Renewable Resources Subtotal... 2,346 2,232 2,837 2,640 2,683 2,647 Non-Firm Purchases System Total Energy Generated and Purchased, MWh (2)... 3,094 3,168 3,496 3,273 3,280 3,477 Distribution System Peak Demand, MW (1) Anaheim transferred its ownership interest in SONGS effective December 29, (2) Includes energy purchased that was ultimately sold to other utilities. (3) In FY 2011, IPP Units 1 and 2 were down for maintenance during the STS Upgrade; and in FY 2012, Unit 1 was down for six months due to an unplanned outage. Customers and Energy Sales The Electric System serves the entire area within the City limits (an area of approximately 50 square miles). For general economic and demographic information relating to the City, see APPENDIX B GENERAL INFORMATION REGARDING THE CITY. The following tables set forth the average number of customers and total electrical energy sold (in megawatt hours) during the five Fiscal Years shown. TABLE 4 AVERAGE NUMBER OF CUSTOMERS Fiscal Year Ended June Residential... 97,601 96,460 95,587 94,844 94,506 Commercial... 16,605 16,422 16,208 16,185 16,058 Industrial Other Other Utilities Total - All Classes , , , , ,319 19

26 TABLE 5 TOTAL ENERGY SOLD (MWh) Residential Commercial Industrial... 1,077 1,140 1,244 1,292 1,288 Other Other Utilities (2) 634 Total - All Classes (1)... 2,976 3,344 3,208 2,979 3,234 (1) The difference between the total MWh generated and purchased shown in Table 3 and total MWh sold is due to transmission and distribution system losses and wholesale transactions. (2) Reflects reduced wholesale sales. During the Fiscal Year ended June 30, 2011, Anaheim satisfied approximately 84% of its power requirements for serving retail customers from its own generation projects, its participation in IPP, the Hoover Uprating Project and the Magnolia Power Project and long-term contracts. Anaheim provides for the remaining requirements through market purchases. On March 7, 2000, the Anaheim City Council adopted a Customer Choice program to authorize direct transactions between energy suppliers and end use customers within Anaheim beginning March 31, By initiating the Customer Choice program as of March 31, 2000, Anaheim had expected to be able to collect all stranded costs under the provisions of AB To date, no customer has requested to participate in this program. On March 21, 2002, the California Public Utilities Commission (the CPUC ) suspended direct access and customer choice programs for California investor-owned utilities. However, in October 2009, California Senate Bill 695 ( SB 695 ) was signed into law, which deletes the suspension of direct access transactions for investorowned utilities and instead requires the CPUC to authorize direct access transactions for nonresidential end-use customers subject to a phase-in schedule of not less than three years and not more than five years, and subject to an annual maximum allowable total kilowatt hour ( kwh ) limit established for each investor-owned utility. The ten largest power customers of Anaheim s Electric System, in terms of kwh sales, accounted for approximately 20% of the Electric System s total energy sales for the Fiscal Year ended June 30, The largest power customer accounted for approximately 11% of total energy sales for such Fiscal Year. In connection with an expansion of the Disneyland Resort located in the City, the City entered into an agreement with The Walt Disney Company ( Disney ) pursuant to which the City and Disney agreed that the City would provide all electricity required by Disney for the operation of the Disneyland Resort. Power purchased by Disney under such agreement is at a discount from otherwise applicable rate schedules of the City. From and after July 1, 2005, the agreement allows Disney to purchase all or a portion of its electric power requirements from a supplier other than the City if the City is at that time permitting other customers with similar load characteristics to purchase electric power from other suppliers. The right of Disney to purchase power from other suppliers is subject to the right of the City to match the economic terms of any new purchase, in which event, Disney will be obligated to accept the City s offer and purchase that portion of its electric power covered by any such offer from the City. To date, Disney has not purchased power from any another supplier for its Anaheim facilities. The term of the agreement with Disney extends to December 31, 2013, with options exercisable by the City and Disney for additional six-month extensions until December 31,

27 Electric Rates and Charges Anaheim is obligated by the Anaheim Charter and by certain resolutions of Anaheim s City Council under which it has electric revenue bonds outstanding to establish rates and collect charges in an amount sufficient to service Anaheim Electric System s indebtedness, to meet its expenses of operation and maintenance and to pay other obligations payable from gross revenues, with specified requirements as to priority and coverage. Electric rates are fixed by Anaheim s City Council and are not subject to regulation by the CPUC or by any other state agency. The rates charged by Anaheim to its customers are not subject to approval by any federal agency; however, the Public Utility Regulatory Policies Act ( PURPA ) requires state regulatory authorities and nonregulated electric utilities, including Anaheim, to consider certain rate-making standards and to make certain determinations in connection therewith. Anaheim believes that it is operating in compliance with PURPA. Anaheim s City Charter requires that electric rates be based upon the cost of service to the various customer classes. The Anaheim Electric System has a number of base rate schedules. Generally, all costs of the Anaheim Electric System, including power supply costs, are recovered through the application of these base rates. Anaheim also charges its customers a Rate Stabilization Adjustment ( RSA ) that increases or decreases specifically for the recovery of the respective fluctuations in power supply, relevant operational costs and environmental mitigation costs in order to meet specified financial performance indicators and goals. These goals include the maintenance of debt service coverage ratios no less than 1.6 times and a regulatory credit account balance equal to approximately $50 million. The RSA contains two components: the Power Cost Adjustment ( PCA ) and the Environmental Mitigation Adjustment ( EMA ). The PCA is structured so that it can increase up to ½ per kwh in any 12-month period to collect for changes in power production costs, purchased power costs, regulatory compliance costs, debt service and any other costs involved in delivering energy. Additionally, if the Department s power supply or fuel costs increase by more than 10% over originally budgeted levels for a period of one month or longer or if the Department loses a major resource such as generation or transmission unit then the Department may increase the PCA by an additional 1 /kwh over and above the current ½ limit until all associated costs are collected, at which time the PCA will be reduced to its previous level. The second component of the RSA, the EMA, allows for the recovery of environmental mitigation costs, such as projected greenhouse gas emissions costs, the marginal cost differential between renewable power and traditional fossil fuel based power, and environmental mitigation costs imposed by regulatory bodies, legislative mandates or judicial settlements, orders or decrees. The EMA is structured similarly to the PCA in that the annual limit of the increase is ½ /kwh unless costs increase by more than 10% of projections, at which point the EMA s limit on annual increases may be increased by an additional 1 /kwh until all associated costs are collected, and at that time the EMA will be reduced to its previous level. The RSA collections are regulatory credit accounts to be used by management to mitigate material fluctuations in the cost of energy, loss of revenues or unbudgeted costs including the unexpected long-term loss of a generating facility, unplanned limits on the ability to transmit energy to the City, or disasters that could otherwise negatively affect the revenue stream. At management s discretion, amounts in the RSA may be withdrawn and recognized as Gross Revenues of the Electric System in order to maintain sufficient debt service coverage ratios. As of June 30, 2011, the balance in the RSA regulatory credit account was approximately $46.3 million. The RSA provides the City with operational and billing flexibility. With respect to any RSA adjustment, Anaheim first considers the result on customer bills with a goal of maintaining total electric charges that are competitive with those of other utilities in the region. Any change indicated by the RSA calculation is reviewed against other known long-term factors prior to any automatic implementation of rate changes. This allows Anaheim to blend forecasted increases or decreases in the projected power supply or operational costs to meet the financial requirements of the City and mitigate future fluctuations in electrical costs to customers. The Public Utilities General Manager has the authority to adjust the RSA within prescribed guidelines. Currently, the PCA charge is 1.90 /kwh for all retail customers, including domestic usage above prescribed lifeline levels, and is 1.45 /kwh for commercial usage, industrial usage and municipal customers. The 21

28 EMA charge is currently 1.00 /kwh for all domestic customers and 0.50 /kwh for all other customers. In addition, all classes pay a 4% undergrounding surcharge in order to fund the conversion of overhead power lines into underground lines throughout Anaheim. Anaheim does not impose a utilities user tax. The base electric rates were last revised by City Council on November 9, This action increased base electric rates by 10% overall with a 5% increase on December 1, 2010 and another 5% increase on December 1, TABLE 6 PRIMARY RATE SCHEDULES FOR RESIDENTIAL, COMMERCIAL AND INDUSTRIAL CUSTOMERS (As of June 2012) Type and Description of Service Domestic Services Single Family Customers (Basic): Customer Charge, per meter, per month $ 3.37 Energy Charge (to be added to Customer Charge): First 270 kwh, cents per kwh All Excess kwh, cents per kwh General Service Small Commercial Customers: Customer Charge, per meter, per month $ Energy Charge (to be added to Customer Charge): All kwh, cents per kwh General Service Medium Commercial Customers: Customer Charge Demand Charge (to be added to Customer Charge) First 15 kw or less of billing demand All excess kw of billing demand per kw Energy Charge (to be added to Demand Charge) All kwh, cents per kwh General Service Large Commercial and Industrial Customers: $ Customer Charge, per meter, per month $ Demand Charge (to be added to Customer Charge): First 200 kw or less of billing demand 2, All excess kw of billing demand, per kw Energy Charge (to be added to Demand Charge): For the first 540 kwh per kw of billing demand, cents per kwh 9.85 All excess kwh, cents per kwh 6.63 Summer Winter General Service Optional Time of Use Rate: Customer Charge, per meter, per month: $ $ Demand Charge (added to Customer Charge): Non-Time related Maximum Demand, per kw Plus all on-peak billing demand, per kw N/A Plus all mid-peak billing demand, per kw Plus all off-peak billing demand, per kw N/A N/A Energy Charge (added to Demand Charge): All on-peak energy, cents per kwh N/A Plus all mid-peak energy, cents per kwh Plus all off-peak energy, cents per kwh

29 The table below sets forth the average billing price per kilowatt-hour for the various customer classes during the five Fiscal Years shown. TABLE 7 AVERAGE BILLING PRICE (CENTS) PER KILOWATT-HOUR (RETAIL SALES) Fiscal Year Ended June Residential Commercial Industrial Other System Average Source: Anaheim. The following table sets forth average monthly electric billings in certain Southern California utilities: TABLE 8 ELECTRIC RATE COMPARISON BY MONTHLY BILL (As of June 2012) Residential Commercial (2) Industrial (2) 200 kwh 500 kwh 1,000 kwh 500 kwh 5,000 kwh 150 kw 50,000 kwh 1,000 kw 300,000 kwh Anaheim (1) $28.14 $81.96 $ $ $ $7, $47, Edison , , , Riverside , , LADWP , , Pasadena , , (1) The City s bill includes the RSA charge and the 4% Underground Conversion Charge collected to fund conversion of distribution lines from overhead to underground. The City does not impose a utilities user tax. As to the other utilities presented, the table does not reflect any utilities user taxes, undergrounding surcharges or street signal surcharges, although such charges are in fact imposed in many areas of Southern California. (2) Class is calculated using summer rates. Source: Anaheim. Cost of Power and Non-Firm Power The City currently has several contracts for firm purchases of power, described in greater detail herein under Non-City Owned Resources. These contracts account for approximately 70.5% of the City s total energy resources. In addition, the City has the ability to replace some of the energy otherwise available from its firm resources with energy purchased from other suppliers throughout the West. These short-term purchases are made under the Western Systems Power Pool Agreement and under bilateral agreements between the City and various suppliers. The City does this when the delivered cost of such energy is less than the variable cost of energy from its long-term resources or when additional energy is needed to meet the City s load. In the Fiscal Year ending June 30, 2011, the City purchased 504,965 MWh of short-term energy (about 15.9% of its total energy). The City expects to continue to provide for its energy needs by dispatching power from generating plants in which it has an ownership share, from power sales agreements or from short term (monthly, weekly, daily or hourly) purchases it makes on the spot market. The cost of obtaining the necessary energy will depend upon contract 23

30 requirements and the current market price for energy. Spot market prices are dependent upon such factors as the availability of generating resources in the region and weather conditions such as ambient temperatures and the amount of rainfall or snowfall. Generating unit outages, dry weather, hot or cold temperatures and time of year can all adversely impact the supply and price of energy. There is no assurance that low cost energy will be available to the City in the future, though as a participant in the Western Systems Power Pool the City will have access to market priced power. Capital Improvements Plan As part of its planning process, the City has identified the following Electric System capital improvement projects through Fiscal Year 2017 (the Five-Year Plan ), totaling approximately $190 million: Five-Year Plan New Substations $ 9,500,000 Substation Improvements 8,420,000 Transmission and Distribution 80,753,000 System Undergrounding 66,785,000 Other Capital Projects 24,729,000 Total $190,187,000 Projects involving the Electric System s electricity distribution substations include enhancements to existing substations, such as new transformers, circuit breakers and switchgear that will improve reliability and provide sufficient capacity for anticipated electric load growth. Another component of the Electric System s capital improvement plan involves projects through Fiscal Year 2017 to replace aging overhead electrical and communication facilities with new state-of-the-art underground facilities, in order to improve overall system reliability, public safety and City aesthetics. Undergrounding projects to date have resulted in completion of 109 of 220 circuit miles of the City s electric lines along the City s major thoroughfares. The Five-Year Plan for underground conversion will convert another 27 circuit miles of overhead lines to underground systems. In addition, the Electric System s capital improvement plan contemplates the repair and replacement of existing overhead and underground facilities. Other capital projects include replacing aging transformers, vaults, switches, cable and utility poles, as well as system reliability enhancements for equipment automation, supervisory control and data acquisition (SCADA) and telecommunications projects. The City funds its capital plan through a mix of bonds, pay as you go, and other resources. The City anticipates issuing Qualified Obligations to finance approximately $140 million of the total $190 million cost of the Five-Year Plan. The City is in the bond market on a periodic basis to fund appropriate capital projects based on its planning models. City-Owned Resources The City s owned generation resources currently consist of the Kraemer CT Plant and its interest in Unit 4 of San Juan. The capacity available from the Kraemer CT Plant is 48 MW in the winter and 46 MW in the summer. The capacity available to the City from San Juan is approximately 50 MW. The City shares its ownership interests in San Juan with other utilities, one or more of which have primary responsibility for the operation and management of these facilities. Information as to production costs associated with the City s owned generation resources is set forth in the table captioned Electric System Statistics. San Juan Generating Station Unit 4. The City has a 10.04% (50 MW) undivided ownership interest in San Juan, located in San Juan County in northwestern New Mexico, near Farmington, New Mexico. San Juan is a four-unit coal-fired steam electric generating plant. Unit 4 has a rated net generating capability of 507 MW. Unit 4 was constructed and is operated by Public Service Company of New Mexico ( PNM ). Other participants in Unit 4 are PNM, %; City of Farmington, New Mexico, 8.475%; M-S-R Public Power Agency, which is comprised of three California entities: Modesto Irrigation District, the City of Santa Clara, and the City of Redding 28.8%; Utah Associated Municipal Power Systems, 7.028%; and Los Alamos County, New Mexico, 7.20%. Unit 4 became 24

31 commercially operational in April In April 1991, the City and PNM entered into a Purchase and Participation Agreement that allowed the City to purchase its 50 MW share in Unit 4 for a price of $55 million, which was financed through revenue bonds. In Fiscal Year ended June 30, 2012, San Juan provided approximately 358,000 MWh of energy to the City. The City and the other owners are entitled to power and energy in proportion to their respective participation share. On October 27, 1999, the City and the other owners entered into the San Juan Project Participation Agreement to govern the ownership and operation of the project. The San Juan Project Participation Agreement, among other things, enhances the ability to manage their interests in the project. The cost of capital additions and replacements and operating work is charged to each owner in accordance with its participation share. The Engineering and Operations Committee approves the budget for capital expenditures and operating expense for the plant. However, any expenditures proposed by it that exceed $500,000 must be approved by the members San Juan Coordination Committee which includes one representative from each participant. The Purchase and Participation Agreement for San Juan terminates July 1, 2022 unless the San Juan Project Participation Agreement is extended. If the San Juan Project Participation Agreement is extended, the term of the Purchase and Participation Agreement will automatically be extended unless the City elects to terminate its interest effective July 1, San Juan is a mine mouth plant to which low sulfur coal is delivered from the San Juan Mine and the La Plata Mine. The coal is crushed and then conveyed to one of the four coal storage piles at San Juan. This stockpile is designed to assure a steady fuel supply in the event of fluctuations in mining operations. The supply of coal for San Juan is acquired by PNM as the operating agent. On August 23, 2000, PNM reached an agreement with the coal supplier to replace the surface mining operations with an underground mine located adjacent to the plant. Underground mining provides a higher quality coal at a lower cost per ton. The new mine uses longwall mining technique and began operations on October 14, The new coal supply arrangements are expected to save the City about $31 million in fuel costs over the life of the contract (which terminates in 2017). Besides saving on fuel costs, the higher quality cleaner burning coal is also expected to reduce the City s share of the plant s operating and maintenance expenses. In addition to the plant for Unit 4, the participants in Unit 4 are responsible for the maintenance and operation of certain common facilities in conjunction with the participants in other San Juan units. The common facilities include all pollution control equipment, the control room and some coal handling facilities. In December 2009, the City received a notice of an intent to sue ( RCRA Notice ) under the Resources Conservation and Recovery Act ( RCRA ) from the Sierra Club. The RCRA Notice was also sent to all San Juan Generating Station owners, to the San Juan Coal Company ( SJCC ), which operates the San Juan Mine that supplies coal to the generating station, and to the San Juan Coal Company s parent company, BHP Billiton ( BHP ). Additionally, SJCC and BHP received a separate Notice of Intent to Sue ( SMCRA Notice ) under the Surface Mine Control and Reclamation Act ( SMCRA ) from the Sierra Club. On April 8, 2010, the Sierra Club filed suit in the U.S. District Court for the District of New Mexico against PNM, PNM Resources ( PNMR ), the parent company of PNM, SJCC and BHP. In the suit, the Sierra Club alleges that activities at the San Juan Generating Station and the San Juan Mine are causing imminent and substantial harm to the environment, including ground and surface waters in the region. On July 10, 2010, the Sierra Club filed an amended complaint that corrected some technical deficiencies in its original complaint. The factual allegations remained the same. The parties have agreed to a stay of the action, which the Court entered on August 27, 2010, to allow the parties to try to address Sierra Club s concerns. The parties engaged in lengthy settlement negotiations including the development and informal exchange of settlement information to facilitate settlement negotiations and to better define the technical matters at issue in the lawsuit. The Sierra Club, PNM, and SJCC agreed, and entered into a consent decree on April 12, 2012 to avoid further litigation as the most appropriate means of resolving this matter. The resulting outcome includes construction and operation of a system for the recovery and transfer of surface water and groundwater, management of surface water flow at the recovery system, and to investigate the need for, and feasibility of, alternative remedial measures to address alleged impacts to surface water and groundwater. The total financial impact resulting from the consent decree is $10.15 million of which the City is responsible for approximately $315,

32 The U.S. Environmental Protection Agency (the EPA ) has established rules addressing regional haze (i.e., visibility impairment caused by cumulative air pollutant emissions from numerous sources over a wide geographic area). The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. The rules require Best Available Retrofit Technology ( BART ) to be considered as a control measure on specific categories of certain major stationary sources of haze-producing pollutants in existence prior to the enactment in 1977 of the Clean Air Act amendments addressing regional haze. If a source is found to be BART-eligible, a determination of the source s contribution to visibility impairment and the resulting emission reductions from the application of BART is conducted. In November 2006, the New Mexico Environment Department (the NMED ) requested a BART analysis for nitrogen oxide ( NOx ) and particulates for each of the four units at the San Juan Generating Station. PNM submitted its analysis to the NMED in June 2007, recommending against installing additional pollution control equipment on any of the San Juan Generating Station units beyond those planned at that time, the installation of which was completed in March PNM subsequently provided additional data in response to requests from the NMED. In June 2010, the NMED filed a proposed regional haze State Implementation Plan ( SIP ) with the New Mexico Environmental Improvement Board (the EIB ), which included a finding by the NMED that BART for NOx at the San Juan Generating Station is a technology known as selective catalytic reduction ( SCR ) plus sorbent injection. PNM disagreed with this BART determination. The costs of installation of these technologies at the San Juan Generating Station would be substantial and would also be expected to result in increased operating costs. The NMED subsequently withdrew its petition for adoption of the regional haze SIP on December 17, The EPA was subject to a consent decree that required it to issue a proposed Federal Implementation Plan ( FIP ) for certain states, including New Mexico, for regional haze mitigation if no proposed SIP had been submitted by December 22, The EPA Region 6 issued a proposed Interstate Transport FIP on December 20, 2010 which required the installation of SCR technology at all four units of the San Juan Generating Station within a three-year timeframe. On February 28, 2011, the NMED submitted a new proposed SIP to the EIB which included a state BART determination for San Juan Generating Station. Under the proposed SIP as submitted, the state has concluded that selective non-catalytic reduction ( SNCR ) is BART for San Juan, a different and less expensive technology than proposed by the EPA in the FIP. On August 5, 2011 the EPA issued the final FIP which includes the installation of SCRs at San Juan over a five year timeframe. The resulting final FIP led PNM to appeal the process and request a stay directly with the EPA as well as in the 10 th Circuit Court. The 10 th Circuit Court denied the stay on March 1, The court will now consider the merits of appeals of the requirement by PNM, the NMED and New Mexico Governor Susana Martinez. Those parties maintain EPA s mandate would cost New Mexico electric ratepayers and others about $750 million or more while a New Mexico plan could meet the same federal visibility rules for $77 million, or about one-tenth of the cost. On July 2, 2012, the EPA granted a 90-day stay of the five-year deadline contained in the final FIP to allow a collaborative effort among the NMED, PNM and the EPA to develop an alternative plan for the San Juan Generating Station to meet the federal regional haze requirements. The City is unable to predict whether the final FIP or SIP will ultimately prevail and what, if any, additional pollution control equipment will ultimately be required for the San Juan Generating Station. As described above, the installation of additional pollution control equipment at the San Juan Generating Station, if required, would likely require a significant capital investment by the San Juan Generating Station owners, including the City. Combustion Turbine Plant. The City owns 100% of the Kraemer CT Plant, a 48-MW natural gas-fired combustion turbine plant located in the northeast part of the City, adjacent to the City s Dowling Substation. There is also a heat recovery steam generator for emissions control and power augmentation. The Kraemer CT Plant is able to operate for up to 16 hours per day, six days a week for 50 weeks per year, which equates to a maximum of 4,800 annual operating hours. The Kraemer CT Plant began operation in May The City has increased its hours of operation by participation in the Air Quality Management District s ( AQMD ) Reclaim project and has purchased sufficient credits to cover the anticipated NO X emissions associated with its operation as an intermediate unit, rather than just a peaking resource. Since 2000, the operations of the Kraemer CT Plant have increased as market conditions have changed. In the Fiscal Year ending June 30, 2012, the Kraemer CT Plant provided approximately 44,000 MWh of energy to the City. 26

33 San Onofre Nuclear Generating Station. Until 2007, the City s interest in the San Onofre Nuclear Generating Station ( SONGS ) was the most significant City-owned generation resource in its portfolio. Under agreements with Edison, the City acquired a 3.16% ownership interest in SONGS Units 2 and 3. Maintenance and operation of SONGS remained the responsibility of Edison, under an operating agreement with the City (the SONGS Operating Agreement ) and other agreements with various participants. On June 22, 2004, Edison gave notice of an operating impairment under the SONGS Operating Agreement, requiring the City to contribute approximately $24 million to the cost of a steam generator replacement project. As a result of Edison s action, on October 11, 2004, the City exercised its option not to participate in the work related to the impairment and to have its ownership share reduced in accordance with the SONGS Operating Agreement. On December 20, 2005, the City and Edison entered into an agreement for the City to transfer its interest in SONGS to Edison pending Edison s receipt of required regulatory approvals. All approvals were obtained and the transfer became effective on December 29, The City made the decision to sell its interest in SONGS not only to avoid paying $24 million for its share of steam generator replacement costs, but also to reduce future capital costs associated with its ownership share and to avoid additional future decommissioning costs, which are estimated to range from $24.2 million to as much as $80 million in addition to approximately $127.4 million previously funded by the City and currently held in trust for decommissioning. Non-City Owned Resources The City purchases power from other sources pursuant to contracts. These contracts provide generally for the City to pay costs associated with the firm purchase of power (fixed costs) as well as operations, maintenance and administrative expense (variable costs). Information regarding the cost of power purchased from these facilities is set forth herein the table captioned Electric System Statistics. With respect to each of the facilities discussed herein other than the Canyon Power Project, the City is one of any number of purchasers of such power and does not control the operations or management of such facility. Intermountain Power Project. Intermountain Power Project ( IPP ) consists of: (a) a two-unit coal-fired, steam-electric generating plant with net ratings of 900 MW per unit (the Intermountain Generating Station ) and switchyard (the Intermountain AC Switchyard ), located near Lynndyl, in Millard County, Utah; (b) a ±500 kv direct current transmission line approximately 490 miles in length from and including the Intermountain AC Switchyard, the Intermountain Converter Station (an alternating current/direct current converter station adjacent to the Switchyard) to and including a corresponding converter station at Adelanto, California (collectively, the Southern Transmission System or STS ); (c) two 50-mile, 345-kV alternating current transmission lines from the Intermountain AC Switchyard to the Mona Substation in the vicinity of Mona, Utah, and a 144-mile, 230-kV alternating current transmission line from the Intermountain AC Switchyard to the Gonder Substation near Ely, Nevada (collectively, the Northern Transmission System or NTS ); (d) a rail car service center located in Springville, in Utah County, Utah (the Service Center ); and (e) certain water rights and coal supplies. Such water rights and coal supplies, together with the Intermountain Generating Station, the Intermountain AC Switchyard and the Service Center, are referred to herein collectively as the Generation Station. IPP purchasers are 36 utilities (collectively, the IPP Purchasers ) consisting of the City, and the California cities of Los Angeles, Riverside, Burbank, Glendale and Pasadena (the IPP California Participants ); PacifiCorp, as successor to the obligations of Utah Power & Light Company ( UP&L ); 22 members of IPA and Heber Light & Power Company (collectively, the Utah Municipal Purchasers ); and six rural electric cooperatives serving loads in the States of Utah, Arizona, Colorado, Nevada and Wyoming (collectively, the Cooperative Purchasers ). The Los Angeles Department of Water and Power ( LADWP ) is the operating agent of IPP. The IPP California Participants, PacifiCorp, the Utah Municipal Purchasers and the Cooperative Purchasers have contracted, pursuant to IPP Power Sales Contracts, to purchase 75%, 4%, 14% and 7%, respectively, of the net capability of the Generation Station. The City has a % (237 MW) entitlement in the capability of the Generation Station. 27

34 IPP was constructed to provide IPP Purchasers with firm capacity and energy to satisfy a portion of their projected firm power and energy requirements. IPP and other planned resources have assisted the IPP California Participants in reducing their dependence on oil-fired and natural gas-fired generation. Unit 1 and Unit 2 of IPP were placed in commercial operation in July 1, 1986 and May 1, 1987, respectively. On December 28, 2011, the IPP Unit 1 generator (118 MW) suffered an internal failure of the generator windings causing them to melt. Repairs on the generator were completed one month ahead of schedule and the unit was returned to service on May 29, The City s current share of IPP capacity is 237 MW. The City s participation in IPP Units 1 and 2 continues through the year The City, along with the other California participants in IPP, will undertake studies and subsequent plans to mitigate emissions and/or offsets at the facility in an effort to maintain its position in the plant beyond Transmission of the output from IPP to the City and the other IPP California Participants is provided by STS. STS was placed in operation in May 1987, and its current transfer capability is 2,400 MW (as a result of completion of the STS Upgrade project referenced below). The City s entitlement in the STS is % (now MW following completion of the upgrade). The City and SCPPA have entered into a transmission service contract to provide for transmission of the City s entitlement between the Generation Station and Adelanto. Transmission service from Adelanto to the City is provided under transmission service agreements with the LADWP and transmission service under the California Independent System Operator Corporation ( CAISO ) tariff. There is a large potential of wind and geothermal renewable energy resource development available in Central Utah and in order to have access to the potential energy in that area, the California participants in IPP completed the STS Upgrade project, which increased the capacity of the transmission by 480 MW (from 1,920 MW to 2,400 MW). The cost of the project was $109 million and was bond financed by SCPPA in December As a result of the STS Upgrade project that began commercial operation in December 2010, the City s entitlement to the STS transfer capability increased by 85 MW, and the annual costs increased by approximately $3 million per year. In February 2005, a number of dairies and dairy farmers filed a lawsuit (the Utah Dairy Case ) in Utah state court naming IPA, LADWP and others as defendants based upon claims alleging that since 1987 stray voltage emitted from the IPP facilities through the ground and ground water damaged the dairy herds, including higher than normal death rates, a reduction in milk production and an impairment to the cows immune systems. The Utah plaintiffs seek compensatory damages in excess of $250 million. The trial court has dismissed certain claims in the complaint with prejudice and certain other claims without prejudice. In September 2008, the court issued rulings on certain other pending motions, including granting a motion of LADWP and IPA to dismiss all claims of punitive damages as against those entities, dismissing the claims of one plaintiff, dismissing one other cause of action against LADWP and IPA, and denying certain other motions without prejudice. In June 2009, the court held a five-day evidentiary hearing on motions by LADWP and IPA to exclude the testimony of Plaintiffs experts. On August 4, 2009, the court ruled that it would permit Plaintiffs electrical experts to testify, but would exclude all testimony of Plaintiffs only veterinary witness. Because the court has strongly suggested in prior rulings that Plaintiffs must have expert veterinary testimony to proceed, LADWP and IPA filed a motion of summary judgment. However, in the interim, Plaintiffs sought leave to appeal the order excluding their veterinary witness. The Utah Court of Appeals granted such leave on November 19, 2009, and subsequently issued an order on December 4, 2009, staying all proceedings in the trial court pending resolution of the appeal. LADWP and IPA then cross-appealed the trial court s decision permitting Plaintiffs electrical experts to testify. Plaintiffs moved to dismiss the cross-appeal. LADWP and IPA filed an opposition. By order dated May 25, 2010, the court of appeals denied that motion, directed that briefing on the appeal and cross-appeal be completed, and stated that the court would review the issues raised in plaintiffs motion to dismiss once all briefing was completed. The parties then fully briefed the plaintiffs appeal and the Department s cross-appeal. Oral argument was held on both appeals on March 22, On January 20, 2012, the court of appeals reversed the decision of the trial court and directed that the Plaintiffs veterinary expert be permitted to testify. It also affirmed the decision of the trial court to permit the testimony of Plaintiffs electrical experts at trial. On March 19, 2012, LADWP and IPA timely filed a petition for a 28

35 writ of certiorari to the Utah Supreme Court, asking that court to review and reverse the court of appeals decision concerning the testimony of Plaintiffs veterinary witness. Plaintiffs responded with an opposition on May 18, LADWP filed a reply in support of the petition on May 31, The Utah Supreme Court is not obligated to accept the petition for certiorari, and no prediction can be made as to whether that court will accept LADWP s petition for review, or, if it does, whether the court will then affirm, reverse, or modify the decision of the court of appeals. There is no deadline by which the court must act on the petition. If the court denies the petition for review, the court of appeals decision will stand, and the case will be returned to the trial court for further pretrial proceedings. Prior to the appeal being taken, the trial court had decided that in the event of trial, there would be several trials, given the number of farms, with the first trial to include six dairies as chosen by the parties. However, the judge that handled this case has since been reassigned to a different district, and it has not been determined whether that same judge will opt to retain this litigation. If the same judge does not do so, the case will be assigned to a new judge, and that judge may decide to proceed differently. The City is unable to predict what decisions any judge in the Utah Dairy Case may make. LADWP has indicated that electrical tests performed by LADWP s experts reveal no current or voltage attributable to the IPP facilities on the Utah plaintiffs farms, and LADWP believes that their claims are without merit. LADWP has indicated that in the event that damages are awarded to the Utah plaintiffs against IPA, any part of the award not otherwise covered by insurance may be apportioned among utilities that purchase IPP capacity in accordance with their entitlement shares. The City cannot predict the final resolution of the Utah Dairy Case or its impact on the IPP or the IPP Purchasers. The City s entitlement in the Generation Station has historically accounted for between one-third and onehalf of the Electric System s total energy resources. The Generation Station also represents the City s largest source of electricity generated by coal-fired plants. SB 1368 and other recent legislation may cause the City to decrease its reliance on electricity generated by burning coal. See DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS State Legislation. Hoover Uprating Project. Modern insulation technology made it possible to uprate the nameplate capacity of existing generators (the Hoover Uprating Project ). The Hoover Uprating Project consists principally of the uprating of the capacity of the 17 existing generating units at the hydroelectric power plant of the Hoover Dam, located approximately 25 miles from Las Vegas, Nevada. The City along with the cities of Azusa, Banning, Burbank, Colton, Glendale, Pasadena, Riverside and Vernon have obtained entitlements totaling 127 MW of capacity and approximately 143,000 MWh of allocated energy annually from the Hoover Uprating Project. In 1987, to reflect these entitlements, these cities entered into contracts with the United States Bureau of Reclamation (the Bureau ) providing for the advancement of funds for the uprating and with the Western Area Power Administration ( Western ) for the purchase of power from the Hoover Uprating Project. Subsequently, the City along with the cities of Riverside, Burbank, Azusa, Colton and Banning (the Hoover Participants ) entered into assignment agreements with SCPPA to assign their entitlements in return for SCPPA s agreement to provide funds to the Bureau to pay for the Hoover Participants share of the Hoover Uprating Project costs. Based on allocations and the assignment agreements of Western, SCPPA s proportionate share of the total capacity of the Hoover Uprating Project is approximately 94 MW along with the energy allocation. The Hoover Participants and SCPPA have executed power sales contracts under which the Hoover Participants have agreed to make monthly payments on a take-or-pay basis in exchange for their shares of SCPPA s proportionate share of Hoover capacity and allocated energy (the Hoover Entitlements ). The City s entitlement in the Hoover Uprating Project is 40 MW. A portion of the Hoover Entitlements became available in June 1987 under the thirty-year agreement and the full entitlement became available in June Western delivers the City s entitlement at the Mead Substation. The Hoover Uprating Project was substantially completed on September 30, The Boulder Canyon Project ( BCP ) contracts administered by the Desert Southwest Region of Western expire on September 30, In an anticipation of the expiration of the Hoover contracts, the contractors including Anaheim introduced legislation to renew the Hoover contracts in On December 21, 2011, the Hoover Power Plant Act of 2011 (Public Law ) (the HPAA ) was enacted into law. The HPAA prescribes certain key aspects for the marketing of the BCP as of October 1, 2017, including specified amounts of contingent capacity and firm energy to be offered by Western to existing BCP Contractors. The HPAA also directs Western to create a 29

36 resource pool of contingent capacity and firm energy to be allocated to new allottees. The new contract terms are currently being developed by Western with input from the current contractors, with the requirement of relinquishing up to 5% of the current entitlement. Under the HPAA, Anaheim will receive capacity and firm energy from Hoover through Mead-Phoenix Transmission Project. The Mead-Phoenix Transmission Project consists of a 256-mile, 500-kV alternating current ( AC ) transmission line that extends between a southern terminus at the existing Westwing Substation (in the vicinity of Phoenix, Arizona) and a northern terminus at Marketplace Substation, a substation located approximately 17 miles southwest of Boulder City, Nevada. The line is looped through the 500-kV switchyard constructed in the existing Mead Substation in southern Nevada with an estimated transfer capability of 1,923 MW (as a result of certain upgrades completed in 2009). By connecting to Marketplace Substation, the Mead-Phoenix Transmission Project interconnects with the Mead-Adelanto Transmission Project (discussed below) and with the existing McCullough Substation. The Mead-Phoenix Transmission Project is comprised of three project components. SCPPA has executed an ownership agreement providing it with an % member-related ownership share in the Westwing-Mead project component, a % member-related ownership share in the Mead Substation project component, and a % member-related ownership share in the Mead-Marketplace project component. Other owners of the line are Arizona Public Service Company ( APS ), M- S-R Public Power Agency, Salt River Project and the City of Vernon. SCPPA has sold, on a take-or-pay basis, the entire capability of its member-related ownership interest through transmission service contracts (the Transmission Service Contracts ) with nine members of SCPPA (all of SCPPA members, including the City, but with the exception of the Imperial Irrigation District ( IID ) and the City of Vernon). The City s entitlement share in these three components is 3.615%, % and %, respectively of the SCPPA members-related ownership interest. SCPPA has two separate and independent ownership interests in this project: one interest for SCPPA s members participating in the project, and one interest for Western which provides the funding for that interest. The construction cost for the project was approximately $230 million, of which $44 million was SCPPA s memberrelated share. The commercial operation date for the project was April 15, The Mead-Phoenix Transmission Project, as well as the Mead-Adelanto Transmission Project, are used for the transmission of energy purchased by the City. Mead-Adelanto Transmission Project. In connection with the Mead-Phoenix Transmission Project, certain members of SCPPA, including the City, and other utilities have undertaken the Mead-Adelanto Transmission Project. The Mead-Adelanto Transmission Project consists of a 202-mile, 500-kV AC transmission line that extends between a southwest terminus at the existing Adelanto Substation in southern California and a northeast terminus at Marketplace Substation, a new substation located approximately 17 miles southwest of Boulder City, Nevada. By connecting to Marketplace Substation, the new line interconnects with the Mead-Phoenix Transmission Project and the Mead-Adelanto Transmission Project interconnects with the existing McCullough Substation in southern Nevada. The new line has an estimated initial transfer capability of 1,200 MW. SCPPA has executed an ownership agreement providing it with a total of a % member-related ownership share in the project. The other owners of the line are M-S-R Public Power Agency and the City of Vernon. The City s entitlement share is % of SCPPA s member-related ownership interest. SCPPA has sold the entire capability of its member-related ownership interest, on a take-or-pay basis, through transmission service contracts with nine members of SCPPA (all of the SCPPA members with the exception of IID and the City of Vernon). SCPPA has two separate and independent ownership interests in this project: one interest for SCPPA s members participating in the project, and one interest for Western which provides the funding for that interest. The construction cost for the project was $204 million, of which $140 million was SCPPA s member-related share. The commercial operation date for the project was April 15, 1996, which coincided with the completion of the Mead-Phoenix Transmission Project. Magnolia Power Project. The Magnolia Power Project is a clean burning, high efficiency, gas-fired, combined cycle electric generating unit on five acres of the existing Burbank Water & Power generating station complex adjacent to Magnolia Boulevard in the City of Burbank. The Magnolia Power Project is owned by SCPPA and was constructed for the primary purpose of providing participants, including the City, with firm capacity and energy to help meet their power requirements. The total project cost was approximately $275 million, with estimated annual operating costs ranging from $8 million to $10 million, plus natural gas fuel supply costs. The unit was placed in service in September 2005 and operates in a base-load mode (8,000 hours per year or more) with 30

37 staffing by Burbank Water & Power personnel on a 24-hour basis. The City has acquired a 38% (92 MW base capacity and 26 MW peaking capacity) entitlement in the project through a long-term power purchase agreement with SCPPA. In the Fiscal Year ended June 30, 2011, the Magnolia Power Project supplied the City with 434,006 MWh. See Joint Powers Agency Contracts below. Canyon Power Project. The City has acquired an entitlement to 100% of the capacity and energy of the Canyon Power Project, a peaking power plant owned by SCPPA and operated and maintained by the City. The Canyon Power Project consists of a simple cycle natural gas-fired power generating plant (comprised of four generating units), with a combined nominally rated net base capacity of approximately 200 MW, and auxiliary facilities to be located in the City. The Canyon Power Project began commercial operation in phases, with unit 4 going on line in July, with each subsequent unit following a month later. The entire facility was deemed to have reached final completion in October The Canyon Power Project is subject to the New Source Review ( NSR ) air quality permitting program promulgated by the SCAQMD, the agency responsible for developing and enforcing air quality requirements in the South Coast Air Basin (the Basin ), which includes Los Angeles, Riverside, San Bernardino and Orange Counties. The SCAQMD s NSR program is required to comply with certain provisions and requirements established pursuant to federal and State law, including the federal Clean Air Act. The federal Clean Air Act sets standards for different types of air pollutants and allows states to create plans to address pollution in areas with unclean air. These programs may include emission offset trading programs that require new sources to obtain emission reduction credits ( ERCs ) for every pound of new pollution that they propose to emit. At the end of calendar year 2008, Anaheim procured all the necessary ERCs required for particulate matter (PM 10 ) and sulfur dioxide (SO X ) required for the operating parameters for the Canyon Power Project. Natural Gas Reserves Project. The City has joined several members of SCPPA in acquiring natural gas reserves as a source of long-term supply of gas at a levelized price to provide fuel for the Magnolia Power Project. As a base-load combined-cycle facility, the City s operating share of fuel requirements for operating the Magnolia Power Project amounts to approximately 4.5 billion cubic feet of natural gas per year. Part of the City s overall natural gas portfolio strategy is to provide a portion of that natural gas through long-term, fixed price gas supplies, either through long-term gas supply contracts or gas reserve field acquisition. On June 7, 2005, the City entered into a Gas Sales Agreement with SCPPA pursuant to which the City purchases natural gas and acquired interests in gas reserve fields and related facilities. Through this Gas Sales Agreement, the City has acquired a project entitlement share in SCPPA s first gas field at a cost of approximately $16.4 million that ultimately is expected to provide over 15% of the City s gas requirements for the Magnolia Power Project. The City has taken delivery of this gas since July Since that time, the City has acquired interests in a second gas field in Texas at a cost of approximately $18.6 million that is expected to ultimately provide an additional 15% of the City s gas needs at Magnolia. Prepaid Natural Gas Financing. The City and several members of SCPPA completed a prepaid natural gas financing to secure another source of long-term supply of gas to provide fuel for the Magnolia Power Project and other gas-fired generation stations. In connection with the prepaid natural gas financing, the City entered into a natural gas supply agreement with SCPPA pursuant to which the City purchases natural gas beginning on July 1, 2008 at a discount from the spot price over a term of approximately 30 years (now a term of 27 years as a result of the restructuring described below). On October 22, 2009, SCPPA restructured its prepaid natural gas sales agreements relating to this financing, to provide an acceleration of a portion of the long-term savings, reduce the remaining volumes of gas to be delivered and shorten the overall duration of the agreements. Anaheim s restructured natural gas supply agreement with SCPPA is expected to provide approximately 13% of the City s gas requirements for the Magnolia Power Project. The projects described above under the captions City Owned Resources and Non-City Owned Resources are subject to the other parties involved in those projects meeting their respective obligations with respect to such projects (except the Prepaid Natural Gas Financing and the Canyon Power Project). If a party defaults on its payment obligations, then the non-defaulting parties, subject to the utilization of any reserves, may be required to expend additional funds with respect to such project. If a non-defaulting party does step up to the 31

38 payment obligation of a defaulting party, the non-defaulting party is entitled to the capability or output of the defaulting party s share of the project. Renewable Energy Resources. The City has purchased 32 MW of wind generated energy from PPM Energy under two separate contracts. Wind energy typically comes with a 33% load factor, so the PPM Energy contracts effectively represent 12 MW of resources. The first contract is delivered flat at 2 MW and priced at $53.50/MWh which is fixed over the 20-year life of the contract, effective July 1, The second contract for 30 MW (effectively 10 MW) is priced at $55/MWh which is also fixed over the life of the contract with a 20-year term effective July 1, This contract is deemed as-available and delivered through the Northern Transmission System at the Mona interconnection tie in the LADWP control area. The City receives and pays for energy only when the units are operating. The City has contracted with Ormat Technologies, through SCPPA, for a geothermal project with the City s share of the project totaling 8.4 MW. The project came on line on January 1, 2006 and is priced at $57.50/MWh with an annual escalation rate of 1.5% per year. The energy is delivered at the interconnection with IID at the Mirage Interconnection tie. The term of the contract is for a minimum of 15 years with an option to extend an additional five years. The City executed Power Purchase Agreements with Brea Power Partners, LP to deliver landfill gas renewable energy. The first contract is a short-term 5 MW contract with a start date of April 1, 2007 (with power received commencing July 9, 2007) through the commercial operation date of the second contract or December 31, The price was $69.00/MWh through December 31, 2008 and then increased to $71.00/MWh on January 1, 2009, with an annual price escalation thereafter of 2% commencing January 1, The second is a long-term 27 MW contract that will start when commercial operation commences (which is expected to occur in October 2012). The 27 MW contract expires 33 years after the commercial operation date. The price is $112.5/MWh with no escalation over the term of the contract. The City executed two Power Purchase Agreements with two different Raser Technologies subsidiary corporations for two geothermal projects of 11 MW each. The projects are located in central Utah and will be delivered to the City at the NTS at the Mona interconnection tie in the LADWP control area. The terms and conditions of the two contracts are identical with the exception of the location of each unit. The energy cost for each facility is $78/MWh with a 2% annual escalation factor. There is an additional transmission cost to the City of $2.98/MWh to get delivery to the Mona interconnection point. The first project began commercial operation in April The term for the agreement is 20 years. The second project was put on hold due to increased costs of construction. On or about April 29, 2011 Raser Technologies, Inc. and its Affiliated Debtors filed voluntary petitions for relief under the Bankruptcy Code. The Bankruptcy Court on August 30, 2011 confirmed the Third Amended Plan of Raser Technologies, Inc. and its Affiliated Debtors with a Plan effective date of September 9, The Bankruptcy Court approved one of the reorganized subsidiary corporation s assumption of its Power Purchase Agreement with the City, but not the other so the City only has the one geothermal project in central Utah. The City has contracted with The Metropolitan Water District of Southern California, through SCPPA, for 10 MW of hydro electricity from a variety of small power plants located at various sites within the Los Angeles Basin. The power is run-of-the-river hydro as opposed to storage hydro and as such, is deemed energy as available, much like wind. The power is priced at $94.83/MWh, and delivery began November 1, The contract has an initial term of five years with renewable options up to 15 years. Consistent with State legislation, the City has adopted a Renewable Portfolio Standard (the RPS ) that sets a target of increasing its purchases of eligible renewable energy resources to 33% by The City is on track to reach the 33% by the 2020 target. See DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS State Legislation Renewable Portfolio Standards. Certain of the projects described above under the captions City Owned Resources and Non-City Owned Resources are subject to the other parties involved in those projects meeting their respective payment obligations with respect to such projects. If a party defaults on its payment obligations, then the non-defaulting parties, subject 32

39 to the utilization of any reserves, may be required to expend additional funds with respect to such project. If a nondefaulting party does step-up to the payment obligation of a defaulting party, the non-defaulting party is entitled to the capability or output of the defaulting party s share of the project. Anaheim s CAISO Arrangements The CAISO began operations on March 31, The fundamental purpose of the CAISO is to operate the transmission system in a manner that is independent of the interests of the owners of the transmission facilities to buy or sell energy. This purpose is accomplished by the CAISO providing transmission service and related ancillary services to all users, including the City, on a non-discriminatory basis. In June 2002, the City notified the CAISO of its intent to become a Participating Transmission Owner ( PTO ) by turning over operational control of the City s transmission entitlements. In November 2002, Anaheim executed the Transmission Control Agreement ( TCA ) between the CAISO and the PTOs. On January 1, 2003, the City became a PTO under the CAISO tariff by turning over operational control of its transmission entitlements to the CAISO. In return, the City receives payment of its revenue requirement for such facilities from the CAISO. The City now obtains all of its transmission scheduling requirements from the CAISO and it procures additional ancillary services required from the CAISO or from the open competitive market. At this time, the City s transmission revenue requirement has been approved by Federal Energy Regulatory Commission ( FERC ), and there are no outstanding contested issues associated with the City s transmission revenue requirement. Certain of the CAISO-Transferred Facilities were financed by SCPPA utilizing tax-exempt bonds (the SCPPA Transmission Bonds ). The City has executed certain transmission service contracts with SCPPA that prohibit the City from taking any action that would adversely affect the tax-exempt status of the SCPPA Transmission Bonds. If the City were to be found to have breached such contractual obligation, the City could be subjected to significant financial liability. The TCA contains certain withdrawal provisions which the City believes will protect the tax-exempt status of the SCPPA Transmission Bonds and will satisfy its contractual obligation to SCPPA under its transmission service contracts. Historical Financial Results The following table shows a summary of the financial results of the Electric System, together with calculation of debt service coverage of outstanding Electric System obligations for the five Fiscal Years shown. [Remainder of page intentionally left blank] 33

40 TABLE 9 CITY OF ANAHEIM ELECTRIC UTILITY FUND, FINANCIAL RESULTS OF THE ELECTRIC SYSTEM ($000) Fiscal Year Ended June 30, Ten Months ended 04/30/12 (Unaudited) Ten Months ended 04/30/11 (Unaudited) Revenues Sale of electricity: Residential $ 69,383 $ 65,547 $ 76,620 $ 74,327 $ 72,204 $ 65,681 $ 62,000 Commercial 84,670 80,090 96,416 84,981 76,196 72,014 66,420 Industrial 106, , , , , , ,624 Other 1,993 2,441 2,875 2,974 3,444 3,788 3,247 Other Utilities (wholesale) 17,189 19,039 21,039 35,409 27,821 22,228 28,835 Billed revenue from sale of electricity $ 279, ,590 $ 320,333 $ 316,920 $ 302,541 $ 280,960 $ 268,126 Change in unbilled electric revenue 0 0 1,228 1,456 (1,778) 3,620 (635) Total revenue from sale of electricity $ 279,798 $ 269,590 $ 321,561 $ 318,376 $ 300,763 $ 284,580 $ 267,491 RSA revenue 21,500 32,000 22,500 31,200 30,700 21,800 5,000 Other (including general interest income) 38,721 35,407 47,157 40,788 47,453 67,462 57,930 Total gross revenues $ 340,019 $ 336,997 $ 391,218 $ 390,364 $ 378,916 $ 373,842 $ 330,421 Expenses (excluding depreciation and amortization): Cost of purchased power (1) $ 211,418 $ 214,494 $ 239,339 $ 236,208 $ 229,595 $ 235,301 $ 198,957 Fuel and generation (2) 16,382 15,752 21,921 26,981 25,763 25,382 35,153 Operations & Maintenance (2) 37,989 37,428 42,707 45,923 44,911 38,851 31,229 Right of Way fee 4,005 3,922 4,713 4,555 4,262 3,655 3,528 Total expenses $ 269,794 $ 271,596 $ 308, ,667 $ 304,531 $ 303,189 $ 268,867 Net revenues(a) 70,225 65,401 82,538 76,697 74,385 70,653 61,554 Senior Bond debt service ,784 6,829 requirements(b) (3) Deposits to Renewal and Replacement ,792 2, Account Surplus Revenues(c) $ 70,225 $ 65,401 $ 81,944 $ 76,427 $ 72,593 $ 61,564 $ 54,043 Qualified Obligations purchase 36,552 33,529 40,234 39,371 35,622 28,379 22,689 payments(d) (4) Second Lien Qualified Obligations(e) (5) 7,013 7,013 8,416 8,412 8,546 8,977 8,973 Net revenues after debt service payments $ 26,660 $ 24,859 $ 33,294 $ 28,644 $ 28,425 $ 24,208 $ 22,381 Transfers (to) Anaheim General Fund (7,108) (7,708) (16,042) (14,122) (28,933) (6) (12,393) (12,331) Transfers (to)/from other Anaheim funds 0 0 2,153 1,276 (1,263) (5,610) (456) Balance for other purposes $ 19,552 $ 17,151 $ 19,405 $ 15,798 $ (1,771) $ 6,205 $ 9,594 Senior Bond debt service coverage (a/b) N/A N/A N/A N/A N/A 10.4x 9.0x Qualified Obligation (incl. Second Lien) 1.6x 1.6x 1.7x 1.6x 1.6x 1.6x 1.7x debt service coverage (c/(d +e)) (1) Includes take-or-pay obligations with joint powers agencies. The significant increase from Fiscal Year 2007 to Fiscal Year 2008 was due primarily to an unplanned four month outage at San Juan resulting in increased generation at Magnolia (at a higher variable cost due to increased natural gas prices) and increased market purchases. (2) Fuel and generation includes all expenses associated with the operation of CT Plant, SONGS and San Juan. SONGS generation was terminated during Fiscal Year (3) As of June 30, 2009, all Senior Bonds have been retired. (4) Qualified Obligations outstanding at April 30, 2012 include $90,390,000 Anaheim Public Financing Authority Revenue Bonds, Series 2011-A, $67,765,000 Anaheim Public Financing Authority Revenue Bonds, Series 2009-A, $201,040,000 Anaheim Public Financing Authority Distribution System Revenue Bonds, Series 2007; $29,640,000 Anaheim Public Financing Authority Revenue Refunding Bonds, Series 2003; $164,310,000 Anaheim Public Financing Authority Revenue Bonds, Series 2002; and $34,650,000 Anaheim Public Financing Authority Revenue Bonds, Series (5) Second Lien Qualified Obligations outstanding at April 30, 2012 include $113,960,000 Anaheim Public Financing Authority Distribution System Revenue Bonds, Series (6) In Fiscal Year 2009, the Anaheim Public Utilities Department made a one-time change to move from paying in arrears to paying currently. 34

41 Transfers of Electric System funds to the City s General Fund are being made on a monthly basis. Under the Charter, annual transfers are limited to 4% of gross revenues of the Electric Revenue Fund for the prior Fiscal Year. Total gross revenues for the Fiscal Year ended June 30, 2011 of $391 million represent a $0.9 million increase from the prior Fiscal Year, which is due to a $3.2 million increase from the sale of electricity and a $6.4 million increase in other revenues, offset by an $8.7 million decrease in RSA revenues. The $3.2 million increase in electricity sales was due to a $17.5 million increase in retail sales offset by a $14.4 million decrease in wholesale energy revenues. The increase in retail sales was due to a 10.7% increase in average system retail rates in response to increasing power costs during the year. Wholesale sales were lower due to a combination of wholesale sales volume declining by 32% and wholesale average prices declining by 5% in this Fiscal Year. The $6.4 million increase in other revenues was mainly due to an increase in surplus natural gas revenues. When Magnolia and the Kraemer CT Plant experienced outages, less natural gas was used and more surplus gas could be sold back in the spot market. The $8.7 million decrease in RSA revenues was due to only $22.5 million RSA revenues being recognized to offset the increase in power costs and to keep debt service coverage on target. Total operating expenses of $308.7 million for the Fiscal Year ended June 30, 2011 represent a decrease of $5.0 million from the prior Fiscal Year. The $5.0 million decrease in expenses was mainly due to a $5.1 million decrease in fuel and generation expenses that were the combination of a decrease in decommission expenses for SONGS and decreased operation and maintenance expenses for the Kraemer CT Plant. Accounting Policies The Electric System s accounting records, financial transactions and billing are computerized. Annual audits of the Electric System are made by the City s independent auditor. The Electric System audit is made simultaneously with the audits of the other City financial activities. Funds of the Electric System are separated from the General Fund of the City and the books and records are maintained separate and apart from all other funds and accounts of the City. For further information concerning the Electric System s financial position, please refer to the audited financial statements of the Anaheim Electric Utility Fund for the Fiscal Year ended June 30, 2011 and June 30, 2010 attached hereto as Appendix A, including Management s Discussion and Analysis of Operations and Financial Condition therein. The City s financial statements for the Fiscal Years ended June 30, 2011 and June 30, 2010, included in Appendix A hereto, have been audited by KPMG LLP, certified public accountants. KPMG LLP was not requested to consent to the inclusion of its report in Appendix A and it has not undertaken to update its report or to take any action intended or likely to elicit information concerning the accuracy, completeness or fairness of the statements made in this Official Statement, and no opinion is expressed by KPMG LLP with respect to any event subsequent to the date of its report. Joint Powers Agency Contracts As previously discussed, the City participates in or contracts with several joint powers agencies, including IPA and SCPPA. Obligations of the City under the agreements with IPA and SCPPA constitute Maintenance and Operation Expenses of the City payable prior to any of the payments required to be made with respect to Qualified Obligations, including the Purchase Payments. Agreements between the City and IPA and the City and SCPPA (other than the agreement relating to SCPPA s Prepaid Natural Gas Project bonds) are on a take-or-pay basis, which requires payments to be made whether or not applicable projects are completed or operable, or whether output from such projects is suspended, interrupted or terminated. All of these agreements (other than the agreements relating to SCPPA s Prepaid Natural Gas Project bonds, the Natural Gas Reserves bonds and the Canyon Power Project bonds) contain step up provisions obligating the City to pay a share of the obligations of a defaulting 35

42 participant. The City s participation and share of debt service obligation (without giving effect to any step up provisions) for each of the joint powers agency projects in which it participates are shown in the following table. TABLE 10 OUTSTANDING DEBT OF JOINT POWERS AGENCIES AND ANAHEIM SHARE As of July 15, 2012 Principal Amount of Outstanding Debt Anaheim s Participation (1) Anaheim s Share of Principal Amount of Outstanding Debt (2) Intermountain Power Agency Intermountain Power Project (3) $2,190,575, % $ 289,703,544 Southern California Public Power Authority Southern Transmission System $ 755,700, % $ 133,358,379 Hoover Dam Uprating 11,355, ,831,893 Magnolia Power Project (4) 340,260, ,025,376 Mead-Phoenix Transmission 45,025, ,896,050 Mead-Adelanto Transmission 147,415, ,901,025 Prepaid Natural Gas Project 322,360, ,189,400 Natural Gas Reserves (5) 56,520, ,520,000 Canyon Power Project 301,470, ,470,000 Total $4,170,680,000 $1,004,895,667 (1) Obligation is subject to increase upon default of another Project Participant (other than with respect to SCPPA s Natural Gas Prepaid bonds, the Natural Gas Reserves bonds and the Canyon Power Project bonds). (2) Excludes interest on the debt. (3) Includes commercial paper, subordinate notes and full accreted value at maturity for any capital appreciation bonds. Inclusive of the IPP Excess Power Sales Agreement, after reduction for portion withdrawn by Utah members in accordance with such Agreement. (4) Excludes bonds relating solely to City of Cerritos. (5) Not a take-or-pay obligation; the City must pay for contracted natural gas only to the extent delivered. Source: Anaheim. For the Fiscal Year ended June 30, 2012, the City's payments of debt service on its joint powers agency obligations aggregated approximately $90.5 million. Annual debt service on the City's joint powers agency obligations is expected to increase to a high of approximately $96.0 million in Fiscal Year 2013, but is expected to decline to approximately $40.2 million in Fiscal Year This projection assumes no future debt issuances and further assumes that the annual interest rate on unhedged variable rate joint powers agency debt obligations (i.e., joint powers agency obligations not otherwise fixed through interest rate swap agreements) will be 3.5%. As of July 1, 2012, approximately 7.9% of the joint powers agency obligation debt service was unhedged variable rate debt, including outstanding commercial paper. Unreimbursed draws under liquidity arrangements supporting joint powers agency variable rate debt obligations bear interest at a maximum rate substantially in excess of the assumed rates stated above. Labor Relations The Department has a total of 355 full-time and 42 part-time authorized positions. Of these positions, 158 full-time employees and 16 part-time employees are represented by the International Brotherhood of Electrical Workers ( IBEW ) Local 47. In addition to the IBEW, the Anaheim Municipal Employees Association ( AMEA ) represents 24 full-time employees of the Department. There are no part-time employees represented by AMEA. The City has reached agreements with IBEW and AMEA to extend their memoranda of understanding through July 2, 2013 and January 3, 2014, respectively. The City has not experienced any strike, work stoppage or other labor action by the Department s employees in the last five years. 36

43 Retirement Programs All permanent employees of the City are covered under the California Public Employees Retirement System ( PERS ), a public employee, defined benefit pension plan. The City s required contributions to PERS during Fiscal Year amounted to $51,913,000, of which $4,025,000 was allocated to the Electric System. As of June 30, 2010 (the most recent actuarial valuation date), the plan was 81.9% funded and the actuarial accrued liability for benefits was $1,805,198,000, resulting in an unfunded actuarial accrued liability of $326,415,000. As of June 30, 2011, PERS participants were required to contribute 8% (9% for public safety employees) of their annual covered salary. For Electric System employees, the City pays 7% of the participant contributions and the employee pays 1%. The City is also required to contribute all remaining amounts necessary to fund the benefits for its members, using the actuarial basis recommended by PERS actuaries and actuarial consultants and adopted by the PERS Board of Administration. The Electric System is allocated its portion of the City s required contribution as determined by PERS actuaries. The Electric System contributed 100% of its allocated required contributions of $4,025,000, $4,109,000 and $4,044,000 to PERS for the Fiscal Years ended June 30, 2011, 2010 and 2009, respectively. In addition to the defined benefit pension plan described above, the City also maintains a program providing other post-employment benefits ( OPEB ) to eligible retirees, including health care and disability coverage and death benefits. The City made significant changes to its OPEB program during Fiscal Year For City employees hired prior to January 1, 1996 (other than those represented by the Anaheim Police Association, the Anaheim Fire Association or the IBEW), the length of service credit was frozen for all employees eligible for the benefit. Length of service, a factor in determining the amount of the benefit earned, will not accrue beyond December 31, Employees hired on or after January 1, 1996 (other than those represented by the Anaheim Police Association or the Anaheim Fire Association) are no longer eligible for City funding of all or a portion of post-retirement medical benefits. For City employees represented by the IBEW who had not retired as of October 15, 2005, benefits for future retirees are to be provided through a trust established by the IBEW. Benefits are determined by the trustees of the trust and the City s liability is limited to specified percentages of employee pay. City employees hired on or after January 1, 1996 and before January 1, 2002 (other than those represented by the Anaheim Police Association, the Anaheim Fire Association or the IBEW) were transitioned from the former defined benefit post-retirement medical plan to a defined contribution post-retirement medical plan. The City made a one-time contribution of $1,685,000 to a newly established retiree health savings account for those eligible employees at the end of the year. Participation in the retiree health savings account is mandatory for this transitional group of employees. In all cases, eligible retirees may participate in any health plan made available to active City employees. The City has several plans with different contribution levels and benefit provisions. City contributions vary up to 100% of annual premium cost, depending on the employee s Medicare eligibility, year of hire, age and employee group. At June 30, 2011, 1,305 retirees or surviving spouses met the various eligibility requirements and were receiving benefits. The City s contributions toward the cost of its OPEB program are generally advance funded on an actuarial basis to a dedicated reserve, but annual contributions are not required. During Fiscal Year , the City s contribution to the post-retirement medical plan was $10,266,000. Governmental Accounting Standards Board Statement No. 45 has required the City to account for and disclose its OPEB liability since Fiscal Year The Electric System does not separately account for its allocable portion of the cost of pension and OPEB benefits funded, the actuarially computed present value of vested and nonvested accumulated plan benefits, the related assumed rates of return used, and the actuarially computed value of vested benefits over the related pension and OPEB fund assets. 37

44 DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS State Legislation A number of bills affecting the electric utility industry have been introduced or enacted by the California Legislature in recent years. In general, these bills regulate greenhouse gas emissions and provide for greater investment in energy-efficiency and environmentally friendly generation alternatives through more stringent renewable resource portfolio standards. The following is a brief summary of certain of these bills that have been enacted. Greenhouse Gas Emissions. On June 1, 2005, then Governor Arnold Schwarzenegger signed Executive Order S-3-05, which placed an emphasis on efforts to reduce greenhouse gas emissions by establishing statewide greenhouse gas reduction targets. The targets are: (i) a reduction to 2000 emissions levels by 2010; (ii) a reduction to 1990 levels by 2020; and (iii) a reduction to 80% below 1990 levels by The Executive Order also called for the California Environmental Protection Agency to lead a multi-agency effort to examine the impacts of climate change on California and develop strategies and mitigation plans to achieve the targets. On April 25, 2006, then Governor Schwarzenegger also signed Executive Order S which directs the State to meet a 20% biomass utilization target within the renewable generation targets of 2010 and 2020 for the contribution to greenhouse gas emission reduction. Then Governor Schwarzenegger signed Assembly Bill 32, the Global Warming Solutions Act of 2006 (the GWSA ), which became effective as law on January 1, The GWSA prescribed a statewide cap on global warming pollution with a goal of returning to 1990 greenhouse gas emission levels by In addition, the GWSA establishes a mandatory reporting program for all IOUs, local, publicly-owned electric utilities ( POUs ) and other load-serving entities (electric utilities providing energy to end-use customers) to inventory and report greenhouse gas emissions to the California Air Resources Board ( CARB ), requires CARB to adopt regulations for significant greenhouse gas emission sources (allowing CARB to design a cap-and-trade system) and gives CARB the authority to enforce such regulations beginning in On December 11, 2008, CARB adopted a scoping plan to reduce greenhouse gas emissions. The scoping plan set out a mixed approach of market structures, regulation, fees and voluntary measures. The scoping plan included a cap-and-trade system covering approximately 85% of all greenhouse gas emissions in California. In August 2011, CARB revised the scoping plan in response to litigation. The revised scoping plan continues to include a cap-and-trade system. On October 20, 2011, CARB adopted a regulation implementing a cap-and-trade system. The California Office of Administrative Law ( OAL ) approved the regulation on December 13, The cap-and-trade regulation became effective on January 1, 2012, and it provides for emission compliance obligations to begin on January 1, The cap-and-trade program covers sources accounting for 85% of California s greenhouse gas emissions, the largest program of its type in the United States. The cap-and-trade program will be implemented in phases. The first phase of the program (January 1, 2013 to December 31, 2014) will introduce a hard emissions cap that covers emissions from electricity generators and large industrial sources emitting more than 25,000 metric tons of carbon dioxide-equivalent greenhouse gases ( CO 2 e ) per year. In 2015, the program will be expanded to cover emissions from transportation fuels, natural gas, propane and other fossil fuels. The cap will decline each year. The cap-and-trade program will include the distribution of carbon allowances. Each allowance will be equal to one metric ton of CO 2 e. As part of a transition process, initially, most of the carbon allowances will be distributed for free. Additional allowances will be auctioned quarterly, beginning in November Utilities can acquire more carbon allowances at these auctions. IOUs, as well as POUs that sell electricity into the CAISO markets, will be required to auction their allowances. They will then need to purchase allowances to meet their compliance obligations, and use any remaining proceeds from the sale of their allocated allowances for the benefit of their ratepayers. POUs that do not sell into the CAISO markets have three options (which are not mutually 38

45 exclusive) once their allocated allowances are distributed to them. They can (i) place allowances in their compliance accounts to meet compliance obligations for plants they operate directly, (ii) place allowances in the compliance account of a joint powers agency or public power utility that generates power on their behalf, and/or (iii) auction the allowances and use the proceeds to benefit their ratepayers. The cap-and-trade program will also allow covered entities to use offset credits for compliance purposes (not exceeding 8% of a covered entity s compliance obligation). Offsets can be generated by emission reduction projects in sectors that are not regulated under the cap-and-trade program. Approved project types include urban forest projects, reforestation projects, destruction of ozone-depleting substances, and livestock methane management projects. CARB is considering additional offset protocols, including emission reductions through changes to rice cultivation practices, and destruction of fugitive coal mine methane. These protocols may be approved in There are a number of issues remaining to be addressed prior to the start of emission compliance obligations in 2013, including linking the California cap-and-trade program to the equivalent program in Quebec, Canada (subject to the approval of Governor Brown pursuant to Senate Bill 1018), and developing and testing a trading and tracking computer system. CARB will work on these issues throughout Linking California s program to additional Canadian cap-and-trade programs may occur in 2013, as part of the Western Climate Initiative. The Western Climate Initiative is a regional effort consisting of California and four Canadian provinces (Quebec, British Columbia, Ontario and Manitoba), which is in the process of establishing a greenhouse gas reduction trading framework. In 2013, CARB may also consider changes to the cap-and-trade program s electricity sector provisions, including provisions relating to electricity imports and resource shuffling. The City is unable to predict at this time the full impact of the cap-and-trade program on the Department s electric utility or on the electric utility industry generally or whether any changes to the adopted program will be made. However, the City could be adversely affected if the carbon emissions of its resource portfolios are in excess of the allowances administratively allocated to them and it is required to purchase allowances on the market to cover their emissions. In addition to the GWSA, Senate Bill 1368 ( SB 1368 ) also became effective as law on January 1, It provides for an emission performance standard, restricting new investments in baseload fossil fuel electric generating resources that exceed the rate of greenhouse gas emissions for existing combined-cycle natural gas baseload generation. SB 1368 allows the California Energy Commission (the CEC ) to establish a regulatory framework to enforce the greenhouse gas emission performance standard for POUs such as the City. The CPUC has a similar responsibility for the IOUs. The regulations promulgated by the CEC were approved by the Office of Administrative Law on October 16, The CEC regulations prohibit any investment in baseload generation that does not meet the emission performance standard of 1,100 pounds of CO 2 per MWh of electricity, with limited exceptions for routine maintenance, requirements of pre-existing contractual commitments, or threat of significant financial harm. In January 2012, the CEC undertook a review of these regulations to ensure there is adequate review of investments in facilities that do not meet the emission performance standard. Changes to these regulations pursuant to this review may affect the City. Additionally, Assembly Bill 1925, signed by then Governor Schwarzenegger on September 26, 2006, requires the CEC to develop a cost-effective strategy for the geologic sequestration and management of industrial carbon dioxide. Energy Procurement and Efficiency Reporting. Senate Bill 1037 ( SB 1037 ) was signed by then Governor Schwarzenegger on September 29, It requires that each POU, including the City, prior to procuring new energy generation resources, first acquire all available energy efficiency, demand reduction, and renewable resources that are cost effective, reliable and feasible. SB 1037 also requires each POU to report annually to its customers and to the CEC its investment in energy efficiency and demand reduction programs. Further, California Assembly Bill 2021 ( AB 2021 ), signed by then Governor Schwarzenegger on September 29, 2006, requires that the POUs establish, report, and explain the basis of the annual energy efficiency and demand reduction targets by June 1, 2007 and every three years thereafter for a ten-year horizon. The City has 39

46 complied with this reporting requirement under AB Future reporting requirements under AB 2021 include (i) the identification of sources of funding for the investment in energy efficiency and demand reduction programs; (ii) the methodologies and input assumptions used to determine cost-effectiveness; and (iii) the results of an independent evaluation to measure and verify energy efficiency savings and demand reduction program impacts. The information obtained from the POUs is being used by the CEC to present the progress made by the POUs towards the State s goal of reducing electrical consumption by 10% within ten years and the greenhouse gas targets presented in Executive Order S In addition, the CEC will provide recommendations for improvement to assist each POU in achieving cost-effective, reliable, and feasible savings in conjunction with the established targets for reduction. Renewable Portfolio Standards. In September 2002, the California Legislature enacted and then Governor Gray Davis signed into law Senate Bill 1078 ( SB 1078 ). SB 1078 requires that the IOUs adopt a Renewable Portfolio Standard ( RPS ) to meet a minimum increase of 1% of retail energy sales needs each year from renewable resources and to meet a goal of 20% of their retail energy needs from renewable energy resources by the year SB 1078 also directed the State s POUs to implement and enforce an RPS that recognizes the intent of the Legislature to encourage development of renewable resources, taking into consideration the impact on a utility s rates, reliability, financial resources, and the goal of environmental improvement. On September 26, 2006, then Governor Schwarzenegger signed Senate Bill 107 ( SB 107 ) into law, which requires IOUs to have 20% of their electricity produced by renewable sources by 2010 and prescribes that POUs meet the intent of the legislation. On November 17, 2008, then Governor Schwarzenegger signed Executive Order S Among other things, Executive Order S provides that the RPS target established for California shall require retail electricity sellers to serve 33% of their loads with eligible renewable energy resources by Since the implementation of SB 1078, the CPUC and the CEC have taken a number of actions designed to assist utilities in achieving the renewable energy goals set by the legislation. In order to help utilities overcome the challenges associated with meeting accelerated RPS goals, the CPUC and the CEC supported the implementation of a renewable energy certificate ( REC ) trading system. In parallel, pursuant to SB 1078, the CEC, collaboratively with the Western Governors Association and the Western Electricity Coordinating Council, has established the Western Renewable Energy Generation Information System ( WREGIS ), which is expected to ensure the integrity of RECs and prevent the double counting of the certificates. The electronic tracking system became operational in The City and SCPPA have elected to use WREGIS to transfer and account for the RECs associated with renewable energy procured by SCPPA on behalf of the City. Senate Bill X1 2 ( SBX1 2 ), the California Renewable Energy Resources Act, was signed into law by Governor Jerry Brown on April 12, SBX1 2 codifies the RPS target for retail electricity sellers to serve 33% of their loads with eligible renewable energy resources by 2020 as provided in Executive Order S As enacted, SBX1 2 makes the requirements of the RPS program applicable to POUs (rather than just prescribing that POUs meet the intent of the legislation as under previous statutes). However, the governing boards of POUs are responsible for implementing the requirements, rather than the CPUC, as is the case for the IOUs. In addition, certain enforcement authority with respect to POUs is given to the CEC and CARB, including authority to impose penalties. SBX1 2 requires each POU to adopt and implement a renewable energy resource procurement plan. The plan must require the utility to procure a minimum quantity of electricity products from eligible renewable energy resources, which may include RECs, as a specified percentage of total kilowatt hours sold to the utility s retail enduse customers to achieve the following targets: (i) an average of 20% for the period January 1, 2011 to December 31, 2013, inclusive; (ii) 25% by December 31, 2016 and (iii) 33% by December 31, 2020 and for all subsequent years. SBX1 2 grandfathers any facility approved by the governing board of a POU prior to June 1, 2010 for procurement to satisfy renewable energy procurement obligations adopted under prior law if the facility is a renewable electrical generation facility as defined in the bill (subject to certain restrictions). Renewable electrical generation facilities include certain out-of-state renewable energy generation facilities if the facility (i) will not cause or contribute to any violation of a California environmental quality standard or requirement, (ii) participates in the accounting system to verify compliance with the RPS program requirements, and (iii) either (a) commenced initial commercial operation after January 1, 2005 or (b) either (x) the electricity is from 40

47 incremental generation resulting from expansion or repowering of the facility or (y) electricity generated by the facility was procured by a retail seller or POU as of January 1, The percentage of a POU s RPS requirements that may be met with unbundled RECs from generating facilities outside California declines over time, beginning at 25% through 2013 and declining to a level of 10% in 2017 and beyond. The CEC is in the process of developing detailed rules to implement SBX1 2. The CEC expects to finalize its RPS regulation in September See also THE ELECTRIC SYSTEM Non-City Owned Resources Renewable Energy Resources for additional information regarding the City s renewable resources. Solar Power. On August 21, 2006, then Governor Schwarzenegger signed into law Senate Bill 1 (also known as the California Solar Initiative ). This legislation requires POUs, including the City, to establish a program supporting the stated goal of the legislation to install 3,000 MW of photovoltaic energy in California. POUs are also required to establish eligibility criteria in collaboration with the CEC for the funding of solar energy systems receiving ratepayer funded incentives. The legislation gives a POU the choice of selecting an incentive based on the installed capacity, starting at $2.80 per watt, or based on the energy produced by the solar energy system, measured in kilowatt-hours. Incentives would be required to decrease at a minimum average rate of 7% per year. POUs also have to meet certain reporting requirements regarding the installed capacity, number of installed systems, number of applicants, amount of awarded incentives and the contribution toward the program s goals. The City has established a program to comply with the requirements of the California Solar Initiative. Future Regulation The electric industry is subject to continuing legislative and administrative reform. States routinely consider changes to the way in which they regulate the electric industry. Recently, both further deregulation and forms of additional regulation have been proposed for the industry, which has been highly regulated throughout its history. The City is unable to predict at this time the impact any such proposals will have on the operations and finances of the City or the electric utility industry generally. Impact of Developments on the City The effect of the developments in the California energy markets described above on the City s Electric System cannot be fully ascertained at this time. Also, volatility in energy prices in California may return due to a variety of factors that affect both the supply and demand for electric energy in the western United States. These factors include, but are not limited to, the adequacy of generation resources to meet peak demands, the availability and cost of renewable energy, the impact of greenhouse gas emission legislation and regulations, fuel costs and availability, weather effects on customer demand, transmission congestion, the strength of the economy in California and surrounding states and levels of hydroelectric generation within the region (including the Pacific Northwest). See OTHER FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY herein. This price volatility may contribute to greater volatility in the revenues of the Electric System from the sale (and purchase) of electric energy and, therefore, could materially affect the City s financial condition. The City undertakes resource planning and risk management activities and manages its resource portfolio to mitigate such price volatility and spot market rate exposure. Federal Energy Legislation OTHER FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY Energy Policy Act of Under the federal Energy Policy Act of 2005 ( EPAct 2005 ), FERC was given refund authority over municipal utilities if they sell into short-term markets, like the ISO markets, and sell eight million MWhs or more of electric energy on an annual basis. In addition, FERC was given authority over the behavior of market participants. Under FERC s authority it can impose penalties on any seller for using a manipulative or deceptive device, including market manipulation, in connection with the purchase or sale of energy or of transmission service. 41

48 EPAct 2005 authorizes 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 requires the creation of an electric reliability organization ( ERO ) to establish and enforce, under FERC supervision, mandatory reliability standards to increase system reliability and minimize blackouts. Failure to comply with such mandatory standards exposes a utility to significant fines and penalties by the ERO. NERC Reliability Standards. EPAct 2005 required FERC to certify an ERO to develop mandatory and enforceable reliability standards, subject to FERC review and approval. The reliability standards apply to users, owners and operators of the Bulk-Power System, as more specifically set forth in each reliability standard. On February 3, 2006, FERC issued Order 672, which certified the North American Electric Reliability Corporation ( NERC ) as the ERO. Many reliability standards have since been approved by FERC. 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 of up to $1 million per violation per day. FERC Order 693 further provided the ERO and Regional Entities with the discretion necessary to assess penalties for such violations, while also having discretion to calculate a penalty without collecting the penalty if circumstances warrant. Other Legislation. Congress has considered and is considering numerous bills addressing United States energy policies and various environmental matters, including bills relating to energy supplies (such as a federal clean energy portfolio standard), global warming 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. The impact that federal clean energy portfolio standard legislation will have on the electric utility industry and business generally, and on the City in particular, depends largely on the specific provisions of the legislation that ultimately become law. Some of the important factors to be addressed in any federal clean energy legislation include the clean energy targets and timelines, the list of fuel types accepted as clean energy, and whether or not existing clean energy sources can be used to meet the targets. The timeline and impact of any such legislation cannot be accurately assessed at this time, but it is expected that any such federal action will have a significant impact on fossil-fueled generation facilities. 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. However, the City is unable to predict the outcome or potential impacts of any possible legislation. CAISO FERC Filings Credit Reforms in Organized Wholesale Markets - Order 741. On October 21, 2010, FERC issued Order 741 which required additional credit protection measures for all independent system operators ( ISOs ) in response to concerns related to the potential financial impacts to markets if ISO participants defaulted on payments. In Order No. 741, FERC adopted reforms to strengthen the credit policies used in organized wholesale electric power markets. Citing its statutory responsibility to ensure that all rates charged for the transmission or sale of electric energy in interstate commerce are just, reasonable, and not unduly discriminatory or preferential, FERC directed regional transmission organizations ( RTOs ) and ISOs to revise their tariffs to reflect the following reforms: implementation of shortened settlement timeframes, restrictions on the use of unsecured credit, elimination of unsecured credit in all financial transmission rights markets, such as the CAISO s CRR market, clarification of legal status to continue the netting and set-off of transactions in the event of bankruptcy, establishment of minimum criteria for market participation, clarification regarding the organized markets administrators ability to invoke material adverse change clauses to demand additional collateral from market participants, and adoption of a twoday grace period for curing collateral calls. On May 25, 2012, the CAISO filed the second tariff change to implement the FERC requirements. It is anticipated that these efforts would be beneficial to the CAISO market, and lessen the impact of any potential participant default. CFTC Dodd-Frank Exemption. On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act ) was signed into law in response to the 2008 crisis in the U.S. financial 42

49 markets as an effort to bring transparency and oversight to derivatives, financial products that derive their value from the fluctuations in price of an underlying commodity. Most, but not all, regulations potentially affecting electric utilities are being promulgated by the Commodity Futures Trading Commission ( CFTC ). On February 7, 2012, ISOs and RTOs filed a joint application with the CFTC seeking an exemption from CFTC oversight. Although the proposed order would, if granted, exempt nearly all of the CAISO s products and services from CFTC oversight, it does not cover bilateral trades with other counterparties (scheduling coordinators), called inter-sc trades, and as currently structured, these would not qualify for an exemption. Inter-SC trades are a feature of CAISO settlements that enables parties to bilateral transactions to allocate certain CAISO costs and charges between them via the CAISO settlement system, rather than through a separate transaction outside CAISO settlements. The main purpose of inter-sc trades in the day-ahead market is to reverse the effects of a double energy settlement, whereby the supplier receives payment both through the CAISO settlement system and under the bilateral contract. Inter-SC trades can also facilitate the allocation of charges for losses, congestion, ancillary services capacity and IFM load uplift calculation. As currently structured, inter-sc trades could be considered swaps under the Commodity Exchange Act, as amended by the Dodd-Frank Act. This would add additional requirements the CAISO, and market participants including Anaheim, because potentially offering even one product regulated by the CFTC would require the CAISO and other market participants, including Anaheim, to comply with the full range of requirements imposed by the Commodity Exchange Act. Based on communications with CFTC staff, the CAISO expects that the CFTC would expand the requested exemption to include inter-sc trades if certain additional conditions are imposed on the transactions. Essentially, scheduling coordinators would have to represent, by entering the inter-sc trades in the CAISO system, that there is a corresponding bona fide bilateral contract, and retain records to establish that. It is anticipated that Anaheim would be able to meet the requirements for exemption, if granted. 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 continuing legislative, regulatory and judicial action regarding such standards and procedures. Consequently, there is no assurance that any City facility or project will remain subject to the laws and regulations currently in effect, will always be in compliance with future laws and regulations or will always be able to obtain all required operating permits. An inability to comply with environmental standards could result in additional capital expenditures, reduced operating levels or the shutdown of individual units not in compliance. In addition, increased environmental laws and regulations may create certain barriers to new facility development, may require modification of existing facilities and may result in additional costs for affected resources. Greenhouse Gas Regulations Under the Clean Air Act. The United States Environmental Protection Agency (the EPA ) has taken steps to regulate greenhouse gas emissions under existing law. In 2009, the EPA issued a final endangerment finding, in which it declared that the weight of scientific evidence requires a finding that six identified greenhouse gases, namely, carbon dioxide, methane, nitrous oxide, hydroflourocarbons, perfluorocarbons, and sulfur hexafluoride, cause global warming, and that global warming endangers public health and welfare. The final rule for the endangerment finding was published in the Federal Register on December 15, As a result of this finding, the EPA is authorized to issue regulations limiting carbon dioxide emissions from, among other things, stationary sources such as electric generating facilities, under the federal Clean Air Act. The Tailoring Rule, published in the Federal Register on June 3, 2010, states that greenhouse gas emissions will be regulated from large stationary sources, including electric generating facilities, if the sources emit more than the specified threshold levels of tons per year of CO 2 e. Large sources with the potential to emit in excess of the applicable threshold will be subject to the major source permitting requirements under the Clean Air Act. Permits would be required in order to construct, modify and operate facilities exceeding the emissions threshold. Examples of such permitting requirements include, but are not limited to, the application of Best Available Control Technology (known as BACT) for greenhouse gas emissions, and monitoring, reporting, and recordkeeping for 43

50 greenhouse gases. The endangerment finding and the Tailoring Rule have been challenged in court, but were upheld on June 26, 2012 in a decision by the U.S. Court of Appeals for the District of Columbia Circuit in Coalition for Responsible Regulation, Inc., et al. v. EPA. This decision may be appealed. On September 22, 2009, the EPA issued the final rule for mandatory monitoring and annual reporting of greenhouse gas emissions from various categories of facilities including fossil fuel suppliers, industrial gas suppliers, direct greenhouse gas emitters (such as electric generating facilities and industrial processes), and manufacturers of heavy-duty and off-road vehicles and engines. This rule does not require controls or limits on emissions, but required data collection to begin on January 1, Such data collection and reporting lays the foundation for controlling and reducing greenhouse gas emissions in the future, whether by way of the EPA regulations under existing Clean Air Act authority or under a new climate change federal law. On December 23, 2010, the EPA announced two settlements with a number of states and environmental groups. The settlements commit the EPA to issuing regulations setting performance standards for greenhouse gas emissions from new, modified, and existing power plants. These standards are to be based on the best demonstrated control technology. On March 27, 2012, the EPA issued its proposed regulations setting performance standards for new power plants. As proposed, the performance standard will apply only to new power plants; it will not apply to existing, modified or reconstructed power plants. In addition, power plants that have been issued a prevention of significant deterioration permit and commence construction within one year will be exempted from application of the new performance standard. The proposed regulations would impose an emissions performance standard of 1,000 pounds of CO 2 per MWh of electricity (averaged over 12 months). (A power plant that uses coal or petroleum coke for fuel would, however, have the option of complying with an alternative annual standard of 1,800 pounds of CO 2 per MWh for 10 years, but would be required to install and operate a carbon capture and storage system thereafter and demonstrate after 30 years that it has emitted no more than 1,000 pounds of CO 2 per MWh on average over that time period). If finalized, this new performance standard would be the most stringent in the country (surpassing the emission performance standard of 1,100 pounds of CO 2 per MWh of electricity imposed by the CEC regulations in California as described under DEVELOPMENTS IN THE CALIFORNIA ENERGY MARKETS State Legislation Greenhouse Gas Emissions ). The regulations were subject to public comment for a period ending on June 25, The EPA has indicated that it has not established a time frame for developing any new performance standard regulations applicable to existing power plants in the near term. On September 28, 2011, the EPA s Office of Inspector General issued a report concluding that the EPA should have followed a more rigorous peer review process in relation to the endangerment finding. The EPA disagreed with this conclusion. In addition, legislation has been introduced in the United States Congress that would repeal the EPA s endangerment finding or otherwise prevent the EPA from regulating greenhouse gases as air pollutants. The City is unable to predict the outcome of these challenges to the EPA s endangerment finding and subsequent rulemaking or the effect that any final rules promulgated by the EPA regulating greenhouse gas emissions from electric generating units and other stationary sources would have on the City and the Electric System. Air Quality National Ambient Air Quality Standards. The Clean Air Act requires that the EPA establish National Ambient Air Quality Standards ( NAAQS ) for certain air pollutants. When a NAAQS has been established, each state must identify areas in its state that do not meet the EPA standard (known as non-attainment areas ) and develop regulatory measures in its state implementation plan to reduce or control the emissions of that air pollutant in order to meet the applicable standard and become an attainment area. The EPA has recently proposed to increase the stringency of the NAAQS for particulate matter. A proposed rule revising the primary and secondary NAAQS for particulate matter was published in the Federal Register on June 29, On September 2, 2011, President Obama directed the EPA to withdraw its proposal to lower the NAAQS for ozone. As a result of this withdrawal, the EPA will now resume the process of issuing non-attainment designations for the ozone NAAQS. Even without lower standards, non-attainment areas for ozone are likely to be designated. These developments may result in stringent permitting processes for new sources of emissions and additional state restrictions on existing sources of emissions. 44

51 Mercury and Air Toxics Standards. On December 16, 2011, the EPA signed a rule establishing new standards to reduce air pollution from coal- and oil-fired power plants under sections 111 (new source performance standards, or NSPS ) and 112 (toxics program) of the Clean Air Act. The final rule was published in the Federal Register on February 16, Under section 111 of the Clean Air Act, the NSPS revises the standards that new coal- and oil-fired power plants must meet for particulate matter, sulfur dioxide, and nitrogen oxides. Under section 112, the new toxics standards set limits on emissions of heavy metals, including mercury, arsenic, chromium, and nickel; and acid gases, including hydrochloric acid and hydrofluoric acid, from existing and new power plants larger than 25 megawatts that burn coal or oil. Power plants have up to four years to meet these standards. While many plants already meet some or all of these new standards, some plants will be required to install new equipment to meet the standards. The City purchases power from coal-fired power stations that may be affected by these new rules, and so the City may be exposed to increased costs. Other Factors The electric utility industry in general has been, or in the future may be, affected by a number of other factors which could impact the financial condition and competitiveness of many electric utilities and the level of utilization of generating and transmission facilities. In addition to the factors discussed above, such factors include, among others, (a) effects of compliance with rapidly changing environmental, safety, licensing, regulatory and legislative requirements other than those described above (including those affecting nuclear power plants), (b) changes resulting from conservation and demand-side management programs on the timing and use of electric energy, (c) changes resulting from a national energy policy, (d) 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, (e) the repeal of certain federal statutes that would have the effect of increasing the competitiveness of many IOUs, (f) increased competition from independent power producers and marketers, brokers and federal power marketing agencies, (g) self-generation or distributed generation (such as microturbines and fuel cells) by industrial and commercial customers and others, (h) 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, (i) effects of inflation on the operating and maintenance costs of an electric utility and its facilities, (j) changes from projected future load requirements, (k) increases in costs and uncertain availability of capital, (l) shifts in the availability and relative costs of different fuels (including the cost of natural gas and nuclear fuel), (m) sudden and dramatic increases in the price of energy purchased on the open market that may occur in times of high peak demand in an area of the country experiencing such high peak demand, such as has occurred in California, (n) inadequate risk management procedures and practices with respect to, among other things, the purchase and sale of energy and transmission capacity, (o) other legislative changes, voter initiatives, referenda and statewide propositions, (p) effects of the changes in the economy, (q) effects of possible manipulation of the electric markets, (r) natural disasters or other physical calamities, including, but not limited to, earthquakes and floods, and (s) changes to the climate. 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. The City is unable to predict what impact such factors will have on the business operations and financial condition of the Electric System, but the impact could be significant. This Official Statement includes a brief discussion of certain of these factors. This discussion does not purport to be comprehensive or definitive, and these matters are subject to change subsequent to the date hereof. Extensive information on the electric utility industry is available from the legislative and regulatory bodies and other sources in the public domain, and potential purchasers of the Bonds should obtain and review such information. 45

52 THE CITY S PUBLIC UTILITIES DEPARTMENT General Description Under the provisions of the California Constitution, the Charter and Title 10 of the Municipal Code of the City, the City owns and operates both the Electric System and the City s water system (the Water System ) for the citizens of the City. The Public Utilities Department exercises jurisdiction over both the Electric System and the Water System and is under the supervision of the Public Utilities General Manager (the General Manager ). The General Manager is responsible for the supervision of the design, construction, maintenance and operation of both the Electric System and the Water System. The Finance Director of the City is charged with the accounting and the administration of the financial affairs of the City. The General Manager and Finance Director are under the direction of the City Manager who is appointed by the City Council. The Department provides electricity as well as water to virtually all the residential, commercial and industrial customers within the City limits. The funds and accounts of the Electric System and the Water System are held separately, and the funds and accounts of one system are not pledged to the other system s obligations. Management of the Public Utilities Department Marcie L. Edwards, Public Utilities General Manager, has been with the Public Utilities Department since January Ms. Edwards has a Bachelor of Science degree in Organizational Management and a Master of Public Administration degree from the University of La Verne. She has full management responsibility to plan, direct and manage the day-to-day activities and operations of the Department. Ms. Edwards has 36 years of utility industry experience. Starting in 1978, Ms. Edwards earned a Los Angeles City Unlimited Steam Engineer license and was responsible for operating steam generation facilities of various sizes at the Los Angeles Department of Water and Power ( LADWP ). Moving in 1985 to the LADWP electric operations group, Ms. Edwards ultimately took over as Energy Control Center Manager where she managed power grid operations and wholesale marketing activities. In 1994, Ms. Edwards was appointed as Manager of Bulk Power Operations & Maintenance and subsequently became the Director over the Bulk Power Business Unit for LADWP in As Director, Ms. Edwards provided management oversight for various energy related functions, including power flow analysis, power contracts, wholesale trading, regulatory activities, and transmission grid operations. Finally, in 1998, Ms. Edwards became the Assistant General Manager of the LADWP Marketing and Customer Service Organization. This organization was comprised of two business units; Customer Service with over 1,400 employees providing all customer related services including Call Center operations, meter reading, and billing, and the Marketing Business Unit, providing account management, rate analysis, energy audits, and new program development. Ms. Edwards is currently a member of the American Public Power Association Board of Directors, Region 6, Southwest, Intermountain Power Project Coordinating Committee, the American Water Works Association and recently served as the President of the Board of Directors of SCPPA and as President of the California Municipal Utilities Association Board of Governors. She is a past member of the CAISO Governing Board, past chairman of the Southern California Utility Power Pool, and past member of the Intermountain Power Services Corporation Board. She also served as Interim CEO for the CAISO while a search was conducted for a permanent CEO. Edward P. Zacherl, Assistant General Manager Finance and Administration, joined the City in 1990 as the Assistant Finance Director. Mr. Zacherl has 35 years of experience in finance and accounting. Mr. Zacherl earned a Bachelor of Arts degree in Economics from Slippery Rock University and a Masters of Business and Administration from Duquesne University in Pittsburgh, Pennsylvania. He is a member of the Government Finance Officers Association and a member of the California Society of Municipal Finance Officers. Mr. Zacherl is also a member of the SCPPA Finance Committee and a member of the Intermountain Power Project Coordination Committee. Dukku Lee, Assistant General Manager Electric Services, joined the Anaheim Public Utilities Department on November 15, He is responsible for managing the engineering, construction, operation and 46

53 maintenance of the utility generation, transmission and distribution system. Mr. Lee has previously worked for Edison and Paragon Consulting Services. He is an advocate of community-owned power systems and their ability to provide safe, reliable and cost-effective power that meets the needs and standards of the local community. Mr. Lee holds a BS degree in Electrical Engineering from California State Polytechnic University, Pomona and an MS degree in Engineering Management from California State University, Long Beach and is a registered Professional Engineer in the State of California. Mr. Lee is an alternate Board Member of SCPPA Board of Directors, and a member of the Transmission & Distribution Engineering and Operations Committee. Stephen J. Sciortino, Assistant General Manager Utilities Joint Services, has been with the Anaheim Public Utilities Department since March He is responsible for managing the public benefit programs, integrated resources planning, communications, customer services and technology services. Previously, Mr. Sciortino held the title of the Integrated Resources Planning Manager with the Anaheim Public Utilities Department, which is responsible for scheduling and planning all energy transactions. He is also the executive sponsor for the Canyon Power Project, a 200 MW peaking facility currently under construction in the City. Mr. Sciortino has over 30 years of experience in the energy industry, having previously worked for the City of Riverside Electric Department, Edison, and the Southern California Gas Company, as well as for an independent power producer. He holds a B.A. and M.A. in Economics and has testified as an expert witness at FERC, the CEC and the CPUC. Public Utilities Board The City Council, by Ordinance No approved July 6, 1976, established a Public Utilities Board with the power and duty to make recommendations to the City Council concerning (i) the operation and conduct of the Electric System and the Water System, (ii) the establishment of rules and regulations and rates for the operation of the Electric System and the Water System, (iii) the duties and qualifications of the General Manager and other employees of the Department, (iv) the acquisition, construction, improvement, extension, enlargement, diminution or curtailment of all or any part of the Electric System and the Water System, (v) the annual budget of the Department, and (vi) financing, including the issuance of bonds for the Electric System and the Water System. The Board may also exercise such other powers and duties as may be prescribed by ordinance not inconsistent with the Charter. The Board consists of seven members, none of whom may hold any paid office or employment in the City government. The members of the Board are appointed by the City Council and may be removed by a majority vote of the City Council. Board members serve four-year overlapping terms and are limited to serving two consecutive four-year terms. The present members of the Board and their terms of appointment are: Jordan Brandman, Chairperson, term expires June 30, Mr. Brandman joined the Board in July He is currently the Director of External Affairs for the Orange County Clerk-Recorder Department. Mr. Brandman was elected to the Board of Trustees of the Anaheim Union High School District in February Previously, Mr. Brandman served as the director of workforce development for the Orange County Business Council, a policy advisor in the Governor s Office of the Secretary for Education and as a legislative aide in the California State Assembly, advising on policy issues including education, local government and transportation. He earned a bachelor s degree from the University of California at Irvine. Dave Morgan, Vice-Chairperson, term expires June 30, Mr. Morgan joined the Board in September Mr. Morgan retired as the City Manager of the City of Anaheim in June, 2009, after having served almost eight years as Anaheim s top executive officer and culminating a career with the city that spanned 35 years. His experience ranged from administrative analysis and budget, to assistant director of MIS and data processing functions, to Resource Development Manager and Human Resources Director, a position he held for four years, prior to being named assistant City Manager in Mr. Morgan has a Bachelor of Arts in Political Science/Public Administration and a Masters of Public Administration from California State University, Fullerton. He also completed the Leadership for the 21st Century Program offered by Harvard University s John F. Kennedy School of Government. 47

54 Pat Carroll, term expires June 30, Mr. Carroll joined the Board in April He has resided in Anaheim for 19 years and has been active in various community organizations including the Boys and Girls Club, Acacia Adult Day Care and Anaheim Community Center Authority. Mr. Carroll received his B.A. from University of California, Irvine and his Juris Doctorate from Loyola University. Mr. Carroll is currently the University Counsel at California State University, Fullerton where he is responsible for a variety of legal issues in areas including human resources, risk management, litigation, and construction. Susan Faessel, term expires June 30, Mrs. Faessel joined the Board in July Mrs. Faessel graduated from California State University, Fullerton in 1972 with a degree in Special Education. She received her Master s Degree in Educational Technology from Azusa Pacific University in Mrs. Faessel retired in 2009 from her 34-year career with the Orange Unified School District. Mrs. Faessel has remained active in the Anaheim community through her Board Memberships in the Anaheim Museum, the Anaheim Historical Society, the Mother Colony Household, the Kiwanis Club, and Advisory Board for the Orange County Symphony. She is a past President of Anaheim Beautiful. She continues her support and membership in a number of other Anaheim community organizations such as the Anaheim Ebell Club, the Chance Theater and the Anaheim MUZEO, where she and her husband Stephen are Founding Members. Mrs. Faessel worked to establish relationships between various Anaheim City Departments that resulted in enhanced library facilities and operations, such as the final funding component of Anaheim s second Bookmobile. Mrs. Faessel has supported diverse facilities and services for the Anaheim community such as her participation on the Anaheim Redevelopment Downtown Design Task Force and her involvement in the planning of Anaheim s Founder s Park. Robert Hernandez, term expires June 30, Mr. Hernandez joined the Board in January Mr. Hernandez is a former City Council member and was first elected to the Anaheim City Council in November 2002 after a 38-year career serving in the Anaheim Fire Department. He has served on the Anaheim Firefighters Association as treasurer and board member at large. He has a long history of service to the community in such organizations as the American Cancer Society, American Heart Association, Anaheim Chamber of Commerce, Western Medical Centers Foundation Board of Trustees, Latino Peace Officers Association, and was a founding member of the Downtown Anaheim Association. Mr. Hernandez addresses the housing needs of people with disabilities as Outreach Chair of the Dayle MacIntosh Center, is a current member of the Anaheim Regional Medical Center Board, and is past Chairman of the Board of Anaheim Memorial Medical Center. John Machiaverna, term expires June 30, Mr. Machiaverna joined the Board in July A resident of Anaheim for more than 45 years and business owner in the community for approximately 17 years, Mr. Machiaverna has been active in community and civic affairs, which have kept him in close touch with community needs and concerns. His community work was recognized in 2000, by the National Philanthropic Society as an Orange County Volunteer of the Year. Charles Peltzer, term expires June 30, Mr. Peltzer has been a member of the Public Utilities Board since He is the owner of Peltzer Pines, and a third generation farmer in Anaheim. As a product of Anaheim schools and an Anaheim native, Mr. Peltzer is passionate about providing low-cost, efficient utility services to the Anaheim community. He is a local businessman who has served as the Orange County Farm Bureau representative to the State of California Department of Water Resources and currently serves on the Farm Bureau's Board of Directors. THE AUTHORITY The Authority was created pursuant to a Joint Exercise of Powers Agreement, dated January 28, 1992 (the Joint Powers Agreement ), by and between the City and the former Anaheim Redevelopment Agency. Pursuant to the Joint Powers Agreement, as amended, the Authority may enter into agreements to acquire, construct, maintain, improve, renovate, repair and expand certain real property, buildings, works and improvements and acquire, maintain, lease and operate certain personal property and equipment. The Authority also has the authority to issue bonds and incur indebtedness. 48

55 The members of the City Council of the City serve as the members of the Board and Directors of the Authority. See APPENDIX B GENERAL INFORMATION REGARDING THE CITY City Council. LITIGATION There is no action, suit, proceeding, inquiry or investigation at law or in equity or before or by any court, public board or body pending or, to the knowledge of the City, threatened, questioning (i) the corporate existence of the Authority, or the title of the officers of the Authority to their respective offices, (ii) the validity of the Bonds or the power and authority of the Authority to issue or remarket the Bonds, (iii) the validity of the Continuing Disclosure Agreement, the Installment Purchase Agreement, the Indenture or the Charter (as it relates to the Bonds), or (iv) the authority of the City to fix, charge and collect rates as provided in the Installment Purchase Agreement. The City has pending against it a number of claims and lawsuits arising out of matters usually incidental to the operation of a utility such as the Electric System. The City is of the view that, if determined adversely to the City, the actual damage awards likely to be ultimately paid with respect to such claims and lawsuits would not, in the aggregate, materially impair the City s ability to make Purchase Payments and Additional Purchase Payments when due. CREDIT RATINGS Standard & Poor s Ratings Services ( S&P ) and Fitch, Inc. ( Fitch ) have assigned their respective municipal bond ratings of AA- and AA- to the Bonds. Each such rating should be evaluated independently of any other rating. No application has been made to any other rating agency in order to obtain additional ratings on the Bonds. Any explanation as to the significance of the above ratings may be obtained from the applicable rating agency. The above described ratings are not recommendations to buy, sell or hold the Bonds, and each such rating may be subject to revision or withdrawal at any time by the applicable rating agency. Any downward revision or withdrawal of any of the ratings may have an adverse effect on the market price of the Bonds. TAX EXEMPTION The Internal Revenue Code of 1986 (the Code ) imposes certain requirements that must be met subsequent to the issuance and delivery of the Bonds for interest thereon to be and remain excluded pursuant to section 103(a) of the Code from the gross income of the owners thereof for federal income tax purposes. Noncompliance with such requirements could cause the interest on the Bonds to be included in the gross income of the owners thereof for federal income tax purposes retroactive to the date of issuance of the Bonds. Each of the Authority and the City has covenanted to maintain the exclusion of the interest on the Bonds from the gross income of the owners thereof for federal income tax purposes. In the opinion of Fulbright & Jaworski L.L.P., Los Angeles, California, Bond Counsel, under existing statutes, regulations, rulings and court decisions, and, assuming compliance with the covenants mentioned below, interest on the Bonds is excluded pursuant to section 103(a) of the Internal Revenue Code of 1986 (the Code ) from the gross income of the owners thereof for federal income tax purposes. Bond Counsel is of the further opinion that under existing statutes, regulations, rulings and court decisions, the Bonds are not specified private activity bonds within the meaning of section 57(a)(5) of the Code and, therefore, interest on the Bonds will not be treated as an item of tax preference for purposes of computing the alternative minimum tax imposed by section 55 of the Code. Receipt or accrual of interest on Bonds owned by a corporation may affect the computation of the alternative minimum taxable income of that corporation. A corporation s alternative minimum taxable income is the basis on which the alternative minimum tax imposed by section 55 of the Code will be computed. Bond Counsel is of the further opinion that interest on the Bonds is exempt from personal income taxes of the State of California under present state law. 49

56 The excess, if any, of the stated redemption price at maturity of the Bonds over the initial offering price to the public of the Bonds set forth on the inside cover of this Official Statement is original issue discount. Such original issue discount accruing on a Bond is treated as interest excluded from the gross income of the owner thereof for federal income tax purposes and exempt from California personal income tax. Original issue discount on any Bond purchased at such initial offering price and pursuant to such initial offering will accrue on a semiannual basis over the term of the Bond on the basis of a constant yield method and, within each semiannual period, will accrue on a ratable daily basis. The amount of original issue discount on such a Bond accruing during each period is added to the adjusted basis of such Bond to determine taxable gain upon disposition (including sale, redemption or payment on maturity) of such Bond. The Code includes certain provisions relating to the accrual of original issue discount in the case of purchasers of the Bonds who purchase the Bonds other than at the initial offering price and pursuant to the initial offering. Any person considering purchasing a Bond should consult his or her own tax advisors with respect to the tax consequences of ownership of bonds with original issue discount, including the treatment of purchasers who do not purchase in the original offering and at the original offering price, the allowance of a deduction for any loss on a sale or other disposition, and the treatment of accrued original issue discount on such bonds under federal individual and corporate alternative minimum taxes. To the extent that a purchaser of a Bond acquires that Bond at a price that exceeds the aggregate amount of payments (other than payments of qualified stated interest within the meaning of section of the Treasury Regulations) to be made on the Bonds, such excess will constitute bond premium under the Code. Section 171 of the Code, and the Treasury Regulations promulgated thereunder, provide generally that bond premium on a taxexempt obligation must be amortized on a constant yield, economic accrual, basis. The amount of premium so amortized will reduce the owner s basis in such obligation for federal income tax purposes, but such amortized premium will not be deductible for federal income tax purposes. Such reduction in basis will increase the amount of any gain (or decrease the amount of any loss) to be recognized for federal income tax purposes upon a sale or other taxable disposition of the obligation. The amount of premium that is amortizable each year by a purchaser is determined by using such purchaser s yield to maturity. The rate and timing of the amortization of the bond premium and the corresponding basis reduction may result in an owner realizing a taxable gain when a Bond owned by such owner is sold or disposed of for an amount equal to or in some circumstances even less than such owner s original cost of the Bond to the owner. Any person considering purchasing a Bond at a price that includes bond premium should consult his or her own tax advisors with respect to the amortization and treatment of such bond premium, including, but not limited to, the calculation of gain or loss upon the sale or other disposition of the Bond. Pursuant to the Installment Purchase Agreement and the Indenture, and in the Tax Certificate Pertaining to Arbitrage and Other Matters under Sections 103 and of the Internal Revenue Code of 1986, to be delivered by the Authority and the City in connection with the issuance of the Bonds, each of the Authority and the City will make representations relevant to the determination of, and will make certain covenants regarding or affecting, the exclusion of interest on the Bonds from the gross income of the owners thereof for federal income tax purposes. In reaching its opinions described in the immediately preceding paragraph, Bond Counsel will assume the accuracy of such representations and the present and future compliance by each of the Authority and the City with each of its such covenants. Further, except as stated in the preceding paragraph, Bond Counsel will express no opinion as to any federal or state tax consequences of the receipt of interest on, or the ownership or disposition of, the Bonds. Furthermore, Bond Counsel will express no opinion as to any federal, state or local tax law consequences with respect to the Bonds, or the interest thereon, if any action is taken with respect to the Bonds or the proceeds thereof predicated or permitted upon the advice or approval of other counsel. Bond Counsel has not undertaken to advise in the future whether any events after the date of issuance of the Bonds may affect the tax status of interest on the Bonds or the tax consequences of the ownership of the Bonds. No assurance can be given that future legislation, if enacted into law, will not contain provisions that could directly or indirectly reduce the benefit of the exemption of interest on the Bonds from personal income taxation by the State of California or of the exclusion of the interest on the Bonds from the gross income of the owners thereof for federal income tax purposes. The opinion of Bond Counsel is not a guarantee of a result, but will represent its legal judgment based upon its review of existing statutes, regulations, published rulings and court decisions and the representations and 50

57 covenants of the Authority and of the City described above. No ruling has been sought from the Internal Revenue Service (the IRS ) with respect to the matters to be addressed in the opinion of Bond Counsel, and Bond Counsel s opinion will not be binding on the IRS. The IRS has an ongoing program of auditing the tax-exempt status of the interest on municipal obligations. If an audit of the Bonds is commenced, under current procedures the IRS is likely to treat the Authority as the taxpayer, and the owners would have no right to participate in the audit process. In responding to or defending an audit of the tax-exempt status of the interest on the Bonds, the Authority may have different or conflicting interests from the owners of the Bonds. Further, the disclosure of the initiation of an audit may adversely affect the market price of the Bonds, regardless of the final disposition of the audit. Although it is expected that Bond Counsel will express the opinion that interest on the Bonds is exempt from California personal income tax and that interest on the Bonds is excluded pursuant to section 103(a) of the Code from the gross income of the owners thereof for federal income tax purposes, an owner s federal, state or local tax liability may be otherwise affected by the ownership or disposition of the Bonds. The nature and extent of these other tax consequences will depend upon the owner s other items of income or deduction. Without limiting the generality of the foregoing, prospective purchasers of the Bonds should be aware that (i) section 265 of the Code denies a deduction for interest on indebtedness incurred or continued to purchase or carry the Bonds and the Code contains additional limits on interest deductions applicable to financial institutions that own tax-exempt obligations (such as the Bonds), (ii) with respect to insurance companies subject to the tax imposed by section 831 of the Code, section 832(b)(5)(B)(i) reduces the deduction for loss reserves by 15% of the sum of certain items, including interest on the Bonds, (iii) interest on the Bonds earned by certain foreign corporations doing business in the United States could be subject to a branch profits tax imposed by section 884 of the Code, (iv) passive investment income, including interest on the Bonds, may be subject to federal income taxation under section 1375 of the Code for Subchapter S corporations that have Subchapter C earnings and profits at the close of the taxable year if greater than 25% of the gross receipts of such Subchapter S corporation is passive investment income, (v) section 86 of the Code requires recipients of certain Social Security and certain Railroad Retirement benefits to take into account, in determining the taxability of such benefits, receipts or accruals of interest on the Bonds and (vi) under section 32(i) of the Code, receipt of investment income, including interest on the Bonds, may disqualify the recipient thereof from obtaining the earned income credit. Bond Counsel will express no opinion regarding any such other tax consequences. A copy of the form of opinion of Bond Counsel relating to the Bonds is included in Appendix F. CERTAIN LEGAL MATTERS Fulbright & Jaworski L.L.P., Los Angeles, California, Bond Counsel, will render an opinion with respect to the validity and enforceability of the Bonds, the Indenture and the Installment Purchase Agreement, substantially in the form set forth in Appendix F hereto. Certain other legal matters will be passed upon for the Authority and the City by the City Attorney, and for the Underwriters by Stradling Yocca Carlson & Rauth, a Professional Corporation, Newport Beach, California, Underwriters Counsel. FINANCIAL STATEMENTS The audited financial statements of the City Electric Utility Fund as of and for the year ended June 30, 2011 and June 30, 2010, included in Appendix A to this Official Statement, have been audited by KPMG LLP, independent accountants (the Auditor ), as stated in their report appearing in Appendix A. The City has not requested, nor has the Auditor given, the Auditor s consent to the inclusion in Appendix A of its report on such financial statements. The Auditor s review in connection with the audited financial statements included in Appendix A included events only as of June 30, 2011, and no review or investigation with respect to subsequent events has been undertaken in connection with such financial statements by the Auditor. See THE ELECTRIC SYSTEM Historical Financial Results for a discussion of year to date financial results. 51

58 FINANCIAL ADVISOR The Authority and the City have retained Public Financial Management, Inc. as financial advisor (the Financial Advisor ) in connection with the preparation of this Official Statement and with respect to the issuance of the Bonds. The Financial Advisor is not obligated to undertake, and has not undertaken to make, an independent verification or assume responsibility for the accuracy, completeness or fairness of the information contained in this Official Statement. Public Financial Management, Inc. is an independent financial advisory firm and is not engaged in the business of underwriting, trading or distributing municipal securities or other public securities. VERIFICATION OF MATHEMATICAL COMPUTATIONS The Arbitrage Group, Inc., a firm of independent public accountants (the Verification Agent ), will deliver to Authority and the City its verification report indicating that it has verified the mathematical accuracy of the computations of the adequacy of the maturing principal of and interest on the investments in the Escrow Fund and the other moneys in the Escrow Fund to pay, when due, the redemption price of and interest on the Refunded Bonds. The arithmetical accuracy of certain computations included in the schedules provided by Underwriter on behalf of the Authority and the City relating to (a) computation of forecasted receipts of principal and interest on the U.S. Treasury Securities to be deposited in the Escrow Fund and the forecasted payments of principal and interest to redeem the Refunded Bonds, and (b) computation of the yields on the Refunding Bonds and such U.S. Treasury Securities was examined by The Arbitrage Group, Inc. Such computations were based solely upon assumptions and information supplied by Underwriter on behalf of the Authority and the City. The Arbitrage Group, Inc. has restricted its procedures to examining the arithmetical accuracy of certain computations and has not made any study or evaluation of the assumptions and information upon which the computations are based and, accordingly, has not expressed an opinion on the data used, the reasonableness of the assumptions, or the achievability of the forecasted outcome. UNDERWRITING The Bonds are being purchased for reoffering by Citigroup Global Markets, as representative (the Representative ) of itself and E.J. De La Rosa & Co., Inc. (collectively, the Underwriters ). The Underwriters have agreed to purchase the Bonds at a purchase price of $101,194, (which represents the principal amount of the Bonds, plus net bond premium of $9,253,594.85, less an underwriters discount of $189,501.29). The purchase contract pursuant to which the Bonds are being sold provides that the obligation of the Underwriters to purchase the Bonds is subject to certain terms and conditions, including the approval of certain legal matters by counsel. The Underwriters may offer and sell the Bonds to certain dealers and others at prices lower than the offering prices stated on the inside cover page hereof. The offering prices may be changed from time to time by the Underwriters. The Underwriters have entered into distribution agreements with other broker-dealers (that have not been designated by the Authority or the City as Underwriters) for the distribution of the Bonds at the original public offering prices. Such agreements generally provide that the relevant Underwriter will share a portion of its underwriting compensation or selling concession with such broker-dealers. The Representative and its affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, principal investment, hedging, financing and brokerage activities. The Underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various investment banking services for the City for which they received or will receive customary fees and expenses. 52

59 In the ordinary course of their various business activities, the Underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (which may include bank loans and/or credit default swaps) for their own account and for the accounts of their customers and may at any time hold long and short positions in such securities and instruments. Such investment and securities activities may involve securities and instruments of the City. CONTINUING DISCLOSURE Pursuant to a Continuing Disclosure Agreement, the City has covenanted for the benefit of Owners of the Bonds, to provide certain financial information and operating data relating to the City and the Electric System by not later than six months after the end of each of the City s Fiscal Years (presently, by each December 31), commencing with the respective reports for the Fiscal Year (the Annual Reports ), and to provide notices of the occurrences of certain enumerated events. The Annual Reports and notices of material events will be filed by the Dissemination Agent on behalf of the City with the Municipal Securities Rulemaking Board. The Municipal Securities Rulemaking Board intends to make the information available to the public without charge through its EMMA system. The specific nature of information to be contained each Annual Report or notice of material events is set forth in APPENDIX D FORM OF CONTINUING DISCLOSURE AGREEMENT. These covenants have been made by the City in order to assist the Underwriters in complying with Rule 15c2-12 promulgated by the Securities and Exchange Commission. The City has never failed to comply in all material respects with any previous continuing disclosure undertakings pursuant to Rule 15c

60 MISCELLANEOUS The execution and delivery of this Official Statement have been duly authorized by the Anaheim Public Financing Authority. ANAHEIM PUBLIC FINANCING AUTHORITY By /s/ Bob Wingenroth Executive Director 54

61 APPENDIX A CITY OF ANAHEIM ELECTRIC UTILITY FUND AUDITED FINANCIAL STATEMENTS FOR THE FISCAL YEARS ENDED JUNE 30, 2011 AND JUNE 30, 2010

62 [THIS PAGE INTENTIONALLY LEFT BLANK]

63 CITY OF ANAHEIM ELECTRIC UTILITY FUND Financial Statements June 30, 2011 and 2010 (With Independent Auditors Report Thereon)

64 CITY OF ANAHEIM ELECTRIC UTILITY FUND Table of Contents Page Independent Auditors Report 1 Management s Discussion and Analysis (Unaudited) 3 Financial Statements: Balance Sheets 16 Statements of Revenues, Expenses, and Changes in Fund Net Assets 18 Statements of Cash Flows 19 Notes to Financial Statements 21

65 KPMG LLP Suite Pacifica Irvine, CA Independent Auditors Report The Honorable City Council City of Anaheim, California: We have audited the accompanying financial statements of the Electric Utility Fund (Electric Utility) of the City of Anaheim, California (the City) as of and for the years ended June 30, 2011 and 2010, as listed in the accompanying table of contents. These financial statements are the responsibility of the City s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Electric Utility s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in note 1 to the financial statements, the financial statements present only the Electric Utility Fund of the City of Anaheim, California, and do not purport to, and do not, present fairly the financial position of the City, as of June 30, 2011 and 2010, and changes in its financial position and its cash flows, where applicable, for the years then ended, in conformity with U.S. generally accepted accounting principles. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Electric Utility Fund of the City of Anaheim, California, as of June 30, 2011 and 2010, and the changes in its financial position and its cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles. KPMG LLP is a Delaware limited liability partnership, the U.S. member firm of KPMG International Cooperative ( KPMG International ), a Swiss entity.

66 Management s discussion and analysis on pages 3 through 15 is not a required part of the basic financial statements, but is supplementary information required by U.S. generally accepted accounting principles. We have applied certain limited procedures, which consisted principally of inquiries of management regarding the methods of measurement and presentation of the required supplementary information. However, we did not audit the information and express no opinion on it. Orange County, California December 14,

67 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) As management of Anaheim Public Utilities, a department of the City of Anaheim (City), we offer the readers of the City of Anaheim Electric Utility Fund (Electric Utility) financial statements a narrative overview and analysis of the financial statements for the fiscal years ended June 30, 2011 and We encourage readers to consider the information presented here in conjunction with the accompanying financial statements. Financial Highlights The assets of the Electric Utility exceeded its liabilities at the close of the most recent two fiscal years by $331,298 and $323,151, respectively. Of these amounts, $61,456 and $77,283, respectively, may be used to meet the Electric Utility s ongoing obligations to creditors and customers (unrestricted fund net assets). The Electric Utility s total fund net assets increased by $8,147 and $3,033 for the fiscal years ended June 30, 2011 and 2010, respectively. Unrestricted fund net assets represented 18.0% and 22.4% of annual operating expenses for fiscal years 2011 and 2010, respectively. Overview of the Financial Statements This discussion and analysis is intended to serve as an introduction to the Electric Utility s financial statements. Because the Electric Utility is a business-type activity of the City, an enterprise fund is used to account for its operations. These financial statements include only the activities of the Electric Utility and provide comparative information for the last two fiscal years. Information on citywide financial results is available in the City s Comprehensive Annual Financial Report as of June 30, The Electric Utility s financial statements comprise two components: (1) financial statements and (2) notes to financial statements. Included as part of the financial statements are the balance sheets, statements of revenues, expenses, and changes in fund net assets, and statements of cash flows. The balance sheets present information on assets and liabilities with the difference between the two reported as fund net assets. Over time, increases or decreases in fund net assets may serve as a useful indicator of whether the financial condition of the Electric Utility is improving or deteriorating. The statements of revenues, expenses, and changes in fund net assets present information showing how the Electric Utility s fund net assets changed during the most recent two fiscal years. Results of operations are recorded using the accrual basis of accounting, whereby transactions are reported as underlying events occur, regardless of the timing of cash flows. Thus, revenues and expenses are reported in these statements for some items that will result in cash flows in future fiscal periods, such as accounts receivable and accounts payable. The accrual basis of accounting is more fully described in the accompanying notes to financial statements. The statements of cash flows present the flows of cash and cash equivalents during the last two fiscal years, including certain restricted amounts. The notes to financial statements provide additional information that is essential to the full understanding of the data provided in the financial statements. 3 (Continued)

68 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) Financial Analysis As noted earlier, fund net assets may serve over time as a useful indicator of the Electric Utility s financial position. In the case of the Electric Utility, assets exceeded liabilities by $331,298 and $323,151 at June 30, 2011 and 2010, respectively. A portion of the Electric Utility s fund net assets (71.3% and 66.5% as of June 30, 2011 and 2010, respectively) reflects its investment in capital assets, such as production, transmission, distribution facilities, and general plant, less any related debt that remains outstanding used to acquire those assets. The Electric Utility uses these capital assets to provide services to customers; consequently, these assets are not available for future spending. Resources needed to repay the outstanding debt on the balance sheets must come from other sources such as operations. An additional portion of the Electric Utility s fund net assets (10.1% and 9.6% as of June 30, 2011 and 2010, respectively) represents resources that are subject to external restrictions on how they may be used. These restrictions are for items such as debt repayment and other legally restricted purposes. The unrestricted portion of the Electric Utility s fund net assets (18.6% and 23.9% as of June 30, 2011 and 2010, respectively) may be used to meet the Electric Utility s ongoing obligations to creditors and customers. The Electric Utility s condensed balance sheets at June 30 are as follows: Condensed Balance Sheets Current and other assets $ 440, , ,659 Net utility plant 817, , ,129 Total assets 1,258,166 1,174,927 1,186,788 Long-term liabilities, net of current portion 834, , ,336 Current liabilities 92,505 95,710 99,334 Total liabilities 926, , ,670 Invested in capital assets, net of related debt 236, , ,902 Restricted 33,614 31,010 30,071 Unrestricted 61,456 77,283 80,145 Total fund net assets $ 331, , ,118 4 (Continued)

69 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) As of June 30, 2011 Assets Total assets as of June 30, 2011 and 2010 were $1,258,166 and $1,174,927, respectively. The $83,239 (7.1%) increase in total assets was due to a $24,687 increase in net utility plant and a $58,552 increase in current, restricted, and other assets. Net utility plant increased 3.1% due to current year s net capital asset additions of $62,459 related to production, distribution, and general utility plant, which was offset by depreciation expense of $37,772. Current, restricted, and other assets increased 15.3% primarily due to an increase of $36,779 in cash and investments (see statements of cash flows for additional information regarding changes in cash and cash equivalents), and an increase of $17,629 in prepaid purchase power mainly due to a lower true-up of power costs that were less than the estimated payments by $9,080 for Intermountain Power Agency and $4,988 Magnolia gas cost. Liabilities Total liabilities as of June 30, 2011 and 2010 were $926,868 and $851,776, respectively. The $75,092 (8.8%) increase in total liabilities was due to a $78,297 increase in long-term liabilities offset by a $3,205 decrease in current liabilities. Long-term liabilities increased 10.4% primarily due to a $90,390 new bond issue in the current year and an increase of $3,454 in the provision for decommissioning costs, which were offset by principal payments of $17,825. Current liabilities decreased 3.3% primarily due to a decrease of $3,703 in accounts payable and accrued expenses resulting from decreased fuel and generation expenditures. Fund Net Assets Total fund net assets as of June 30, 2011 and 2010 were $331,298 and $323,151, respectively. Total fund net assets increased by $8,147 (2.5%) primarily due to an increase in amounts invested in capital assets, net of related debt of $21,370, offset by a decrease in unrestricted amounts of $15,827. Invested in capital assets, net of related debt increased 9.9% primarily due to an increase of $24,687 in net capital assets during fiscal year Unrestricted net assets decreased 20.5% primarily due to the above investment in capital assets. As of June 30, 2010 Assets Total assets as of June 30, 2010 and 2009 were $1,174,927 and $1,186,788, respectively. The $11,861 (1.0%) decrease in total assets was due to a $15,911 increase in net utility plant, which was offset by a $27,772 decrease in current, restricted, and other assets. Net utility plant increased 2.0% due to net capital asset additions of $51,837 related to production, distribution, and general utility plant, which was offset by depreciation expense of $35,926. Current, restricted, and other assets decreased 6.8% primarily due to a decrease of $28,338 in cash and investments (see statements of cash flows for additional information regarding changes in cash and cash equivalents). 5 (Continued)

70 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) Liabilities Total liabilities as of June 30, 2010 and 2009 were $851,776 and $866,670, respectively. The $14,894 (1.7%) decrease in total liabilities was due to a $11,270 decrease in long-term liabilities and a $3,624 decrease in current liabilities. Long-term liabilities decreased 1.5% primarily due to principal payments of $15,995, which were partially offset by an increase of $6,808 in the provision for decommissioning costs. Current liabilities decreased 3.6% primarily due to a net decrease in regulatory credits of $9,545 (see note 1 of the notes to financial statements for additional information regarding regulatory credits), which were partially offset by an increase of $5,537 in accounts payable and accrued expenses resulting from increased power costs and capital expenditures. Fund Net Assets Total fund net assets as of June 30, 2010 and 2009 were $323,151 and $320,118, respectively. Total fund net assets increased by $3,033 (0.9%). There were no significant or unusual changes during the fiscal year. 6 (Continued)

71 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) The Electric Utility s statements of revenues, expenses, and changes in fund net assets for the years ended June 30 are summarized as follows: Revenues, Expenses, and Changes in Fund Net Assets Revenues: Retail sales, net $ 300, , ,942 Wholesale sales 21,039 35,409 27,821 RSA revenues 22,500 31,200 30,700 Surplus natural gas sales 9,096 2,496 4,119 Transmission revenues 24,590 22,532 25,717 Other revenues 6,033 3,434 4,254 Interest income 7,438 12,326 13,363 Capital contributions 7,349 4,351 5,257 Total revenues 398, , ,173 Expenses: Purchased power 239, , ,595 Fuel and generation 21,921 26,981 25,763 Operations, maintenance, and administration 42,707 45,923 44,911 Depreciation 37,772 35,926 30,692 Interest expense 30,079 29,243 27,027 Cost of capital assets moved to the City 3,581 Total expenses 371, , ,569 Transfers: Transfer to the General Fund of the City (16,042) (14,122) (28,933) Transfer of right-of-way fee to the City (4,713) (4,555) (4,262) Transfers from other funds of the City 2,153 1,276 2,318 Total transfers (18,602) (17,401) (30,877) Changes in fund net assets 8,147 3,033 (8,273) Fund net assets at beginning of year 323, , ,391 Fund net assets at end of year $ 331, , ,118 7 (Continued)

72 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) Revenues Year ended June 30, 2011 Total revenues for the year ended June 30, 2011 were $398,567 as compared with $394,715 in the prior year, an increase in total revenues of $3,852 (1.0%). This increase was primarily due to an increase of $17,555 in retail sales, an increase of $6,600 in surplus natural gas sales, and an increase of $2,058 in transmission revenues, which were offset by a decrease of $14,370 in wholesale sales and a decrease of $8,700 in Rate Stabilization Account (RSA) revenues. The increase of 6.2% in retail sales revenue was in response to the increasing power costs, for which a 5.0% base rate increase was approved on December 1, The increase of 264% in surplus natural gas sales was mainly due to more natural gas available for resale in the spot market. When Magnolia and Combustion Turbine plants experienced unplanned outages, less purchased gas was used for both plants in this fiscal year. The increase of 9.1% in transmission revenues was mainly due to the increased congestion transmission revenues. Transmission revenues are based upon the Electric Utility providing use of its transmission entitlements to the California Independent System Operator (CAISO) as a participating transmission owner. These revenues are based upon the transmission rates charged by CAISO and the demand in the participants market. The decrease of 40.6% in wholesale sales revenue was the combination of a wholesale sales volume decline of 32% and wholesale average price drop of 12% in the market. RSA revenues of $22,500 were recognized in this fiscal year in order to maintain a debt service coverage ratio of 1.6. This coverage ratio is needed to retain the Electric Utility bond ratings. The decrease in the recognition of RSA revenues of 27.9% was mainly due to higher retail sales and surplus natural gas sales to reduce RSA revenues needed in this fiscal year. Additional information on the RSA can be found in the Regulatory Credits section of note 1 of the notes to the financial statements on page 23 of this report. Year ended June 30, 2010 Total revenues for the year ended June 30, 2010 were $394,715 as compared with $384,173 in the prior year, an increase in total revenues of $10,542 (2.7%). This increase was primarily due to an increase of $10,025 in retail sales and an increase of $7,588 in wholesale sales, which were partially offset by a decrease of $1,623 in surplus natural gas sales and a decrease of $3,185 in transmission revenues. The increase of 3.7% in retail sales revenue was in response to sustained increased power costs, for which the City Council increased base rates with an equal and corresponding drop in the Power Cost 8 (Continued)

73 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) Adjustment (PCA) charge. The PCA is a rate charged to customers to collect for the variability in power and fuel supply costs and is not included in retail base rates. The increase of 27.3% in wholesale sales revenue was mainly due to more surplus power available to the wholesale market when the retail sales volumes were decreased and a planned maintenance schedule was delayed in the Intermountain Power Project in this fiscal year. The decrease of 39.4% in surplus natural gas sales was mainly due to less natural gas available for resale in the market as more purchased gas was used for Magnolia and Combustion Turbine gas plants in this fiscal year. Transmission revenues are based upon the Electric Utility providing use of its transmission entitlements to CAISO as a participating transmission owner. These revenues are based upon the transmission rates charged by CAISO and the demand in the participants market. The decrease of 12.4% in transmission revenues was mainly due to the decreased congestion transmission revenues caused by a better transmission congestion management system, which is the new Market Redesign and Technology Upgrade program (MRTU). Revenues by Source Year ended June 30, 2011 Retail Sales net 75% Interest Income 2% Capital Contributions 2% Other Revenues 2% Surplus Natural Gas Sales 2% Wholesale Sales 5% RSA Revenues 6% Transmission Revenues 6% 9 (Continued)

74 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) Revenues by Source Year ended June 30, 2010 Retail Sales net 72% Interest Income 3% Capital Contributions 1% Other Revenues <1% Surplus Natural Gas Sales <1% Wholesale Sales 9% RSA Revenues 8% Transmission Revenues 6% Expenses Year ended June 30, 2011 Total expenses for the year ended June 30, 2011 were $371,818 as compared with $374,281 in the prior year. This $2,463 (0.7%) decrease in total expenses was mainly the result of a $5,060 decrease in fuel and generation offset by an increase in purchased power costs of $3,131. The 18.8% decrease in fuel and generation expense was mainly due to the combination of a decrease of $3,354 in decommissioning expenses for San Onofre Nuclear Generation Station unit 2 and 3 operations (SONGS) and $1,957 in operation and maintenance expenses for the Combustion Turbine. The decrease in decommissioning expenses is due to less interest income available that is required to be contributed to the decommissioning reserve fund in the trustee account. Additional information on the decommissioning expenses can be found in the Decommissioning Costs of note 1 of the notes to the financial statement on page 24 of this report. The decrease in operation and maintenance expenses for the Combustion Turbine plant is due to less natural gas expenses due to unplanned outage in this fiscal year. The 1.3% increase in purchased power costs was due primarily to the combination of increases of transmission and renewable costs, as the City Council has committed to increase the amount of renewable energy in the resource mix to 20.0% by (Continued)

75 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) Year ended June 30, 2010 Total expenses for the year ended June 30, 2010 were $374,281 as compared with $361,569 in the prior year. This $12,712 (3.5%) increase in total expenses was mainly the result of a $6,613 increase in purchased power costs and a $5,234 increase in depreciation. The 2.9% increase in purchased power costs was due primarily to a $6,559 increase in purchased power from the renewable market, as the City Council has committed to increase the amount of renewable energy in the resource mix to 20.0% by The 17.1% increase in depreciation expense was due to $46,602 of assets placed into service this fiscal year, which included upgrading the Lewis substation extension, improvement of the existing distribution system, two underground projects, and upgrading the Anaheim West Tower office building. Additionally, the Electric Utility recognized a full year depreciation of assets placed into service in prior fiscal year. Transfers Year ended June 30, 2011 Transfers to the City s General Fund, as defined by City Charter, are equal to a maximum of 4% of total operating revenues. The transfer to the City s General Fund was $16,042 for fiscal year 2011, which is based on the current year s total operating revenues. An increase of $1,920 was mainly due to increased total operating revenues in the fiscal year The transfer of the right-of-way fee to the City is equal to 1.5% of retail electric revenues of the prior fiscal year. The right-of-way fee transferred to the City was $4,713 for fiscal year There were no significant changes in the amount of right-of-way fee transferred to the City during fiscal year 2011 when compared with fiscal year Transfers from other funds in fiscal year 2011 were $2,153 as compared with $1,276 in the prior fiscal year. The increase of $877 was mainly due to cash transfer from the City for certain capital improvements in the Platinum Triangle area. Year ended June 30, 2010 Transfers to the City s General Fund, as defined by City Charter, are equal to a maximum of 4% of total operating revenues. The transfer to the City s General Fund was $14,122 for fiscal year 2010, which is based on the current year s total operating revenues. A decrease of $14,811 was mainly due to a one-time transfer of $14,910 to the General Fund of the City in the fiscal year The transfer of the right-of-way fee to the City is equal to 1.5% of retail electric revenues of the prior fiscal year. The right-of-way fee transferred to the City was $4,555 for fiscal year There were no significant changes in the amount of right-of-way fee transferred to the City during fiscal year 2010 when compared with fiscal year (Continued)

76 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) Transfers in from other funds in fiscal year 2010 were $1,276 as compared with $2,318 in the prior fiscal year. The $1,276 transfer was mainly a $1,097 vehicle capital assets transfer from other City funds. Expenses and Transfers Year ended June 30, 2011 Purchased Power 61% Fuel and Generation 5% Interest Expense 8% Transfers 5% Operations, Maintenance, and Administration 11% Depreciation 10% 12 (Continued)

77 CITY OF ANAHEIM ELECTRIC UTILITY FUND Management s Discussion and Analysis (Unaudited) June 30, 2011 and 2010 (In thousands) Expenses and Transfers Year ended June 30, 2010 Purchased Power 60% Fuel and Generation 7% Interest Expense 8% Transfers 4% Operations, Maintenance, and Administration 12% Depreciation 9% Capital Assets and Debt Administration Capital Assets The Electric Utility s investment in net utility plant as of June 30, 2011 and 2010 was $817,727 and $793,040, respectively, net of accumulated depreciation. This includes investments in production, transmission, and distribution-related facilities as well as general plant capital assets. The Electric Utility s investment, before depreciation, in total utility plant at June 30, 2011 was $1,168,210, an increase of $56,067 (5.0%) over the prior fiscal year. 13 (Continued)