Pinnacle West Capital (PNW) 10-K 2008 FY Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                    to                    

Commission	Registrants; State of Incorporation;	IRS Employer
File Number	Addresses; and Telephone Number	Identification No.
1-8962	PINNACLE WEST CAPITAL CORPORATION (An Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (602) 250-1000	86-0512431
1-4473	ARIZONA PUBLIC SERVICE COMPANY (An Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona 85072-3999 (602) 250-1000	86-0011170

Securities registered pursuant to Section 12(b) of the Act:
	Title Of Each Class	Name Of Each Exchange On Which Registered
PINNACLE WEST CAPITAL CORPORATION	Common Stock,	New York Stock Exchange
	No Par Value
ARIZONA PUBLIC SERVICE COMPANY	None	None

Securities registered pursuant to Section 12(g) of the Act:None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

PINNACLE WEST CAPITAL CORPORATION Yesþ Noo

ARIZONA PUBLIC SERVICE COMPANY Yesþ Noo

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

PINNACLE WEST CAPITAL CORPORATION Yeso Noþ

ARIZONA PUBLIC SERVICE COMPANY Yeso Noþ

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

PINNACLE WEST CAPITAL CORPORATION Yesþ Noo

ARIZONA PUBLIC SERVICE COMPANY Yesþ Noo

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or in any amendment to this Form 10-K.þ

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

PINNACLE WEST CAPITAL CORPORATION
Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filero	Accelerated filero	Non-accelerated filerþ	Smaller reporting companyo
		(Do not check if a smaller reporting company)

     Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso Noþ

     State the aggregate market value of the voting and non-voting common equity held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of each registrant’s most recently completed second fiscal quarter:

PINNACLE WEST CAPITAL CORPORATION	$3,085,816,962 as of June 30, 2008
ARIZONA PUBLIC SERVICE COMPANY	$0 as of June 30, 2008

     The number of shares outstanding of each registrant’s common stock as of February 16, 2009

PINNACLE WEST CAPITAL CORPORATION	100,990,779 shares
ARIZONA PUBLIC SERVICE COMPANY	Common Stock, $2.50 par value, 71,264,947 shares. Pinnacle West Capital Corporation is the sole holder of Arizona Public Service Company’s Common Stock.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of Pinnacle West Capital Corporation’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 20, 2009 are incorporated by reference into Part III hereof.

     Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) ofForm 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

     This combined Form 10-K is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 10-K that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

TABLE OF CONTENTS

	Page
GLOSSARY		1
PART I		3
Item 1. Business		3
Item 1A. Risk Factors		24
Item 1B. Unresolved Staff Comments		35
Item 2. Properties		35
Item 3. Legal Proceedings		37
Item 4. Submission of Matters to a Vote of Security Holders Supplemental Item		37 38
Executive Officers of Pinnacle West		38
PART II		41
Item 5. Market for Registrants’ Common Equity, Pinnacle West Related Stockholder Matters and Issuer Purchases of Equity Securities		41
Item 6. Selected Financial Data		43
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		45
Item 7A. Quantitative and Qualitative Disclosures about Market Risk		77
Item 8. Financial Statements and Supplementary Data		78
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		164
Item 9A. Controls and Procedures		164
Item 9B. Other Information		165
PART III		165
Item 10. Directors, Executive Officers and Corporate Governance of Pinnacle West		165
Item 11. Executive Compensation		165
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		165
Item 13. Certain Relationships and Related Transactions, and Director Independence		167
Item 14. Principal Accountant Fees and Services		167
PART IV		169
Item 15. Exhibits and Financial Statement Schedules		169
SIGNATURES		208

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GLOSSARY

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

AFUDC – Allowance for Funds Used During Construction

ALJ – Administrative Law Judge

ANPP – Arizona Nuclear Power Project, also known as Palo Verde

APS – Arizona Public Service Company, a subsidiary of the Company

APSES – APS Energy Services Company, Inc., a subsidiary of the Company

Base Fuel Rate – the portion of APS’ retail base rates attributable to fuel and purchased power costs

Cholla – Cholla Power Plant

Clean Air Act – Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

DOE – United States Department of Energy

EITF – FASB’s Emerging Issues Task Force

El Dorado – El Dorado Investment Company, a subsidiary of the Company

EPA – United States Environmental Protection Agency

ERMC – Energy Risk Management Committee

FASB – Financial Accounting Standards Board

FERC – United States Federal Energy Regulatory Commission

FIN – FASB Interpretation Number

FIP – Federal Implementation Plan

Fitch – Fitch, Inc.

Four Corners – Four Corners Power Plant

GAAP – accounting principles generally accepted in the United States of America

IRS – United States Internal Revenue Service

kW – kilowatt, one thousand watts

kWh – kilowatt-hour, one thousand watts per hour

Moody’s – Moody’s Investors Service

MW – megawatt, one million watts

MWh – megawatt-hour, one million watts per hour

Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation

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Note – a Note to Pinnacle West’s Consolidated Financial Statements in Item 8 of this report (references to the Supplemental Notes to APS’ Financial Statements are preceded by an “S,” e.g., Note S-1)

NPC – Nevada Power Company

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

Off-System Sales – sales of electricity from generation owned or contracted by the Company that is over and above the amount required to serve APS’ retail customers and traditional wholesale contracts

Palo Verde – Palo Verde Nuclear Generating Station

Pinnacle West – Pinnacle West Capital Corporation, the Company

Pinnacle West Energy (PWEC) – Pinnacle West Energy Corporation, a subsidiary of the Company, dissolved as of August 31, 2006

Pinnacle West Marketing & Trading – Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the Company

PRP – potentially responsible parties under Superfund

PSA – power supply adjustor approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate

PWEC Dedicated Assets – the following power plants, each of which was transferred by Pinnacle West Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3

Salt River Project – Salt River Project Agricultural Improvement and Power District

SEC – United States Securities and Exchange Commission

Secured Revolver – SunCor’s principal loan facility, which is secured primarily by an interest in land, commercial properties, land contracts and homes under construction

SFAS – Statement of Financial Accounting Standards

Silverhawk – Silverhawk Power Station

Standard & Poor’s – Standard & Poor’s Corporation

SunCor – SunCor Development Company, a subsidiary of the Company

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

TCA – transmission cost adjustor

TEP – Tucson Electric Power Company

VIE – variable-interest entity

West Phoenix – West Phoenix Power Plant

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INTRODUCTION

Filing Format

     This Annual Report on Form 10-K is a combined report being filed by two separate registrants: Pinnacle West and APS. The information required with respect to each company is set forth within the applicable items.

     The Management’s Discussion and Analysis of Financial Condition and Results of Operations included under Item 7 of this report is divided into the following two sections:

• Pinnacle West Consolidated—This section describes the financial condition and results of operations of Pinnacle West and its subsidiaries on a consolidated basis. It includes discussions of Pinnacle West’s regulated utility and non-utility operations. A substantial part of Pinnacle West’s revenues and earnings is derived from its regulated utility, APS.

• APS—This section includes a detailed description of the results of operations and contractual obligations of APS.

     Item 8 of this report includes Consolidated Financial Statements of Pinnacle West and Financial Statements of APS. Item 8 also includes Notes to Pinnacle West’s Consolidated Financial Statements, the majority of which also relates to APS, and Supplemental Notes to APS’ Financial Statements.

PART I

ITEM 1. BUSINESS

OVERVIEW

General

     Pinnacle West was incorporated in 1985 under the laws of the State of Arizona and owns all of the outstanding equity securities of APS, its major subsidiary. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the State of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.

     Pinnacle West’s other principal subsidiary is SunCor, which is engaged in real estate development activities in the western United States. See “Business of SunCor Development Company” in this Item 1. Pinnacle West’s other first-tier subsidiaries, APSES and El Dorado are discussed in “Business of Other Subsidiaries” in this Item 1.

     Pinnacle West Energy, which owned and operated unregulated generating plants, transferred the PWEC Dedicated Assets to APS on July 29, 2005 and sold its 75% ownership interest in Silverhawk to NPC on January 10, 2006. As a result, Pinnacle West Energy no longer owned any generating plants and was dissolved as of August 31, 2006.

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Business Segments

     Pinnacle West has two principal business segments (determined by products, services and the regulatory environment):

• the regulated electricity segment (accounting for 93% of operating revenues in 2008), which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities, and includes electricity generation, transmission and distribution; and

• the real estate segment (accounting for 4% of operating revenues in 2008), which consists of SunCor’s real estate development and investment activities.

     Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months. See Note 17 for financial information about the business segments.

APS ACC Proceedings

     The key issue affecting Pinnacle West’s and APS’ financial outlook is adequate and timely retail rate treatment by the ACC. See “2008 General Rate Case” in Note 3 for a discussion of APS’ pending retail rate case before the ACC.

Employees

     At December 31, 2008, Pinnacle West employed approximately 7,500 people, including the employees of its subsidiaries. Of these employees, approximately 6,900 were employees of APS, including employees at jointly-owned generating facilities (approximately 3,300 employees) for which APS serves as the generating facility manager. Approximately 600 people were employed by Pinnacle West and its other subsidiaries. Pinnacle West’s principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).

Available Information

     Pinnacle West makes available free of charge on or through its website, (www.pinnaclewest.com) the following filings as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC: its Annual Report on Form 10-K, its Quarterly Reports on Form 10-Q, its Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), and its proxy statement filed pursuant to Section 14(a) of the Exchange Act.

     Pinnacle West also has a Corporate Governance webpage. You can access Pinnacle West’s Corporate Governance webpage through its internet site,www.pinnaclewest.com,by clicking on the “About Us” link to the heading “Corporate Commitments.” Pinnacle West posts the following on its Corporate Governance webpage:

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• Corporate Governance Guidelines;

• Board Committee Summary;

• Charters for Pinnacle West’s Audit Committee, Corporate Governance Committee, Finance, Nuclear and Operating Committee and Human Resources Committee;

• Code of Ethics for Financial Professionals;

• Ethics Policy and Standards of Business Practices;

• Director Independence Standards;

• Executive Officer Stock Ownership Guidelines; and

• Restricted Stock Retention Policy.

     Pinnacle West will post any amendments to the Code of Ethics and Ethics Policy and Standards of Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange, on its website. The information on Pinnacle West’s website is not incorporated by reference into this report.

     You can request a copy of these documents, excluding exhibits, by contacting Pinnacle West at the following address: Pinnacle West Capital Corporation, Office of the Secretary, Station 9068, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-3252).

Forward-Looking Statements

     This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of this report, these factors include, but are not limited to:

• state and federal regulatory and legislative decisions and actions, including the outcome or timing of the pending rate case of APS;

• increases in our capital expenditures and operating costs and our ability to achieve timely and adequate rate recovery of these increased costs;

• our ability to reduce capital expenditures and other costs while maintaining reliability and customer service levels, and unexpected developments that would limit us from achieving all or some of our planned capital expenditure reductions;

• volatile fuel and purchased power costs, including fluctuations in market prices for natural gas, coal, uranium and other fuels used in our generating facilities, availability of supplies of such commodities, and our ability to recover the costs of such commodities;

• the outcome and resulting costs of regulatory, legislative and judicial proceedings, both current and future, including those related to environmental matters and climate change;

• the availability of sufficient water supplies to operate our generation facilities, including as the result of drought conditions;

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• the potential for additional restructuring of the electric industry, including decisions impacting wholesale competition and the introduction of retail electric competition in Arizona;

• regional, national and international economic and market conditions, including the strength of the housing, credit and financial markets;

• the potential adverse impact of current economic conditions on our results of operations;

• the cost of debt and equity capital and access to capital markets;

• changes in the market price of our common stock;

• restrictions on dividends or other burdensome provisions in new or existing credit agreements;

• our ability, or the ability of our subsidiaries, to meet debt service obligations;

• current credit ratings remaining in effect for any given period of time;

• the performance of the stock market and the changing interest rate environment, which affect the value of our nuclear decommissioning trust, pension, and other postretirement benefit plan assets, the amount of required contributions to Pinnacle West’s pension plan and contributions to APS’ nuclear decommissioning trust funds, as well as the reported costs of providing pension and other postretirement benefits and our ability to recover such costs;

• volatile market liquidity, any deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);

• changes in accounting principles generally accepted in the United States of America, the interpretation of those principles and the impact of the adoption of new accounting standards;

• customer growth and energy usage;

• weather variations affecting local and regional customer energy usage;

• power plant performance and outages;

• transmission outages and constraints;

• the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;

• risks inherent in the operation of nuclear facilities, such as environmental, regulatory, health and financial risks, risk of terrorist attack, planned and unplanned outages, and unfunded decommissioning costs;

• the ability of our power plant participants to meet contractual or other obligations;

• technological developments in the electric industry;

• the results of litigation and other proceedings resulting from the California and Pacific Northwest energy situations;

• the performance of Pinnacle West’s subsidiaries and any resulting effects on its cash flow;

• the strength of the real estate market and economic and other conditions affecting the real estate market in SunCor’s market areas, which include Arizona, Idaho, New Mexico and Utah; and

• other uncertainties, all of which are difficult to predict and many of which are beyond the control of Pinnacle West and APS.

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REGULATION AND COMPETITION

Retail

     The ACC regulates APS’ retail electric rates and its issuance of securities. The ACC must also approve any transfer or encumbrance of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates.

     APS is subject to varying degrees of competition from other investor-owned utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet their own energy requirements.

     In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. As a result, as of January 1, 2001, all of APS’ retail customers were eligible to choose alternate energy suppliers. However, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. In 2000, an Arizona Superior Court found that the rules were in part unconstitutional and in other respects unlawful, the latter finding being primarily on procedural grounds, and invalidated all ACC orders authorizing competitive electric services providers to operate in Arizona. In 2004, the Arizona Court of Appeals invalidated some, but not all of the rules and upheld the invalidation of the orders authorizing competitive electric service providers. In 2005, the Arizona Supreme Court declined to review the Court of Appeals decision.

     To date, the ACC has taken no final or substantive action on either the rules or the prior orders authorizing competitive electric service providers in response to the final Court of Appeals decision. However, as a result of a new request for authorization to provide competitive retail electric service by Sempra Energy Solutions, LLC, the ACC directed the ACC staff to investigate whether such retail competition was in the public interest and what legal impediments remain to competition in light of the Court of Appeals decision referenced above. The ACC staff’s report on the results of its investigation is due to be filed with the ACC on December 31, 2009. At present, only limited electric retail competition exists in Arizona and only with certain entities not regulated by the ACC. APS cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

Wholesale

     General

     The FERC regulates rates for wholesale power sales and transmission services. See “Formula Transmission Tariff” in Note 3 for information regarding APS’ transmission rates. During 2008, approximately 6.3% of APS’ electric operating revenues resulted from such sales and services. APS’ wholesale activity primarily consists of managing fuel and purchased power risks in connection with the costs of serving retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’ Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, subject to specified parameters, APS markets, hedges and trades in electricity and fuels.

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BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY

General

     APS was incorporated in 1920 under the laws of the State of Arizona and currently has approximately 1.1 million customers. APS does not distribute any products. During 2008, no single purchaser or user of energy accounted for more than 1.8% of electric revenues. See “Overview” and “Regulation and Competition” above for additional background information about APS.

     At December 31, 2008, APS employed approximately 6,900 people, including employees at jointly-owned generating facilities for which APS serves as the generating facility manager. APS’ principal executive offices are located at 400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-1000).

Portfolio Resources

     APS’ sources of energy during 2008 were: coal – 37.4%; nuclear – 24.2%; purchased power – 20.3%; and gas – 18.1%. In accordance with GAAP, a substantial portion of APS’ purchased power expense is netted against wholesale sales on the Consolidated Statements of Income. See Note 18. The disclosure below provides a more detailed description of each of APS’ current sources of energy.

     Generation Facilities

     APS’ portfolio of owned or leased generating capacity is provided in the table below:

	Capacity (kW)
Coal:
Units 1, 2 and 3 at Four Corners		560,000
15% owned Units 4 and 5 at Four Corners		225,000
Units 1, 2 and 3 at Cholla		641,000
14% owned Units 1, 2 and 3 at the Navajo Generating Station		315,000
Subtotal		1,741,000
Gas or Oil:
Two steam units at Ocotillo and two steam units at Saguaro		430,000
Twenty-four combustion turbine units		1,088,000
Seven combined cycle units		1,862,000
Subtotal		3,380,000
Nuclear:
29.1% owned or leased Units 1, 2 and 3 at Palo Verde		1,147,122
Solar		5,816
Total		6,273,938

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     Coal Fueled Generating Facilities

     Four Corners– Four Corners is a coal-fired power plant located in the northwestern corner of New Mexico. APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 15% of Units 4 and 5. APS purchases all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016, with options on APS’ part to extend the contract for five to fifteen additional years. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” below for additional information.

     Cholla– Cholla is a coal-fired power plant located in northeastern Arizona. APS operates the plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4 and APS operates that unit for PacifiCorp. Cholla’s common facilities are jointly owned by APS and PacifiCorp. APS purchases most of Cholla’s coal requirements from coal suppliers that mine all of the coal under long-term leases of coal reserves with the Navajo Nation, the federal government and private landholders. There are currently two coal contracts in place with two separate suppliers for Cholla. One supplier is ramping down its supply to the plant, which will be complete in 2009, and the other is ramping up its supply to the plant to provide Cholla’s full coal requirement by 2010. This agreement runs through 2024. Additionally, APS may purchase a portion of Cholla’s coal requirements on the spot market to take advantage of competitive pricing options and to supplement coal required for increased operating capacity. APS believes that the current fuel contracts and competitive fuel supply options ensure the continued operation of Cholla for its useful life. In addition, APS has a long-term coal transportation contract.

     Navajo Generating Station– The Navajo Generating Station is a coal-fired power plant located in northern Arizona. Salt River Project operates the plant and APS owns a 14% interest in Navajo Units 1, 2 and 3. The Navajo Generating Station’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is under contract with its coal supplier through 2011, with options to extend through 2019. The Navajo Generating Station plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” below for additional information.

     See Note 11 for information regarding APS’ coal mine reclamation obligations.

     Natural Gas Fueled Generating Facilities

     APS has seven natural gas power plants located throughout Arizona, consisting of Redhawk, located near the Palo Verde Nuclear Generating Station; Ocotillo, located in Tempe; Sundance, located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson; Douglas, located in the town of Douglas; and Yucca, located near Yuma. APS owns and operates each plant with the exception of one combustion turbine unit and one steam unit at Yucca that are operated by APS and owned by the Imperial Irrigation District.

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     Nuclear Generating Facility

     Palo Verde Nuclear Generating Station –Palo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3 and about 17% of Unit 2. In addition, APS leases about 12.1% of Unit 2, resulting in a 29.1% combined interest in that Unit. See “Palo Verde Leases” below for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.

     Palo Verde Fuel Cycle –The fuel cycle for Palo Verde is comprised of the following stages:

• mining and milling of uranium ore to produce uranium concentrates;

• conversion of uranium concentrates to uranium hexafluoride;

• enrichment of uranium hexafluoride;

• fabrication of fuel assemblies;

• utilization of fuel assemblies in reactors; and

• storage and disposal of spent nuclear fuel.

     The Palo Verde participants are continually identifying their future resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates and conversion services through 2011. The participants have also contracted for all of Palo Verde’s enrichment services through 2013 and all of Palo Verde’s fuel assembly fabrication services until at least 2015.

     Spent Nuclear Fuel and Waste Disposal –See “Palo Verde Nuclear Generating Station” in Note 11 for a discussion of spent nuclear fuel and waste disposal.

     Palo Verde Leases –In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases or to purchase the property for fair market value at the end of the lease terms. We are analyzing this matter, and will continue to do so as we approach the end of the lease terms, to determine which option or options to pursue. See Notes 9 and 20 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.

     Regulatory–Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period of approximately 40 years, authorize APS, as operating agent for Palo Verde, to operate the three Palo Verde units at full power. APS applied for renewed operating licenses for Palo Verde Unit 1, Unit 2 and Unit 3 on December 15, 2008 for a period of 20 years beyond the expirations of the current licenses. The NRC is currently reviewing the application.

     NRC Inspection –On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) due to electrical output issues with the Unit 3 emergency diesel generator that occurred in 2006. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), which has resulted in an enhanced NRC inspection regime.

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Although only Palo Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need for improvements, APS’ management conducted site-wide assessments of equipment and operations.

     On June 21, 2007, the NRC issued an initial confirmatory action letter confirming APS’ commitments regarding specific actions APS will take to improve Palo Verde’s performance. From October 1, 2007 through November 2, 2007, a team of NRC inspectors performed on-site in-depth inspections of Palo Verde’s equipment and operations. The NRC’s inspection results were documented in an NRC letter to APS dated February 1, 2008 (the “Inspection Report”). The Inspection Report indicated that the facility is being operated safely, but also identified certain performance deficiencies. Based on its review of the APS Palo Verde improvement plan, the NRC issued a revised confirmatory action letter (the “Revised CAL”) on February 15, 2008 that outlines the actions APS must take in order for the NRC to return the Palo Verde site to the NRC’s routine inspection and assessment process. This Revised CAL was anticipated as part of the NRC’s inspection procedure and a substantial majority of the actions required therein was contained in APS’ improvement plan.

     The NRC has continued to provide increased oversight at Palo Verde. The Palo Verde management team has implemented a substantial majority of its improvement plan and has been subject to routine periodic NRC inspections throughout 2008. On February 5, 2009, APS submitted a letter to the NRC stating that it has completed a substantial majority of the actions contained in the Revised CAL and believes the Revised CAL can be closed. APS will continue cooperating fully with the NRC throughout this process and anticipates receiving a response from the NRC within the next several months related to the closure of the Revised CAL.

     Nuclear Decommissioning Costs–The NRC rules on financial assurance requirements for the decommissioning of nuclear power plants provide that a licensee may use a trust as the exclusive financial assurance mechanism if the licensee recovers estimated total decommissioning costs through cost-of-service rates or through a “non-bypassable charge.” The “non-bypassable systems benefits” charge is the charge that the ACC has approved for APS’ recovery of certain types of costs. “Non-bypassable” means that if a customer chooses to take energy from an “energy service provider” other than APS, the customer will still have to pay this charge as part of the customer’s APS electric bill.

     Other mechanisms are prescribed, including prepayment, if the requirements for exclusive reliance on an external sinking fund mechanism are not met. APS currently relies on an external sinking fund mechanism to meet the NRC financial assurance requirements for its interests in Palo Verde Units 1, 2 and 3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in APS’ ACC jurisdictional rates. Decommissioning costs are recoverable through a non-bypassable system benefits charge, which allows APS to maintain its external sinking fund mechanism. See Note 12 for additional information about APS’ nuclear decommissioning costs.

     Palo Verde Liability and Insurance Matters– See “Palo Verde Nuclear Generating Station” in Note 11 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.

     Alternative Generation Sources

     In connection with its ongoing resource planning efforts, APS continues to focus on increasing the percentage of its energy that is produced by renewable resources. On November 1,

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2006, the ACC approved the Arizona Renewable Energy Standard and Tariff (the “Renewable Energy Standard”). Under the Renewable Energy Standard, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable energy requirement increases from 1.5% in 2007 to 15% in 2025. The requirement for 2009 is 2.0%. In addition, an increasing percentage of that requirement must be supplied from distributed resources (generally speaking, small-scale renewable technologies that are located on customers’ properties). The distributed resource requirement increases from 5% of the overall renewable energy requirement in 2007 to 30% in 2012 and subsequent years. The requirement for 2009 is 15%. APS currently has a diverse portfolio of renewable resources including wind, geothermal, solar and biomass, which collectively generate over 120 MW of renewable energy for our customers. All of the current renewable generation projects, except for solar, are acquired through long-term purchased power agreements.

     On February 8, 2008, APS entered into a Renewable Energy Purchase and Sale Agreement under which APS agreed to purchase the energy and related renewable energy credits from a concentrated solar power plant for a period of thirty years after the plant begins commercial operation. The plant, which will have a nameplate rating of 280 MW and a projected annual output of 900,000 MWh, will be located near Gila Bend, Arizona, which is about 70 miles southwest of Phoenix. The agreement is subject to various conditions, including the developer obtaining project financing. If these conditions are met, commercial operation is expected in 2012.

     On February 28, 2008, APS signed a Renewable Energy Purchase and Sale Agreement under which APS agreed to purchase the energy and related renewable energy credits from a wind power plant located in New Mexico for a period of thirty years after the plant begins commercial operation in 2009. The plant has a nameplate rating of 100 MW and a projected annual output of 300,000 MWh.

     APS continues to actively consider opportunities to enhance its renewable energy portfolio, both to ensure its compliance with the Renewable Energy Standard and to meet the needs of its customer base.

     Purchased Power Agreements

     In addition to its own available generating capacity, APS purchases electricity under various arrangements. APS’ purchased power capacity under long-term contracts, as of December 31, 2008, is summarized in the table below. APS also purchases power through short-term markets to supplement its long-term resources and hedge its energy requirements.

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		Capacity
Purchased Power Agreement	Dates Available	(MW)
Purchase Agreement (a)	Year-round through February 2013	Up to 90
Purchase Agreement (b)	Year-round through June 15, 2010		238
Exchange Agreement (c)	May 15 to September 15 annually through 2020		480
Tolling Agreement	June 2007 through May 2017		500
Tolling Agreement	June 2010 through October 2019		560
Day-Ahead Call Option Agreement	June 2007 through September 2015 (summer seasons)		500
Day-Ahead Call Option Agreement	June 2007 through summer 2016		150
Wind Agreement	December 2006 through December 2026		90
Wind Agreement	July 19, 2009 through April 2039		100
Landfill Gas Agreement	Deliveries expected to commence in 2009; expires 2029		3
Landfill Gas Agreement	Deliveries expected to commence in September 2009; expires 2029		3
Solar Agreement (d)	Deliveries expected to commence in 2012; expires 2042		250
Geothermal Agreement	January 2006 through 2029		12
Biomass Agreement	July 2008; expires 2023		14

(a)	The capacity under this agreement varies by month, with a maximum capacity of 90 MW.
(b)	The amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually. Effective June 16, 2007, the seller, Salt River Project, reduced the capacity available to APS by 150 MW. Additionally, Salt River Project has elected to cancel this contract effective June 15, 2010.
(c)	This is a seasonal capacity exchange agreement with PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and APS returns a like amount of electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW of capacity and a related amount of energy available to it under the agreement for its respective seasons. Additionally, under a supplemental energy sales agreement, APS must also make additional offers of energy to PacifiCorp each year through October 31, 2020.
(d)	See “Alternative Generation Sources” above for more information.

     APS continually assesses its need for additional capacity resources to assure system reliability, although APS does not expect to need new capacity, beyond current plans, until around 2015. APS remains committed to seeking proposals from the competitive wholesale market for filling its future resource needs, including renewable resource capacity.

     Reserve Margin

     APS’ 2008 peak one-hour demand on its electric system was recorded on August 1, 2008 at 7,025,900 kW, compared to the 2007 peak of 7,545,100 kW recorded on August 13, 2007. Taking into account additional capacity then available to APS under long-term purchase power contracts, as well as APS’ generating capacity, APS’ capability of meeting system demand on August 1, 2008, amounted to 6,883,000 kW, for an installed reserve margin of negative 2.3%. The power actually available to APS from its resources fluctuates from time to time due in part to planned and unplanned

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plant and transmission outages and technical problems. The available capacity from sources actually operable at the time of the 2008 peak amounted to 5,831,000 kW, for a margin of negative 21.9%. Firm purchases totaling 2,626,000 kW, including short-term seasonal purchases and unit contingent purchases, were in place at the time of the peak, ensuring the ability to meet the load requirement with an actual reserve margin of 20.6%.

     Resource Plan

     On January 29, 2009, APS submitted a Resource Plan Report to the ACC proposing a diverse portfolio of generation resources to address the projected 60% increase in customer peak demand by 2025, which equates to approximately 6,500 MW of new capacity resources and accounts for both new resources needed to meet growing customers loads as well as resources that will be needed to replace expiring long-term purchases. The primary components of the Resource Plan include:

• Energy efficiency initiatives;

• The acceleration of renewable energy sources by doubling the Renewable Energy Standard Requirement in 2015, resulting in the addition of over 1,650 MW of renewable resources by 2025;

• The potential for an addition of new baseload nuclear capacity after 2020 of up to 800 MW of capacity; and

• Peaking resources based on gas-fired resources, whether through wholesale purchases or the construction or acquisition of peaking capacity and/or potential additional deployment of demand response opportunities.

     The Resource Plan would allow Arizona to increase its commitment to non-fossil fuel resources because it does not include new coal-fired generation resources. The Resource Plan states that the risk of future climate change legislation and the resulting potential for significant increases in cost currently make coal-fired generation an unattractive resource choice. The Resource Plan also addresses the transmission infrastructure expansion that will be required to accommodate the new resources.

     Under the Resource Plan, APS’ energy mix would change. Nuclear energy would increase to 32% of its mix, renewable energy sources would increase to 16%, and energy efficiency would increase to 7%. Coal-fired energy would decrease to 24% and gas-fired generation would decrease to 21%.

     APS has requested the ACC to (a) either formally approve the Resource Plan or acknowledge that APS has considered all relevant resources, risks and uncertainties and that the Resource Plan is reasonable and in the public interest; (b) determine that the pursuit of renewable resources above the Renewable Energy Standard is in the public interest; (c) determine that taking the initial steps to preserve APS’ ability to pursue a new nuclear baseload resource is in the public interest; and (d) determine that it is appropriate for APS to proceed to implement the Resource Plan. APS cannot predict the outcome of this matter.

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Transmission and Distribution Facilities

     APS’ transmission facilities consist of approximately 5,825 pole miles of overhead lines and approximately 45 miles of underground lines, 5,601 miles of which are located in Arizona. APS’ distribution facilities consist of approximately 11,392 miles of overhead lines and approximately 16,630 miles of underground primary cable, all of which are located in Arizona. APS shares ownership of some of its transmission facilities with other companies. The following table shows APS’ jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2008:

	Percent Owned
	(Weighted Average)
Palo Verde – Estrella 500KV System	55.5%
ANPP 500KV System	35.8%
Navajo Southern System	31.4%
Four Corners Switchyards	27.5%
Palo Verde – Yuma 500KV System	23.9%
Phoenix – Mead System	17.1%

Plant and Transmission Line Leases and Easements on Indian Lands

     The Navajo Generating Station and Four Corners are located on land held under leases from the Navajo Nation and also under easements from the federal government. The easement and lease for the Navajo Generating Station expire in 2019 and the easement and lease for Four Corners expire in 2016. Each of the leases contains an option to extend for an additional 25-year period from the end of the existing lease term, for a rental amount tied to the original rent payment adjusted based on an index. The easements do not contain an express renewal option and it is unclear what conditions to renewal or extension of the easements may be imposed. The ultimate cost of renewal of the Navajo Generating Station and Four Corners leases and easements is uncertain. As noted above under “Portfolio Resources – Coal Fueled Generating Facilities,” the coal contracted for use in these plants is also located on Indian reservations.

     Certain portions of the transmission lines that carry power from several of our power plants are located on Indian lands pursuant to easements or other rights-of-way that are effective for specified periods. Some of these rights-of-way have expired and our renewal applications have not yet been acted upon by the appropriate Indian tribes. Other rights expire at various times in the future and renewal action by the applicable tribe will be required at that time. The majority of our transmission lines residing on Indian lands are on the Navajo Nation. The Four Corners and Navajo Generating Station plant leases provide Navajo Nation consent to certain of the rights-of-way for transmission lines related to those plants at a specified rental rate for the original term of the rights-of-way and for a like payment in any renewal period. In addition, a 1985 amendment to the leases provides a formula for calculating payments for certain new and renewal rights-of-way. However, some of our rights-of-way are not covered by the leases, or are granted by other Indian tribes. In recent negotiations with other utilities or companies for renewal of similar rights-of-way, certain of the affected Indian tribes have required payments substantially in excess of amounts that we have paid in the past for such rights-of-way or that are typical for similar permits across non-Indian lands; however, we are unaware of the underlying agreements and/or specific circumstances surrounding these renewals. The ultimate cost of renewal of the rights-of-way for our transmission lines is

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uncertain. We are monitoring these rights-of-way and easement issues and have initiated discussions with the Navajo Nation regarding them. We are currently unable to predict the outcome of this matter.

Environmental Matters

     EPA Environmental Regulation

     Regional Haze RulesOn April 22, 1999, the EPA announced final regional haze rules. These regulations required states to submit state implementation plans (SIPs) by December 2007 to demonstrate “reasonable progress” towards achieving natural visibility conditions in certain “Class I Areas,” including several on the Colorado Plateau. SIPs are required to consider and potentially apply “best available retrofit technology” (BART) for certain older major stationary sources. The rules allow nine western states and Indian tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule.

     On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional haze rules by providing guidelines, known as the BART guidelines, for states to use in determining which facilities must install controls and the type of controls the facilities must use. The EPA also issued a Revised Annex Rule on October 13, 2006 to address a previous challenge and court remand of that rule.

     ADEQ is currently undertaking a rulemaking process to amend its SIP to reconcile it with the Revised Annex Rule and to implement the Clean Air Visibility Rule requirements. ADEQ’s Regional Haze SIPs were due to EPA Region 9 in December 2007, but are actually expected to be submitted during 2009. As part of the rulemaking process, ADEQ is requiring certain sources in the state to conduct BART analyses. Cholla and West Phoenix received letters from ADEQ asserting that the plants are potentially subject to BART and requesting that we either perform a BART analysis on each plant or provide information demonstrating that we are not subject to BART. We completed a BART analysis for Cholla and submitted our BART recommendations to ADEQ on February 4, 2008. Our recommendations include the installation of certain pollution control equipment that we believe constitutes BART. Once we receive ADEQ’s final determination as to what constitutes BART for Cholla, we will have five years to complete the installation of the equipment and to achieve the emission limits established by ADEQ. However, in order to coordinate with the plant’s other scheduled activities, we are currently implementing portions of our recommended plan for Cholla on a voluntary basis. Costs related to the implementation of these portions of our recommended plan are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in Item 7).

     Because we believed that ADEQ’s baseline modeling for West Phoenix may have contained some errors, we re-performed the baseline modeling using correct input and have determined that West Phoenix is not subject to BART. We submitted these findings for West Phoenix to ADEQ, and ADEQ has verbally informed us that West Phoenix is not subject to BART.

     In addition, EPA Region 9 requested us to perform a BART analysis for Four Corners. We completed the analysis and submitted it to the EPA on January 30, 2008. In December 2008, we provided additional data in response to a request from the EPA. Our recommendations include the installation of certain pollution control equipment that we believe constitutes BART. Once we

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receive the EPA’s final determination as to what constitutes BART for Four Corners, we will have five years to complete the installation of the equipment and to achieve the emission limits established by EPA Region 9. However, in order to coordinate with the plant’s other scheduled activities, we will begin implementing initial portions of our recommended plan later this year for Four Corners on a voluntary basis. Costs related to the implementation of these portions of our recommended plan are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in Item 7).

     While we continue to monitor this matter, at the present time we cannot predict whether the agencies will agree with our BART recommendations or, if the agencies disagree with our recommendations, the nature of the BART controls the agencies may ultimately mandate and the resulting financial or operational impact.

     MercuryOn March 15, 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to control mercury emissions from coal-fired power plants. This rule establishes performance standards limiting mercury emissions from coal-fired power plants and establishes a two phased market-based emissions trading program. Under the trading program, the EPA has assigned each state a mercury emissions “budget” and each state must submit to the EPA a plan detailing how it will meet its “budget.”

     In November 2006, ADEQ submitted a SIP to the EPA to implement the CAMR. ADEQ’s SIP generally incorporates the EPA’s model cap-and-trade program, but it includes additional requirements, including the requirement to meet a 90% mercury removal control level or 0.0087 lbs/GWh, whichever is greater, the requirement to obtain mercury allowances at a 2:1 ratio for any emissions that fall below the specified control level, and the requirement, beginning in 2013, to consider clean coal technologies as part of permitting any new generation.

     On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR and the EPA rule that allowed for the creation of the CAMR, and on March 14, 2008, the court issued the mandate to vacate these rules. On May 20, 2008, the D.C. Circuit denied the EPA’s request to reconsider its decision. On October 17, 2008, the U.S. Solicitor General, on behalf of the EPA, petitioned the Supreme Court for a writ of certiorari to review the judgment of the D.C. Circuit Court of Appeals’ vacatur of the CAMR. In filing the petition, the U.S. contended, among other things, that the Court of Appeals’ decision “effectively divests EPA of the discretion that Congress conferred on the agency to consider alternative regulatory approaches to combating air pollution from power plants.” Unless and until this decision is overturned, the law in effect prior to the adoption of the CAMR becomes the applicable law, and requires the EPA to develop an emission limit for mercury that represents the maximum achievable control technology. It is expected to take the EPA several years to establish its standard, followed by a period of several years during which existing plants would implement any controls needed to comply with the standard.

     The court’s ruling also invalidates CAMR-based portions of ADEQ’s mercury rule (the trading provisions of the rule), although the state-only emission limits remain in effect. On July 25, 2008, the Arizona Utilities Group (comprised of APS, Arizona Electric Power Cooperative, Salt River Project, Tucson Electric Power Company, and Tri-State Generation and Transmission Association) filed with ADEQ a Petition for Reconsideration and Repeal of the state mercury rule. The petition asserts that ADEQ does not have statutory authority to administer and enforce the state mercury rule, in light of the vacatur of the CAMR and the requirement that EPA promulgate a Maximum Achievable Control Technology (“MACT”) standard. ADEQ granted the petition in part

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and agreed to begin rulemaking efforts to repeal those portions of ADEQ’s mercury rule that are no longer valid in light of the vacatur of the federal CAMR. However, ADEQ denied the petition with respect to certain compliance deadlines and, unless the Arizona Utilities Group reaches an agreement with ADEQ on revisions to the state mercury rule, APS and others will have to comply with the 90% mercury removal or 0.0087 lbs/GWh levels discussed above by 2013. On February 17, 2009, APS signed a consent order with ADEQ under which APS will strive to achieve 50% mercury removal commencing in 2011 and will fully comply with the ADEQ mercury rule by 2016, rather than by 2013 as the rule currently prescribes.

     While we continue to monitor this matter, we cannot predict the final outcome of the petition to the Supreme Court, additional actions by ADEQ resulting from the federal court’s decision or the Arizona Utilities Group petition, or the scope, timing or impact of any alternate rules that may be enacted to address mercury emissions.

     We have installed, and continue to install, certain of the equipment necessary to meet the current mercury standards. However, due to the U.S. Court of Appeals decision described above, we will monitor the type and timing of any necessary equipment installation. The estimated costs expected to be incurred over the next three years for such equipment are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in Item 7).

     Federal Implementation PlanIn September 1999, the EPA proposed FIPs to set air quality standards at certain power plants, including Four Corners and the Navajo Generating Station. On September 12, 2006, the EPA proposed revised FIPs to establish air quality standards at both of these plants.

     Four Corners FIP

     On April 30, 2007, the EPA adopted a source specific FIP to set air quality standards at Four Corners. The FIP essentially federalizes the requirements contained in the New Mexico State Implementation Plan, which Four Corners has historically followed. The FIP also includes a requirement to maintain and enhance dust suppression methods. On July 2, 2007, APS filed a petition for review in the United States District Court of Appeals for the Tenth Circuit seeking revisions to the FIP to clarify certain requirements and allow operational flexibility. The Sierra Club intervened in this action. On July 6, 2007, the Sierra Club and other parties filed a petition for review with the same court challenging the FIP’s compliance with the Clean Air Act and we have intervened in their action. In our lawsuit, we challenge two key provisions of the FIP: a 20% opacity limit on certain fugitive dust emissions, which the EPA filed a motion to remand and vacate in early December 2007, and a 20% stack opacity limit on Units 4 and 5. Briefing in this case is now complete, and oral arguments as requested by the EPA were completed in May 2008. After briefing was completed, the EPA voluntarily moved to vacate the fugitive dust provisions of the FIP. The court has not yet ruled on that motion; however, in light of that motion, APS asked for, and the EPA granted, an administrative stay of the fugitive dust provisions, and the Navajo Nation EPA amended our Four Corners permit to specify that those requirements do not apply unless and until the court denies the EPA’s motion. Although we cannot predict the outcome or the timing of these matters, we do not believe that they will have a material adverse impact on our financial position, results of operations or cash flows.

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     Navajo Generating Station FIP

     The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently predict the effect of this proposed FIP on its financial position, results of operations or cash flows, or whether the proposed FIP will be adopted in its current form.

     SuperfundSuperfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.

     By letter dated April 25, 2008, the EPA informed APS that it may be a PRP in the Gila River Indian Reservation Superfund Site in Maricopa County, Arizona. APS, along with three other electric utility companies, owns a parcel of property on which a transmission pole and a portion of a transmission line are located. The property abuts the Gila River Indian Community boundary and, at one time, may have been part of an airfield where crop dusting took place. Currently, the EPA is only seeking payment from APS and four other PRPs for past cleanup-related costs involving contamination from the crop dusting. Based upon the total amount of cleanup costs reported by the EPA in its letter to APS, we do not expect that the resolution of this matter will have a material adverse impact on our financial position, results of operations, or cash flows.

     Manufactured Gas Plant SitesAPS is currently investigating properties, which it now owns or which were previously owned by it or its corporate predecessors, that were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations, cash flows or liquidity.

     Navajo Nation Environmental Issues

     Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. See “Portfolio Resources – Coal Fueled Generating Facilities” above for additional information regarding these plants.

     In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the “Navajo Acts”). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those activities that occur at Four Corners and the Navajo Generating Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Generating

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Station. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement.

     In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners and the Navajo Generating Station. On July 12, 2000, the Four Corners participants and the Navajo Generating Station participants each filed a petition with the Navajo Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.

     On May 18, 2005, APS, Salt River Project, as the operating agent for the Navajo Generating Station, and the Navajo Nation executed a Voluntary Compliance Agreement (“VCA”) to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. On March 21, 2006, the EPA determined that the Navajo Nation was eligible for “treatment as a state” for the purpose of entering into a supplemental delegation agreement with the EPA to administer the Clean Air Act Title V, Part 71 federal permit program over Four Corners and the Navajo Generating Station. The EPA entered into the supplemental delegation agreement with the Navajo Nation on the same day. Because the EPA’s approval was consistent with the requirements of the VCA, APS sought dismissal of the pending litigation in the Navajo Nation Supreme Court, as well as the pending litigation in the Navajo Nation District Court to the extent the claims relate to the Clean Air Act, and the Courts have dismissed the claims accordingly. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.

Water Supply

     Assured supplies of water are important for APS’ generating plants. At the present time, APS has adequate water to meet its needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions.

     Both groundwater and surface water in areas important to APS’ operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

     A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County, Arizona, Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’ rights and the rights of the other Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Five of APS’ other power plants are also located within the geographic area subject to the summons. APS’ claims dispute the court’s jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks

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confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’ water rights claims has been set in this matter.

     APS has also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’ claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. A number of parties are in the process of settlement negotiations with respect to certain claims in this matter. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’ water rights claims has been set in this matter.

     Although the above matters remain subject to further evaluation, APS does not expect that the described litigation will have a material adverse impact on its financial position, results of operations, cash flows or liquidity.

     The Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. APS is continuing to work with area stakeholders to implement agreements to minimize the effect, if any, on future operations of the plant. The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners.

Climate Change

     Legislative and Regulatory Initiatives.In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions, but such bills have not yet received sufficient Congressional approval to become law; however, there is growing consensus that some form of regulation or legislation is likely to occur in the near future at the federal level with respect to greenhouse gas emissions. In 2007, the United States Supreme Court ruled that greenhouse gases fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, the EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under the Clean Air Act. The court held that the only way the EPA can avoid regulating greenhouse gases is if it determines that the emissions do not contribute to climate change, or if the EPA provides a reasonable explanation for why it cannot or will not exercise its discretion to regulate these emissions. While this decision applies only to emissions from new motor vehicles, if the EPA determines that greenhouse gas emissions can reasonably be anticipated to endanger public health or welfare, this determination will likely impact other Clean Air Act programs as well, and could potentially result in new regulatory requirements for our power plants.

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     In addition to federal legislative initiatives, state specific initiatives may also impact our business. While Arizona has not yet enacted any state specific legislation regarding greenhouse gas emissions, AB 32 is a California statute mandating the reduction of greenhouse gas emissions to 1990 levels by 2020. In December 2008, the California Air Resources Board issued a final scoping plan which is intended to form the basis of rules required under AB 32. On January 1, 2012, the regulations based on the 2009 scoping plan will become effective. We are monitoring this and other state legislative developments to evaluate whether, and the extent to which, any resulting statutes or rules in California or other states may affect our business, including our sales into the impacted states or the ability of our out-of-state power plant participants to meet their obligations.

     If any emission reduction legislation or regulations are enacted, we will assess our compliance alternatives, which may include replacement of existing equipment, installation of additional pollution control equipment, purchase of allowances, curtailing certain operations, or other actions. Although associated capital expenditures or operating costs resulting from greenhouse gas emission regulations or legislation could be material, we believe that we would be able to recover the costs of these environmental compliance initiatives through our rates.

     Regional Initiative.In 2007, six western states (Arizona, California, New Mexico, Oregon, Utah and Washington) and two Canadian provinces (British Columbia and Manitoba) entered into an accord, the Western Climate Initiative (the “Initiative”), to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. Montana, Quebec and Ontario have also joined the Initiative. In August 2007, the Initiative participants set a goal of reducing greenhouse gas emissions 15% below 2005 levels by 2020. Since May 2008, several draft documents have been issued for public comment. We are reviewing the recommendations and requirements in these documents, which currently provide only a general framework for the proposed program. Over the next year, the Initiative participants intend to develop detailed rules to more fully establish and define the program. Since details are not yet available, such as the number of allowances each source may receive, we are unable to quantify the potential financial and operational impacts on our business. In addition, we believe that the implementation of any such program in Arizona would require legislative action. As a result, while we continue to monitor the progress and impact of the Initiative, at the present time we cannot predict what detailed form it will ultimately take, whether it will be implemented or, if it is implemented, what impact it will have on our operations.

     Company Response to Climate Change Initiatives.We have undertaken a number of initiatives to address emission concerns, including renewable energy procurement and development, promotion of programs and rates related to energy conservation, renewable energy use and energy efficiency, and implementation of an active technology innovation effort to evaluate potential emerging new technologies. APS currently has a diverse portfolio of renewable resources including wind, geothermal, solar and biomass and we are focused on increasing the percentage of our energy that is produced by renewable resources. (See “Portfolio Resources – Alternative Generation Sources” above.) In January 2009, we submitted a Resource Plan Report to the ACC proposing our future plans for additional diverse resources. See “Portfolio Resources – Resource Plan” above for information regarding the Resource Plan Report, which was designed, in part, to increase Arizona’s commitment to non-fossil resources.

     In addition, we are currently developing a Climate Management Report to comply with an ACC order that directed APS to undertake a climate management plan, carbon emission reduction study and commitment and action plan with public input and ACC review. We expect to complete the report in early 2009.

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     In January 2008, APS joined the Climate Registry as a Founding Reporter. Founding Reporters are companies that voluntarily joined the non-profit organization before May 2008 to measure and report greenhouse gas emissions in a common, accurate and transparent manner consistent across industry sectors and borders. Pinnacle West has also reported, and will continue to report, greenhouse gas emissions in its annual Corporate Responsibility Report, which is available on our website(www.pinnaclewest.com). In addition to emissions data, the report provides information related to the Company, its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.

BUSINESS OF SUNCOR DEVELOPMENT COMPANY

     SunCor was incorporated in 1965 under the laws of Arizona and is a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. The principal executive offices of SunCor are located at 80 East Rio Salado Parkway, Suite 410, Tempe, Arizona 85281 (telephone 480-317-6800). SunCor and its subsidiaries had approximately 480 employees at December 31, 2008.

     At December 31, 2008, SunCor had total assets of about $547 million. SunCor’s assets consist primarily of land with improvements, commercial buildings, golf courses and other real estate investments. SunCor focuses on real estate development of master-planned communities, and mixed-use residential, commercial, office and industrial projects.

     SunCor projects include six master-planned communities and several commercial and residential projects. Four of the master-planned communities and the commercial and residential projects are in Arizona. Other master-planned communities are located in Idaho, New Mexico and Utah.

     SunCor’s operating revenues were approximately $131 million in 2008, $213 million in 2007 and $400 million in 2006. SunCor’s net loss was approximately $26 million in 2008. SunCor’s net loss in 2008 included a $53 million (pre-tax) real estate impairment charge. SunCor’s net income was approximately $24 million in 2007 and $61 million in 2006. Certain components of SunCor’s real estate sales activities, which are included in the real estate segment, are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” See Notes 22 and 23.

     See “Liquidity and Capital Resources – Other Subsidiaries – SunCor” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of SunCor’s long-term debt, liquidity and capital requirements.

BUSINESS OF OTHER SUBSIDIARIES

     APSES was incorporated in 1998 under the laws of Arizona and provides energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation, and project management) and competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) to commercial and industrial retail customers in the western United States. Recently, APSES has discontinued its commodity-related energy services (see Note 22). APSES had

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approximately 60 employees as of December 31, 2008. APSES’ principal offices are located at 60 E. Rio Salado Parkway, Suite 1001, Tempe, Arizona 85281 (telephone 602-744-5060).

     APSES had a net loss of $1 million in 2008, a net loss of $4 million in 2007 and a net loss of $3 million in 2006. At December 31, 2008, APSES had total assets of $70 million.

     El Dorado was incorporated in 1983 under the laws of Arizona. El Dorado owns minority interests in several energy-related investments and Arizona community-based ventures. El Dorado’s short-term goal is to prudently realize the value of its existing investments. On a long-term basis, Pinnacle West may use El Dorado, when appropriate, for investments that are strategic to the business of generating, distributing and marketing electricity. El Dorado’s offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-3517).

     El Dorado had a net loss of $10 million in 2008, a net loss of $6 million in 2007 and a net loss of $4 million in 2006. Income taxes related to El Dorado are recorded by Pinnacle West. At December 31, 2008, El Dorado had total assets of $28 million.

ITEM 1A. RISK FACTORS

     In addition to the factors affecting specific business operations identified in connection with the description of these operations contained elsewhere in this report, set forth below are risks and uncertainties that could affect our financial results. Unless otherwise indicated or the context otherwise requires, the following risks and uncertainties apply to Pinnacle West and its subsidiaries, including APS.

     APS is subject to comprehensive government regulation by several federal, state and local regulatory agencies that could have a material adverse impact on its business, liquidity and results of operations.

     APS is subject to comprehensive regulation by several federal, state and local regulatory agencies that significantly influence its business, liquidity and results of operations. The ACC regulates APS’ retail electric rates and APS’ issuance of securities. The ACC must also approve any transfer of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between us, APS and our respective affiliates. While approved electric rates are intended to permit APS to recover its costs of service and earn a reasonable rate of return, the profitability of APS is affected by the rates it may charge. Consequently, our financial condition and results of operations are dependent upon the satisfactory resolution of APS’ retail rate proceedings and ancillary matters which are before or which may come before the ACC. Decisions made by the ACC could have a material adverse impact on our results of operations, financial position or liquidity.

     APS is required to have numerous permits, approvals and certificates from the agencies that regulate APS’ business. The FERC, the NRC, the EPA, and the ACC regulate many aspects of our utility operations, including siting and construction of facilities, customer service and, as noted in the preceding paragraph, the rates that APS can charge customers. We believe the necessary permits, approvals and certificates have been obtained for APS’ existing operations and that APS’ business is conducted in accordance with applicable laws in all material respects. However, changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations. We are also unable to predict the impact on our business and operating results from pending or future regulatory activities of any of these agencies.

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     The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime that could ultimately result in the shut down of a unit, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. In early 2007, the NRC placed Palo Verde Unit 3 in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), which has resulted in an enhanced NRC inspection regime, including on-site in-depth inspections of Palo Verde equipment and operations. Although only Palo Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need for improvements, APS management has been conducting site-wide assessments of equipment and operations. APS continues to cooperate fully with the NRC throughout this process. The enhanced NRC inspection regime and APS’ ongoing commitment to the conservatively safe operation of Palo Verde could result in NRC action or an APS decision to shut down one or more units in the event of noncompliance with operating requirements or in light of other operational considerations.

     APS is subject to numerous environmental laws and regulations that may increase its cost of operations, impact its business plans, or expose it to environmental liabilities.

     APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, hazardous waste, and coal combustion products, which consist of bottom ash, fly ash and air pollution control wastes. These laws and regulations can result in increased capital, operating, and other costs, particularly with regard to enforcement efforts focused on power plant emissions obligations. These laws and regulations generally require APS to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if APS fails to obtain, maintain or comply with any such approval, operations at affected facilities could be suspended or subject to additional expenses. In addition, failure to comply with applicable environmental laws and regulations could result in civil liability or criminal penalties. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.

     In addition, we may be a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

     We cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs incurred by APS are not fully recoverable from APS’ customers, could have a material adverse effect on our financial position, results of operations or cash flows.

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     Concern over climate change could result in significant legislative and regulatory efforts to limit greenhouse gas emissions or related litigation, which may increase APS’ cost of operations.

     Concern over climate change, deemed by many to be induced by rising levels of greenhouse gases in the atmosphere, has led to significant legislative and regulatory efforts to limit CO₂, which is a major byproduct of the combustion of fossil fuel, and other greenhouse gas emissions. In addition, lawsuits have been filed against companies that emit greenhouse gases, including a lawsuit filed against us and several other utilities, seeking damages related to climate change. In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions, but such bills have not received sufficient Congressional approval to date to become law; however, there is growing consensus that some form of regulation or legislation is likely to occur in the near future at the federal level with respect to greenhouse gas emissions. In addition, in 2007, the United States Supreme Court ruled that greenhouse gases fit within the Clean Air Act’s broad definition of “air pollutant” and, as a result, the EPA has the authority to regulate greenhouse gas emissions of new motor vehicles under the Clean Air Act. If the United States Congress, or individual states or groups of states in which we operate, ultimately pass legislation regulating the emissions of greenhouse gases, any resulting limitations on generation facility CO₂ and other greenhouse gas emissions could result in the creation of substantial additional capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades and could have a material adverse impact on all fossil fuel fired generation facilities (particularly coal fired facilities, which constitute approximately 28% of our generation capacity). If the EPA determines that greenhouse gas emissions can reasonably be anticipated to endanger public health or welfare, this determination may impact other Clean Air Act Programs and could potentially result in new regulatory requirements for our power plants, which could also result in substantial additional costs. Excessive costs to comply with future legislation or regulations could force APS and other similarly-situated electric power generators to close some coal-fired facilities.

     There are inherent risks in the ownership and operation of nuclear facilities, such as environmental, health, regulatory and financial risks and the risk of terrorist attack.

     Through APS, we have an ownership interest in and operate, on behalf of a group of owners, Palo Verde, which is the largest nuclear electric generating facility in the United States. Palo Verde is subject to environmental, health and financial risks such as the ability to dispose of spent nuclear fuel; the ability to maintain adequate reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; and unscheduled outages due to equipment and other problems. APS maintains nuclear decommissioning trust funds and external insurance coverage to minimize its financial exposure to some of these risks; however, it is possible that damages could exceed the amount of insurance coverage.

     The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime, which could ultimately result in the shut down of a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. See the first risk factor above for a discussion of the enhanced NRC inspection regime currently in effect at Palo Verde and the related operational and regulatory implications. In addition, although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and

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adversely affect our results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.

     The operation of Palo Verde requires licenses that need to be periodically renewed and/or extended. In December 2008, we applied for renewed operating licenses for all three Palo Verde units for 20 years beyond the expirations of the current licenses. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.

     The operation of power generation facilities involves risks that could result in unscheduled power outages or reduced output, which could materially affect our results of operations.

     The operation of power generation facilities involves certain risks, including the risk of breakdown or failure of equipment, fuel interruption, and performance below expected levels of output or efficiency. Unscheduled outages, including extensions of scheduled outages due to mechanical failures or other complications occur from time to time and are an inherent risk of our business. If APS’ facilities operate below expectations, we may lose revenue or incur additional expenses, including increased purchased power expenses.

     The ownership and operation of power generation and transmission facilities on Indian lands could result in uncertainty related to continued easements and rights-of-way, which could have a significant impact on our business.

     Certain portions of the transmission lines that carry power from several of our power plants are located on Indian lands pursuant to easements or other rights-of-way that are effective for specified periods. We are currently unable to predict the outcome of discussions with the appropriate Indian tribes with respect to future renewal of these easements and rights-of-way.

     Deregulation or restructuring of the electric industry may result in increased competition, which could have a significant adverse impact on our business and our results of operations.

     In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. Retail competition could have a significant adverse financial impact on APS due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

     As a result of changes in federal law and regulatory policy, competition in the wholesale electricity market has greatly increased due to a greater participation by traditional electricity suppliers, non-utility generators, independent power producers, and wholesale power marketers and brokers. This increased competition could affect APS’ load forecasts, plans for power supply and wholesale energy sales and related revenues. As a result of the changing regulatory environment and

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the relatively low barriers to entry, we expect wholesale competition to increase, which could adversely affect our business.

     Changes in technology may adversely affect our business.

     Research and development activities are ongoing to improve alternative technologies to produce power, including fuel cells, micro turbines, clean coal and coal gasification, photovoltaic (solar) cells and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these, or other technologies could reduce the cost of power production, making APS’ generating facilities less competitive. In addition, advances in technology could reduce the demand for power supply, which could adversely affect APS’ business.

     Our results of operations can be adversely affected by weather conditions.

     Weather conditions directly influence the demand for electricity and affect the price of energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, our overall operating results fluctuate substantially on a seasonal basis. In addition, APS has historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish our results of operations and harm our financial condition.

     Higher temperatures may decrease the snowpack, which might result in lowered soil moisture and an increased threat of forest fires. Forest fires could threaten our communities and electric transmission lines. Any damage caused as a result of forest fires could negatively impact our results of operations.

     Our results of operations can be adversely affected by current economic conditions.

     Customer growth in APS’ service territory was 1.4% during 2008. Customer growth averaged 3% a year for the three years 2006 through 2008. We currently expect customer growth to decline, averaging about 1% per year for 2009 through 2011 due to factors reflecting the economic conditions both nationally and in Arizona. We currently expect our retail sales growth in 2009 to be below average because of potential effects on customer usage from the economic conditions mentioned above and retail rate increases, which would adversely affect our results of operations.

     The lack of access to sufficient supplies of water could have a material adverse impact on our business and results of operations.

     Assured supplies of water are important for APS’ generating plants. Water in the southwestern United States is limited and various parties have made conflicting claims regarding the right to access and use such limited supply of water. Both groundwater and surface water in areas important to APS’ generating plants have been the subject of inquiries, claims and legal proceedings. In addition, the Four Corners region, in which Four Corners is located, has been experiencing drought conditions that may affect the water supply for the plants if adequate moisture is not received in the watershed that supplies the area. Our inability to access sufficient supplies of water could have a material adverse impact on our business and results of operations.

     Our cash flow largely depends on the performance of our subsidiaries.

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     We conduct our operations primarily through subsidiaries. Substantially all of our consolidated assets are held by such subsidiaries. Accordingly, our cash flow is dependent upon the earnings and cash flows of these subsidiaries and their distributions to us. The subsidiaries are separate and distinct legal entities and have no obligation to make distributions to us.

     The debt agreements of some of our subsidiaries may restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. An ACC financing order requires APS to maintain a common equity ratio of at least 40% and does not allow APS to pay common dividends if the payment would reduce its common equity below that threshold. The common equity ratio, as defined in the ACC order, is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt.

     Our ability to meet our debt service obligations could be adversely affected because our debt securities are structurally subordinated to the debt securities and other obligations of our subsidiaries.

     Because we are structured as a holding company, all existing and future debt and other liabilities of our subsidiaries will be effectively senior in right of payment to our debt securities. None of the indentures under which we or our subsidiaries may issue debt securities limits our ability or the ability of our subsidiaries to incur additional debt in the future. The assets and cash flows of our subsidiaries will be available, in the first instance, to service their own debt and other obligations. Our ability to have the benefit of their assets and cash flows, particularly in the case of any insolvency or financial distress affecting our subsidiaries, would arise only through our equity ownership interests in our subsidiaries and only after their creditors have been satisfied.

     Our inability to reduce capital expenditures could materially and adversely affect our business, financial condition and results of operation.

     Unexpected developments that may prevent us from reducing capital expenditures and other costs while maintaining reliability and customer service levels could have a material adverse impact on our financial position, results of operations, cash flows or liquidity.

     Financial market disruptions may increase our financing costs or limit our access to the credit markets, which may adversely affect our liquidity and our ability to implement our financial strategy.

     We rely on access to short-term money markets, longer-term capital markets and the bank markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets. However, certain market disruptions may increase our cost of borrowing or adversely affect our ability to access one or more financial markets. Such disruptions could include:

• continuation of the current economic downturn;

• the bankruptcy of an unrelated energy company;

• increased market prices for electricity and gas;

• terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies;

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• changes in technology;

• mergers among financial institutions and the overall health of the banking industry; or

• the overall health of the utility or real estate industry.

     In addition, the credit commitments of our lenders under our bank facilities may not be satisfied for a variety of reasons, including unexpected periods of financial distress, which could materially adversely affect the adequacy of our liquidity sources.

     Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by:

• increasing the cost of future debt financing;

• increasing our vulnerability to adverse economic and industry conditions;

• requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes; and

• placing us at a competitive disadvantage compared with our competitors that have less debt.

     Recent sub-prime mortgage issues, the collapse of the credit markets, the weak housing market and the overall weakening of the economy have adversely affected the financial markets, generally resulting in increased interest rates for corporate debt, reduced access to the capital markets, and actual or potential downgrades of bond insurers and banks, among other negative matters. In general, the Company and APS have been unable to access the commercial paper markets since September 2008. As a result, existing bank lines have been used as a source of liquidity on which we depend. In addition, the interest rates on certain issues of APS’ pollution control bonds that are periodically reset through auction processes have recently increased. These bonds are supported by bond insurance policies provided by Ambac Assurance Corporation (“Ambac”), and the interest rates on those bonds are directly affected by the rating of the bond insurer. We do not expect, however, that any such increase will have a material adverse impact on our financial position, results of operations, cash flows or liquidity.

     The 2007 and 2008 financial results of SunCor, our real estate subsidiary, reflect the weak real estate market and current economic conditions. SunCor’s principal loan facility is secured primarily by an interest in land, commercial properties, land contracts and homes under construction (the “Secured Revolver”). At December 31, 2008, SunCor had borrowings of approximately $120 million under this facility. The Secured Revolver matures on January 30, 2010. In addition to the Secured Revolver, at December 31, 2008, SunCor had approximately $68 million of outstanding debt under other credit facilities that mature at various dates and also contain certain loan covenants. The majority of this indebtedness is due in 2009, and SunCor is in the process of renegotiating these facilities.

     If SunCor is unable to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such a debt acceleration would have a material adverse impact on SunCor’s business and its financial position. The Company has not guaranteed any SunCor indebtedness. As a result, the Company does not believe that SunCor’s inability to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities would have a material adverse impact on Pinnacle West’s cash flows or liquidity, although any resulting SunCor losses would be reflected in Pinnacle West’s consolidated financial statements.

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     A reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.

     We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade or withdrawal could adversely affect the market price of Pinnacle West’s and APS’ securities, limit our access to capital and increase our borrowing costs, which would diminish our financial results. We would be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. In addition, borrowing costs under certain of our existing credit facilities depend on our credit ratings. A downgrade would also require us to provide substantial additional support in the form of letters of credit or cash or other collateral to various counterparties. If our short-term ratings were to be lowered, it could completely eliminate any possible future access to the commercial paper market. We note that the ratings from rating agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating.

     The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.

     Our operations include managing market risks related to commodity prices and, subject to specified risk parameters, engaging in marketing and trading activities intended to profit from market price movements. We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas and coal, to the extent that unhedged positions exist. We have established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity. To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time.

     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties are rated as investment grade by the rating agencies, there is still a possibility that one or more of these companies could default, which could result in a material adverse impact on our earnings for a given period.

     Changing interest rates and market conditions could result in financial losses that negatively impact our results of operations.

     Changing interest rates affect interest paid on variable-rate debt and interest earned on variable-rate securities in our pension plan, other postretirement benefit plan and nuclear decommissioning trust funds. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan and other postretirement benefit liabilities are also impacted by the discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations. Declining interest rates impact the discount rate, and may result in increases in pension and other postretirement benefit costs, cash contributions, regulatory assets, and charges to other comprehensive income. The pension plan, other postretirement benefit and

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nuclear decommissioning trust funds also have risks associated with changing market values of fixed income and equity investments. A significant portion of the pension costs and other postretirement benefit costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices.

     The market price of our common stock may be volatile.

     The market price of our common stock could be subject to significant fluctuations in response to factors such as the following, some of which are beyond our control:

• variations in our quarterly operating results;

• operating results that vary from the expectations of management, securities analysts and investors;

• changes in expectations as to our future financial performance, including financial estimates by securities analysts and investors;

• developments generally affecting industries in which we operate, particularly the energy distribution and energy generation industries;

• announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;

• announcements by third parties of significant claims or proceedings against us;

• favorable or adverse regulatory or legislative developments;

• our dividend policy;

• future sales by the Company of equity or equity-linked securities; and

• general domestic and international economic conditions.

     In addition, the stock market in general has experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the market price of our common stock.

     Our stock price could be affected because a substantial number of shares of our common stock could be available for sale in the future.

     Sales in the public market of a substantial number of shares of common stock could depress the market price of the common stock and could impair our ability to raise capital through the sale of additional equity securities. Because of the number of shares of our common stock that we are authorized to issue under our articles of incorporation, a substantial number of shares of our common stock could be available for future sale.

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     We may enter into credit and other agreements from time to time that restrict our ability to pay dividends.

     Payment of dividends on our common stock may be restricted by credit and other agreements entered into by us from time to time. There are currently no material restrictions on our ability to pay dividends under any such agreement.

     Certain provisions of our articles of incorporation and bylaws and of Arizona law make it difficult for shareholders to change the composition of our board and may discourage takeover attempts.

     These provisions, which could preclude our shareholders from receiving a change of control premium, include the following:

• restrictions on our ability to engage in a wide range of “business combination” transactions with an “interested shareholder” (generally, any person who owns 10% or more of our outstanding voting power or any of our affiliates or associates) or any affiliate or associate of an interested shareholder, unless specific conditions are met;

• anti-greenmail provisions of Arizona law and our bylaws that prohibit us from purchasing shares of our voting stock from beneficial owners of more than 5% of our outstanding shares unless specified conditions are satisfied;

• a requirement that shareholder action be taken only at an annual or special meeting or by unanimous written consent, and bylaws that require that only a majority of our Board of Directors, the Chairman of our Board of Directors, or our President may call a special meeting of shareholders;

• advance notice procedures for nominating candidates to our Board of Directors or presenting matters at shareholder meetings;

• shareholders may only remove a director with or without cause by a majority vote at a special meeting of shareholders;

• the ability of the Board of Directors to increase the size of the Board and fill vacancies on the Board, whether resulting from such increase, or from death, resignation, disqualification or otherwise; and

• the ability of our Board of Directors to issue additional shares of common stock and shares of preferred stock and to determine the price and, with respect to preferred stock, the other terms, including preferences and voting rights, of those shares without shareholder approval.

     In addition, we have adopted a shareholder rights plan that may have the effect of discouraging unsolicited takeover proposals, including takeover proposals that could result in a premium over the market price of our common stock. The shareholder rights plan will expire on March 26, 2009.

     While these provisions have the effect of encouraging persons seeking to acquire control of us to negotiate with our Board of Directors, they could enable the Board to hinder or

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frustrate a transaction that some, or a majority, of our shareholders might believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors.

     SunCor’s business and financial performance could continue to be adversely affected by a variety of factors affecting the real estate market.

     SunCor’s business and financial performance could continue to be adversely affected by a variety of factors affecting the real estate market, including:

• downward changes in general economic, real estate construction or other business conditions;

• the current economic down cycle for the homebuilding industry;

• the increase in foreclosures;

• reductions in mortgage availability, future increases in interest rates or increases in the effective costs of owning a home, which could prevent potential customers from buying homes in SunCor’s developments;

• future increases in interest rates which could limit future sales of commercial property and land;

• competition for homebuyers or commercial customers or partners, which could reduce SunCor’s profitability;

• supply shortages and other risks related to the demand for skilled labor and building materials, which could increase costs and delay deliveries; and

• government regulations, which could increase the cost and limit the availability of SunCor’s development, homebuilding and commercial projects.

     As noted above (see the Risk Factor relating to “financial market disruptions”), at December 31, 2008, SunCor had borrowings of approximately $120 million under its principal loan facility, the Secured Revolver. The Secured Revolver matures on January 30, 2010. In addition to the Secured Revolver, at December 31, 2008, SunCor had approximately $68 million of outstanding debt under other credit facilities that mature at various dates and also contain certain loan covenants. The majority of this indebtedness is due in 2009, and SunCor is in the process of renegotiating these facilities.

     If SunCor is unable to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such a debt acceleration would have a material adverse impact on SunCor’s business and its financial position. The Company has not guaranteed any SunCor indebtedness. As a result, the Company does not believe that SunCor’s inability to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities would have a material adverse impact on Pinnacle West’s cash flows or liquidity, although any resulting SunCor losses would be reflected in Pinnacle West’s consolidated financial statements.

     During 2008 the real estate market weakened significantly resulting in lower land and home sales and depressed real estate prices. As a result, in 2008 we recognized certain impairment charges. If conditions in the broader economy or the real estate markets worsen, or as a result of a change in SunCor’s strategy, we may be required to record additional impairements.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

     Neither Pinnacle West nor APS has received written comments regarding its periodic or current reports from the SEC staff that were issued 180 days or more preceding the end of its 2008 fiscal year and that remain unresolved.

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ITEM 2. PROPERTIES

Information Regarding Our Properties

     See “Business of Arizona Public Service Company – Portfolio Resources” in Item 1 for the location and a description of our principal properties.

     See “Business of Arizona Public Service Company – Environmental Matters” and “Water Supply” in Item 1 with respect to matters having a possible impact on the operation of certain of APS’ power plants.

     See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 for a discussion of APS’ construction program.

Real Estate Segment Properties

     See “Business of SunCor Development Company” in Item 1 for information regarding SunCor’s properties. Substantially all of SunCor’s debt is collateralized by interests in certain real property.

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37

ITEM 3. LEGAL PROCEEDINGS

     See “Business of Arizona Public Service Company – Environmental Matters” and “Water Supply” in Item 1 with regard to pending or threatened litigation and other disputes.

     See Note 3 with respect to retail rate proceedings before the ACC.

     See Note 11 with regard to a lawsuit against APS and the other Navajo Generating Station participants, for information relating to the FERC proceedings on California and Pacific Northwest energy market issues, and for information regarding a billing dispute with SRP.

ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS

     Not applicable.

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SUPPLEMENTAL ITEM.
EXECUTIVE OFFICERS OF PINNACLE WEST

Pinnacle West’s executive officers are as follows:

Name	Age at February 20, 2009		Position(s) at February 20, 2009
William J. Post		58	Chairman of the Board and Chief Executive Officer (1)
Donald E. Brandt		54	President and Chief Operating Officer, and Chief Executive Officer of APS (1)
James R. Hatfield		51	Senior Vice President and Chief Financial Officer
John R. Denman		66	Senior Vice President, Fossil Operations, APS
Randall K. Edington		55	Executive Vice President and Chief Nuclear Officer, APS
Chris N. Froggatt		51	Vice President and Treasurer
Barbara M. Gomez		54	Vice President, Controller and Chief Accounting Officer
Nancy C. Loftin		55	Senior Vice President, General Counsel and Secretary
Donald G. Robinson		55	President and Chief Operating Officer, APS
Lori S. Sundberg		45	Vice President, Human Resources, APS
Steven M. Wheeler		60	Executive Vice President, Customer Service and Regulation, APS

(1) Member of the Board of Directors.

     The executive officers of Pinnacle West are elected no less often than annually and may be removed by the Board of Directors at any time. The terms served by the named officers in their current positions and their principal occupations (in addition to those stated in the table) of such officers for the past five years have been as follows:

     Mr. Post was elected Chairman of the Board effective February 2001, and Chief Executive Officer effective February 1999. He has served as an officer of Pinnacle West since 1995 in the following capacities: from August 1999 to February 2001 as President; from February 1997 to

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February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr. Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until October 2002. Mr. Post has announced that he will retire effective April 30, 2009. He will remain a member of the Company’s Board of Directors and APS’ Board of Directors.

     Mr. Brandt was elected to the Board of Directors of the Company and APS in January 2009. Effective April 30, 2009, Mr. Brandt will continue to serve as President of Pinnacle West and will also assume the positions of Pinnacle West’s Chairman of the Board and Chief Executive Officer. Also effective April 30, 2009, Mr. Brandt will continue to serve as Chief Executive Officer of APS and will assume the position of APS’ Chairman of the Board. Mr. Brandt was elected President and Chief Operating Officer of Pinnacle West in March 2008. Prior to that time, he was Executive Vice President of Pinnacle West (September 2003 – March 2008) and Senior Vice President of Pinnacle West (December 2002 – September 2003). He was also elected Chief Financial Officer of Pinnacle West in December 2002. Mr. Brandt was also elected Chief Executive Officer of APS in March 2008. Mr. Brandt was elected President of APS in December 2006, a position he held until January 2009. Prior to that time, he was Executive Vice President of APS (September 2003 – December 2006) and Senior Vice President of APS (January 2003 – September 2003). He was also elected Chief Financial Officer of APS in January of 2003.

     Mr. Hatfield was elected to his present position effective July 2008. Prior to that time, he was Senior Vice President and Chief Financial Officer of OGE Energy Corp. since 1999. His previous experience includes nearly 14 years with OGE Energy Corp. in a variety of financial and management leadership roles, including serving as Vice President and Treasurer, and more than 28 years of electric and gas industry experience.

     Mr. Denman was elected to his present position effective November 2007. Prior to that time, he was Vice President, Fossil Generation of APS (April 1997 – November 2007).

     Mr. Edington was elected to his present position effective November 2007. Prior to that time, he was Senior Vice President and Chief Nuclear Officer of APS (January 2007 – November 2007). He was previously with Entergy Corporation, serving as Site Vice President and Chief Nuclear Officer of Cooper Generating Station (2003 – January 2007).

     Mr. Froggatt was elected to his present position for APS and Pinnacle West in December 2008. Prior to that time, he was Vice President and Controller of APS (October 2002 – December 2008), Vice President and Controller of Pinnacle West (August 1999 – October 2002), Controller of Pinnacle West (July 1999 – August 1999) and Controller of APS (July 1997 – July 1999).

     Ms. Gomez was elected to her present position in December 2008. Prior to that time, she was Vice President and Treasurer of Pinnacle West and APS (February 2004 – December 2008), Treasurer of Pinnacle West (August 1999 – February 2004) and Manager, Treasury Operations of APS (1997 – 1999). She was also elected Treasurer of APS in October 1999 and Vice President of APS in February 2004.

     Ms. Loftin was elected to her present position effective November 2007. Prior to that time, she was Vice President, General Counsel and Secretary of Pinnacle West (October 2002 – November 2007) and Vice President and General Counsel (July 1999 – October 2002). She was also elected Vice President and General Counsel of APS in July 1999 and Secretary of APS in October 2002.

     Mr. Robinson was elected to his present position effective January 2009. Prior to that time, he was Senior Vice President, Planning and Administration of APS (November 2007 – January 2009), Vice President, Planning of APS (September 2003 – November 2007), Vice President, Finance and Planning of APS (October 2002 – September 2003) and Vice President, Regulation and Planning of Pinnacle West (June 2001 – October 2002).

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     Ms. Sundberg was elected Vice President, Human Resources of APS effective November 2007. Prior to that time, she was with American Express Company, serving as Vice President, Employee Relations, Safety, Compliance & Embrace (January 2007 – November 2007) and Vice President, HR Relationship Leader, Global Corporate Travel Division (August 2003 – January 2007).

     Mr. Wheeler was elected to his present position in September 2003. Prior to that time, he was Senior Vice President, Regulation, System Planning and Operations of APS (October 2002 – September 2003) and Senior Vice President, Transmission, Regulation and Planning of Pinnacle West and APS (June 2001 – October 2002).

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PART II

ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     Pinnacle West’s common stock is publicly held and is traded on the New York Stock Exchange. At the close of business on February 16, 2009, Pinnacle West’s common stock was held of record by approximately 29,295 shareholders.

QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE
STOCK SYMBOL: PNW

							Dividends
2008	High		Low		Close		Per Share
1st Quarter	$	42.92	$	34.08	$	35.08	$	0.525
2nd Quarter		37.39		30.26		30.77		0.525
3rd Quarter		37.88		30.34		34.41		0.525
4th Quarter		35.83		26.27		32.13		0.525

							Dividends
2007	High		Low		Close		Per Share
1st Quarter	$	51.67	$	46.43	$	48.25	$	0.525
2nd Quarter		50.68		39.38		39.85		0.525
3rd Quarter		41.76		36.79		39.51		0.525
4th Quarter		44.50		39.04		42.41		0.525

     APS’ common stock is wholly-owned by Pinnacle West and is not listed for trading on any stock exchange. As a result, there is no established public trading market for APS’ common stock.

     The chart below sets forth the dividends paid on APS’ common stock for each of the four quarters for 2008 and 2007.

Common Stock Dividends
(Dollars in Thousands)

Quarter	2008		2007
1st Quarter	$	42,500	$	42,500
2nd Quarter		42,500		42,500
3rd Quarter		42,500		42,500
4th Quarter		42,500		42,500

     The sole holder of APS’ common stock, Pinnacle West, is entitled to dividends when and as declared out of funds legally available therefor. As of December 31, 2008, APS did not have any outstanding preferred stock.

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     Issuer Purchases of Equity Securities

     The following table contains information about our purchases of our common stock during the fourth quarter of 2008.

	Total				Total Number of
	Number of				Shares Purchased		Maximum Number of
	Shares		Average		as Part of Publicly		Shares that May Yet Be
	Purchased		Price Paid		Announced Plans		Purchased Under the
Period	(1)		per Share		or Programs		Plans or Programs
October 1 – October 31, 2008		24	$	29.61		—		—
November 1 – November 30, 2008		—		—		—		—
December 1 – December 31, 2008		—		—		—		—
Total		24	$	29.61		—		—

(1) Represents shares of common stock withheld by Pinnacle West to satisfy tax withholding obligations upon the vesting of restricted stock.

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ITEM 6. SELECTED FINANCIAL DATA
PINNACLE WEST CAPITAL CORPORATION
SELECTED CONSOLIDATED FINANCIAL DATA

	2008		2007		2006		2005			2004
	(dollars in thousands, except per share amounts)
OPERATING RESULTS
Operating revenues:
Regulated electricity segment	$	3,127,383	$	2,918,163	$	2,635,036	$	2,237,145		$	2,035,247
Real estate segment		131,067		212,586		399,798		338,031			350,315
Marketing and trading (a)		66,897		138,247		136,748		179,895			227,040
Other revenues		41,729		48,018		36,172		61,221			42,816
Total operating revenues	$	3,367,076	$	3,317,014	$	3,207,754	$	2,816,292		$	2,655,418
Income from continuing operations (b)	$	213,557	$	298,744	$	316,265	$	227,288		$	242,887
Discontinued operations – net of income taxes (c)		28,568		8,399		10,990		(51,021	)		308
Net income	$	242,125	$	307,143	$	327,255	$	176,267		$	243,195
COMMON STOCK DATA
Book value per share – year-end	$	34.16	$	35.15	$	34.48	$	34.58		$	32.14
Earnings (loss) per weighted-average common share outstanding:
Continuing operations – basic	$	2.12	$	2.98	$	3.18	$	2.36		$	2.66
Net income – basic	$	2.40	$	3.06	$	3.29	$	1.83		$	2.66
Continuing operations – diluted	$	2.12	$	2.96	$	3.16	$	2.35		$	2.65
Net income – diluted	$	2.40	$	3.05	$	3.27	$	1.82		$	2.66
Dividends declared per share	$	2.10	$	2.10	$	2.025	$	1.925		$	1.825
Weighted-average common shares outstanding – basic		100,690,838		100,255,807		99,417,008		96,483,781			91,396,904
Weighted-average common shares outstanding – diluted		100,964,920		100,834,871		100,010,108		96,589,949			91,532,473
BALANCE SHEET DATA
Total assets	$	11,620,093	$	11,162,209	$	10,817,900	$	10,588,485		$	9,875,456
Liabilities and equity:
Current liabilities	$	1,505,928	$	1,344,449	$	923,338	$	1,608,863		$	1,590,460
Long-term debt less current maturities		3,031,603		3,127,125		3,232,633		2,608,455			2,584,985
Deferred credits and other		3,636,583		3,159,024		3,215,813		2,946,203			2,749,815
Total liabilities		8,174,114		7,630,598		7,371,784		7,163,521			6,925,260
Common stock equity		3,445,979		3,531,611		3,446,116		3,424,964			2,950,196
Total liabilities and equity	$	11,620,093	$	11,162,209	$	10,817,900	$	10,588,485		$	9,875,456

(a)	Reflects reclassifications of APSES’ discontinued commodity-related energy services revenue for the years 2004 through 2008. See Note 22.
(b)	Includes a $32 million after tax real estate impairment charge in 2008. (See Note 23.) Also includes regulatory disallowance of $8 million after tax in 2007 and $84 million after tax in 2005. (See Note 3.)
(c)	Amounts primarily related to Silverhawk, SunCor and APSES discontinued operations. See Note 22.

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SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY

	2008		2007		2006		2005			2004
			(dollars in thousands)
OPERATING RESULTS
Electric operating revenues	$	3,133,496	$	2,936,277	$	2,658,513	$	2,270,793		$	2,197,121
Fuel and purchased power costs		1,289,883		1,151,392		969,767		688,982			763,254
Other operating expenses		1,408,213		1,358,890		1,290,804		1,200,198			1,104,886
Operating income		435,400		425,995		397,942		381,613			328,981
Other income (deductions)		836		20,870		27,584		(69,171	)		15,328
Interest deductions – net of AFUDC		173,892		162,925		155,796		141,963			144,682
Net income	$	262,344	$	283,940	$	269,730	$	170,479		$	199,627
BALANCE SHEET DATA
Total assets	$	10,963,577	$	10,321,402	$	9,948,766	$	9,143,643		$	8,069,564
Liabilities and equity:
Common stock equity	$	3,339,150	$	3,351,441	$	3,207,473	$	2,985,225		$	2,232,402
Long-term debt less current maturities		2,850,242		2,876,881		2,877,502		2,479,703			2,267,094
Total capitalization		6,189,392		6,228,322		6,084,975		5,464,928			4,499,496
Current liabilities		1,267,768		1,055,706		806,556		1,021,084			1,154,702
Deferred credits and other		3,506,417		3,037,374		3,057,235		2,657,631			2,415,366
Total liabilities and equity	$	10,963,577	$	10,321,402	$	9,948,766	$	9,143,643		$	8,069,564

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

     The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’ Financial Statements and the related Notes that appear in Item 8 of this report.

OVERVIEW

     Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so.

     While customer growth in APS’ service territory has been an important driver of our revenues and earnings, it has significantly slowed, reflecting recessionary economic conditions both nationally and in Arizona. Customer growth averaged 3% a year for the three years 2006 through 2008. We currently expect customer growth and retail electricity sales growth (excluding the effects of weather variations) to average about 1% per year during 2009 through 2011. We currently project that our customer growth will begin to accelerate as the economy recovers.

     The near-term economic conditions are reflected in the recent volatility and disruption of the credit markets, as discussed in detail under “Liquidity and Capital Resources – Pinnacle West Consolidated” below. Despite these conditions, Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities and have been able to access these facilities, ensuring adequate liquidity for each company.

     Our cash flows and profitability are affected by the electricity rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed below under “Liquidity and Capital Resources – Pinnacle West Consolidated,” are substantial because of increased costs related to environmental compliance and controls and system reliability, as well as continuing, though slowed, customer growth in APS’ service territory.

     APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. See “Factors Affecting Our Financial Outlook” below. On March 24, 2008, APS filed a rate case with the ACC, which it updated on June 2, 2008, requesting, among other things, an increase in retail rates to help defray rising infrastructure costs, approval of an impact fee and approval of new conservation rates. See Note 3 for details regarding this rate case, including the ACC’s approval of an interim base rate surcharge pending the outcome of the case.

     The 2007 and 2008 financial results of SunCor, our real estate subsidiary, reflect the weak real estate market and current economic conditions, which have adversely affected SunCor’s ability to access capital. SunCor’s net loss in 2008 included a $53 million (pre-tax) real estate impairment charge. If conditions in the broader economy or the real estate markets worsen, or as a result of a change in SunCor’s strategy, we may be required to record additional impairments (see Note 23). In addition to SunCor’s Secured Revolver, under which approximately $120 million in borrowings were outstanding at December 31, 2008, SunCor had approximately $68 million of outstanding debt under other credit facilities that mature at various dates and also contain certain loan covenants. The majority of this indebtedness, except for the Secured Revolver, is due in 2009, and SunCor is in the process of renegotiating these facilities. If SunCor is unable to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such a debt acceleration would have a material adverse impact on SunCor’s business and its financial position. The Company has not guaranteed any SunCor indebtedness. As a result, the Company does not believe that SunCor’s inability to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities would have a material adverse impact on Pinnacle West’s cash flows or liquidity, although any resulting SunCor losses would be reflected in Pinnacle West’s consolidated financial statements.

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     Our other principal first tier subsidiaries, El Dorado and APSES, are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.

     We continue to focus on solid operational performance in our electricity generation and delivery activities. In the delivery area, we focus on superior reliability and customer satisfaction. We plan to expand long-term energy resources and our transmission and distribution systems to meet the electricity needs of our growing retail customer base and to sustain reliability.

     See “Factors Affecting Our Financial Outlook” below for a discussion of several factors that could affect our future financial results.

PINNACLE WEST CONSOLIDATED –
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT

     Pinnacle West’s two reportable business segments are:

• our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and

• our real estate segment, which consists of SunCor’s real estate development and investment activities.

     The following table presents income from continuing operations for our regulated electricity and real estate segments and reconciles those amounts to net income in total for the years ended 2008, 2007, and 2006 (dollars in millions):

	2008			2007			2006
Regulated electricity segment	$	256		$	274		$	259
Real estate segment (a)		(49	)		14			50
All other (b)		7			11			7
Income from continuing operations		214			299			316
Income (loss) from discontinued operations – net of tax:
Real estate segment (c)		23			9			10
All other (b)		5			(1	)		1
Net income	$	242		$	307		$	327

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(a)	SunCor’s net loss in 2008 included a $32 million after-tax real estate impairment charge (see Note 23).
(b)	Includes activities related to marketing and trading, APSES, Silverhawk and El Dorado. Income from discontinued operations for 2008 is primarily related to the resolution of certain tax issues associated with the sale of Silverhawk in 2005. The 2007 loss is primarily related to an APSES project. None of these segments is a reportable segment.
(c)	Primarily relates to sales of commercial properties.

PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS

2008 Compared with 2007

     Our consolidated net income decreased approximately $65 million, to $242 million in 2008 from $307 million in 2007. The major factors that increased (decreased) our net income for the year ended December 31, 2008 compared with the prior year are summarized in the following table (dollars in millions):

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	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment:
Impacts of retail rate increase effective July 1, 2007 and transmission rate increases:
Retail revenue increase primarily related to higher Base Fuel Rate	$	156		$	95
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(141	)		(86	)
Transmission rate increases (including related retail rates)		31			19
Lower mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals		(14	)		(9	)
Regulatory disallowance in 2007		14			8
Higher retail sales primarily due to customer growth, excluding weather effects, partially offset by lower average usage		21			13
Effects of weather on retail sales		(43	)		(26	)
Operations and maintenance expense increases primarily due to:
Customer service and other costs, including distribution system reliability		(30	)		(18	)
Generation costs, including more planned maintenance		(18	)		(11	)
Employee severance costs		(9	)		(5	)
Higher depreciation and amortization primarily due to increased utility plant in service		(18	)		(11	)
Income tax benefits related to prior years resolved in 2008		—			30
Income tax benefits related to prior years resolved in 2007		—			(13	)
Higher interest expense, net of capitalized financing costs, primarily due to higher rates on certain APS pollution control bonds and higher short-term debt balances		(15	)		(9	)
Miscellaneous items, net		1			5
Decrease in regulated electricity segment net income		(65	)		(18	)
Lower real estate segment income from continuing operations primarily due to:
Real estate impairment charge (Note 23)		(53	)		(32	)
Lower land parcel sales resulting from the weak real estate market		(40	)		(24	)
Lower sales of residential property resulting from the weak real estate market		(4	)		(2	)
Higher other costs		(7	)		(5	)
Lower marketing and trading contribution primarily due to lower sales volumes		(16	)		(10	)
Other miscellaneous items, net		14			6
Decrease in income from continuing operations	$	(171	)		(85	)
Increase in real estate segment income from discontinued operations primarily related to a 2008 commercial property sale					14
Increase in other income from discontinued operations primarily related to the resolution in 2008 of certain tax issues associated with the sale of Silverhawk in 2005					6
Decrease in net income				$	(65	)

Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $209 million higher for the year ended December 31, 2008 compared with the prior year primarily because of:

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• a $156 million increase in retail revenues due to a rate increase effective July 1, 2007;

• a $38 million increase in revenues from Off-System Sales due to higher prices and volumes;

• a $31 million increase due to transmission rate increases (including related retail rates);

• a $29 million increase in retail revenues primarily related to customer growth, excluding weather effects;

• a $26 million increase in revenues related to long-term traditional wholesale contracts;

• a $14 million increase in renewable energy surcharges which are offset by operations and maintenance expense;

• a $63 million decrease in retail revenue due to the effects of weather;

• a $47 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of lower amortization of the same amount recorded as fuel and purchased power expense; and

• a $25 million net increase due to miscellaneous factors.

Real Estate Segment Revenues

     Real estate segment revenues were $82 million lower for the year ended December 31, 2008 compared with the prior year primarily because of:

• a $62 million decrease primarily due to lower sales of land parcels as a result of the weak real estate market;

• a $14 million decrease primarily due to lower residential property sales as a result of the weak real estate market; and

• a $6 million net decrease due to miscellaneous factors.

All Other Revenues

     All other revenues were $78 million lower for the year ended December 31, 2008 compared with the prior year primarily because of planned reductions of marketing and trading activities.

2007 Compared with 2006

     Our consolidated net income decreased approximately $20 million, from $327 million for 2006 to $307 million for 2007. The major factors that increased (decreased) net income for the year ended December 31, 2007 compared with the prior year are summarized in the following table (dollars in millions):

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	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment:
Higher retail sales primarily due to customer growth, excluding weather effects	$	46		$	28
Effects of weather on retail sales		37			23
Impacts of retail rate increase effective July 1, 2007:
Revenue increase related to higher Base Fuel Rate		185			113
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(171	)		(104	)
Non-fuel rate increase		6			4
Net changes in fuel and purchased power costs related to price:
Higher fuel and purchased power costs related to increased commodity prices		(121	)		(74	)
Increased deferred fuel and purchased power costs related to increased prices		115			70
Mark-to-market fuel and purchased power costs, net of related deferred fuel and purchased power costs		18			11
Regulatory disallowance (see Note 3)		(14	)		(8	)
Operations and maintenance increases primarily due to:
Increased generation costs, including increased maintenance and overhauls and Palo Verde performance improvement plan		(25	)		(15	)
Customer service and other costs		(21	)		(13	)
Higher depreciation and amortization primarily due to increased utility plant in service		(12	)		(7	)
Lower other income, net of expense, primarily due to lower interest income as a result of lower investment balances and miscellaneous asset sales in prior year		(15	)		(9	)
Income tax benefits resolved in 2007 related to prior years		—			13
Income tax credits resolved in 2006 related to prior years		—			(14	)
Miscellaneous items, net		6			(3	)
Increase in regulated electricity segment net income		34			15
Lower real estate segment income from continuing operations primarily due to:
Lower sales of residential property resulting from the continued slowdown in the western United States real estate markets		(47	)		(29	)
Lower sales of land parcels		(12	)		(7	)
Higher other costs		(1	)		—
Higher marketing and trading contribution primarily due to higher mark-to-market gains resulting from changes in forward prices and higher unit margins		6			3
Other miscellaneous items, net		(2	)		1
Decrease in income from continuing operations	$	(22	)		(17	)
Discontinued operations:
Increased commercial property real estate sales					(1	)
Other discontinued operations					(2	)
Decrease in net income				$	(20	)

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Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $283 million higher for the year ended December 31, 2007 compared with the prior year primarily because of:

• a $191 million increase in retail revenues due to a rate increase effective July 1, 2007;

• a $60 million increase in retail revenues primarily related to customer growth, excluding weather effects;

• a $50 million increase in retail revenues due to the effects of weather;

• a $3 million increase in revenues from Off-System Sales due to higher prices and volumes;

• a $35 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 3); and

• a $14 million net increase due to miscellaneous factors.

Real Estate Segment Revenues

     Real estate segment revenues were $187 million lower for the year ended December 31, 2007 compared with the prior year primarily because of:

• a $167 million decrease in residential property sales due to the continued slowdown in western United States real estate markets; and

• a $20 million decrease primarily due to lower sales of land parcels.

All Other Revenues

     Other revenues were $13 million higher for the year ended December 31, 2007 compared with the prior year primarily as a result of increased sales by APSES of energy-related products and services.

LIQUIDITY AND CAPITAL RESOURCES – Pinnacle West Consolidated

Cash Flows

     The following table presents net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2008, 2007 and 2006 (dollars in millions):

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	2008			2007			2006
Net cash flow provided by operating activities	$	814		$	658		$	394
Net cash flow used for investing activities		(815	)		(873	)		(569	)
Net cash flow provided by financing activities		51			185			108
Net Increase (decrease) in cash and cash equivalents	$	50		$	(30	)	$	(67	)

     2008 Compared with 2007

     The increase of approximately $156 million in net cash provided by operating activities is primarily due to lower current income taxes; lower real estate investments resulting from the weak real estate market; and increased retail revenue related to higher Base Fuel Rates, partially offset by increased collateral and margin cash provided as a result of changes in commodity prices.

     The decrease of approximately $58 million in net cash used for investing activities is primarily due to a real estate commercial property sale in 2008; lower levels of capital expenditures (see table and discussion below); and increased contributions in aid of construction related to changes in 2008 in APS’ line extension policy (see Note 3), partially offset by lower cash proceeds from the net sales and purchases of investment securities.

     The decrease of approximately $134 million in net cash provided by financing activities is primarily due to the use of the proceeds from the sale of a real estate commercial property to pay down long-term debt in 2008, partially offset by higher levels of short-term debt borrowings.

     2007 Compared with 2006

     The increase of approximately $264 million in net cash provided by operating activities is primarily due to a decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.

     The increase of approximately $304 million in net cash used for investing activities is primarily due to the proceeds of $208 million received in 2006 from the 2005 sale of Silverhawk and an increase in cash used for capital expenditures and capitalized interest (see table and discussion below), partially offset by higher cash proceeds from the net sales and purchases of investments.

     The increase of approximately $77 million in net cash provided by financing activities is primarily due to higher levels of short-term borrowings, partially offset by a decrease in net new long-term debt (issuances net of redemptions and refinancing).

     Liquidity

     Capital Expenditure Requirements

     The following table summarizes the actual capital expenditures for 2006, 2007 and 2008 and estimated capital expenditures, net of contributions in aid of construction, for the next three years:

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CAPITAL EXPENDITURES
(dollars in millions)

	Actual						Estimated
	2006		2007		2008		2009		2010		2011
APS
Distribution	$	357	$	372	$	340	$	276	$	266	$	356
Generation (a)		176		353		310		288		274		319
Transmission		113		138		163		275		99		185
Other (b)		16		37		43		44		37		50
Subtotal		662		900		856		883		676		910
SunCor (c)		201		161		41		14		70		175
Other		7		3		7		7		3		3
Total	$	870	$	1,064	$	904	$	904	$	749	$	1,088

(a)	Generation includes nuclear fuel expenditures of approximately $60 million to $80 million per year for 2009, 2010 and 2011.
(b)	Primarily information systems and facilities projects.
(c)	Consists primarily of capital expenditures for residential, land development and retail and office building construction reflected in “Real estate investments” and “Capital expenditures” on the Consolidated Statements of Cash Flows.

     Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems, partially offset by contributions in aid of construction in accordance with APS’ line extension policy.

     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Environmental expenditures differ for each of the years 2009, 2010 and 2011, with the lowest year estimated at approximately $25 million, and the highest year estimated at approximately $80 million. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures. (See “Business of Arizona Public Service Company – Environmental Matters – EPA Environmental Regulation – Regional Haze Rules” and “Environmental Matters – EPA Environmental Regulation – Mercury” in Item 1.)

     In early 2008, we announced and began implementing a cost reduction effort that included the elimination of approximately $200 million of capital expenditures for the years 2008 – 2012. These capital expenditure reductions are reflected in the estimates provided above. Due primarily to our reduced customer growth outlook as well as the deferral of upgrades and other capital projects, we have identified additional capital expenditure reductions of over $500 million at APS (net of the

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change in amounts collected for projected line extensions) over the years 2009 – 2011. These reductions are across all areas – distribution, generation, transmission and general plant, and are reflected in the estimates provided above. (See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook – Customer and Sales Growth” below for additional information on our growth outlook.)

     Capital expenditures will be funded with internally generated cash and/or external financings, which may include issuances of long-term debt and Pinnacle West common stock.

     Pinnacle West (Parent Company)

     Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

     On January 21, 2009, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on March 2, 2009, to shareholders of record on February 2, 2009.

     Our primary sources of cash are dividends from APS, external debt and equity financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2006 through 2008, total distributions from APS were $510 million and total distributions received from SunCor were $15 million. For 2008, cash distributions from APS were $170 million and there were no distributions from SunCor. An existing ACC order requires APS to maintain a common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the payment would reduce its common equity below that threshold. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At December 31, 2008, APS’ common equity ratio, as defined, was approximately 54%.

     The credit and liquidity markets experienced significant stress beginning the week of September 15, 2008. While Pinnacle West’s and APS’ ability to issue commercial paper has been negatively impacted by the market stress, they have both been able to access existing credit facilities, ensuring adequate liquidity. Cash on hand is being invested in money market funds consisting of U.S. Treasury and government agency securities and repurchase agreements collateralized fully by U.S. Treasury and government agency securities.

     At December 31, 2008, Pinnacle West’s outstanding long-term debt, including current maturities, was $175 million. Pinnacle West has a $300 million revolving credit facility that terminates in December 2010. Credit commitments totaling approximately $17 million from Lehman Brothers are no longer available due to its September 2008 bankruptcy filing. The remaining $283 million revolver is available to support the issuance of up to $250 million in commercial paper (see discussion above) or to be used as bank borrowings, including issuances of letters of credit of up to $94 million. At December 31, 2008, Pinnacle West had outstanding $144 million of borrowings under its revolving credit facility and approximately $7 million of letters of credit. Pinnacle West had no commercial paper outstanding at December 31, 2008. In general, the Company and APS have been unable to access the commercial paper markets since September 2008. At December 31, 2008, Pinnacle West had remaining capacity available

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under its revolver of approximately $132 million and had cash and investments of approximately $6 million.

     Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We contributed $35 million to our pension plan in 2008. On a cash funded basis, which is based on Internal Revenue Code regulations, our preliminary estimate of the qualified plan’s funded status (market value of assets to liabilities) as of January 1, 2009 is 98.6%. The plan’s IRS cash funded status was 94.3% as of January 1, 2008. Most of the increase from the prior year was due to gains in the long-duration bonds and interest rate swaps that we utilized in 2008 to better match the interest rate sensitivity of the plan’s assets to that of the plan’s liabilities. The required minimum contribution to our pension plan is estimated to be approximately $36 million in 2009 and approximately $25 million in 2010. The expected contribution to our other postretirement benefit plans in 2009 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

     See Note 3 for information regarding Pinnacle West’s approval from the ACC regarding a potential equity infusion into APS of up to $400 million.

     In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.

     APS

     APS’ capital requirements consist primarily of capital expenditures and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, equity infusions from Pinnacle West and external financings. APS has historically paid its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.

     APS’ outstanding long-term debt, including current maturities, was approximately $2.9 billion at December 31, 2008. APS has two committed revolving credit facilities totaling $900 million, of which $400 million terminates in December 2010 and $500 million terminates in September 2011. Credit commitments totaling about $34 million from Lehman Brothers are no longer available due to its September 2008 bankruptcy filing. The remaining $866 million is available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit up to $583 million. At December 31, 2008, APS had borrowings of approximately $522 million and no letters of credit under its revolving lines of credit. APS had no commercial paper outstanding at December 31, 2008. In general, the Company and APS have been unable to access the commercial paper markets since September 2008. At December 31, 2008, APS had remaining capacity available under its revolvers of $344 million and had cash and investments of approximately $72 million.

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     The interest rates on eleven issues of APS’ pollution control bonds, in the aggregate amount of approximately $343 million, are reset every seven days through auction processes. These bonds are supported by bond insurance policies provided by Ambac, and the interest rates on the bonds can be directly affected by the rating of the bond insurer. Certain bond insurers, including Ambac, have had downgrades of their credit ratings. Downgrades of bond insurers result in downgrades of the insured bonds, which increases the possibility of a “failed auction” and results in higher interest rates during the failed auction periods. When auctions of APS bonds fail, the APS bondholders receive the maximum 14% annual interest rate for the week of the failed auction. For the twelve months ended December 31, 2008, we had ninety-nine failed auctions, which represented about 17% of all of our auctions. The average interest rate at December 31, 2008 on the auction rate securities was 12.4%. Bond auctions continued to fail through mid-January; however, since that time, we have had only one failure. The average interest rate at February 18, 2009 on the auction rate securities was 5.7%. We continue to closely monitor this market and, if market and business conditions allow, we are planning on refunding and reissuing these bonds during 2009. We do not expect, however, that our auction rate interest exposure will have a material adverse impact on our financial position, results of operations, cash flows or liquidity.

     On September 11, 2008, APS repurchased at par two series of pollution control bonds that had no credit enhancements. The repurchase included $7 million of its 1996 Series A Coconino County Pollution Control Bonds and $20 million of its 1999 Series A Coconino County Pollution Control Bonds. APS borrowed funds under its revolving lines of credit to re-purchase the bonds as permitted under the bond indenture. APS intends to keep the $27 million outstanding until we complete our planned refunding and reissuance of these bonds, if market and business conditions allow, in 2009.

     Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million (which is required to be used for purchases of natural gas and power) and (b) APS’ long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. This financing order expires December 31, 2012; however, all debt previously authorized and outstanding on December 31, 2012 will remain authorized and valid obligations of APS.

     Other Financing Matters –See Note 3 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.

     See Note S-5 for information regarding an ACC order permitting Pinnacle West to infuse up to $400 million of equity into APS, on or before December 31, 2009, if Pinnacle West deems it appropriate to do so to strengthen or maintain APS’ financial integrity.

     See “Cash Flow Hedges” in Note 18 for information related to the change in our margin account.

     Other Subsidiaries

     SunCor– The weak real estate market and current economic conditions have adversely affected SunCor’s financial results and its ability to access capital. During the past three years,

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SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures during 2008 and projected capital expenditures for the next three years.

     SunCor’s principal loan facility, the Secured Revolver, is secured primarily by an interest in land, commercial properties, land contracts and homes under construction. On February 19, 2009, SunCor and the Secured Revolver lenders extended the maturity date of the Secured Revolver to January 30, 2010 (classified as current maturities of long-term debt at December 31, 2008). SunCor is required to repay amounts under the Secured Facility in order to reduce the lenders’ commitments to a balance of $100 million by December 31, 2009. The Secured Revolver requires compliance with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow coverage and restrictions on debt. In addition to the Secured Revolver, at December 31, 2008, SunCor had approximately $68 million of outstanding debt under other credit facilities that mature at various dates and also contain certain loan covenants. The majority of this indebtedness is due in 2009, and SunCor is in the process of renegotiating these facilities.

     If SunCor is unable to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such a debt acceleration would have a material adverse impact on SunCor’s business and its financial position. The Company has not guaranteed any SunCor indebtedness. As a result, the Company does not believe that SunCor’s inability to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities would have a material adverse impact on Pinnacle West’s cash flows or liquidity, although any resulting SunCor losses would be reflected in Pinnacle West’s consolidated financial statements.

     SunCor entered into a secured construction loan on April 13, 2007, in the amount of $60 million which was subsequently repaid in June 2008.

     On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan matures on July 31, 2009, and may be extended annually up to two years.

     SunCor’s total outstanding debt was approximately $188 million as of December 31, 2008, including $120 million of debt classified as current maturities of long-term debt under revolving lines of credit totaling $150 million. SunCor’s long-term debt, including current maturities, was $183 million and total short-term debt was $5 million at December 31, 2008. See Notes 5 and 6. SunCor had cash and investments of approximately $27 million at December 31, 2008.

     El Dorado– El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.

     APSES– APSES expects minimal capital expenditures over the next three years.

     Debt Provisions

     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total

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consolidated capitalization not exceed 65%. At December 31, 2008, the ratio was approximately 51% for Pinnacle West and 49% for APS. The provisions regarding interest coverage require minimum cash coverage of two times. The interest coverage was approximately 4.5 times under APS’ bank financing agreements as of December 31, 2008. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

     Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank financial agreements contain a pricing grid in which the interest costs we pay are determined by our current credit ratings.

     All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.

     See Note 6 for further discussions.

     Credit Ratings

     The ratings of securities of Pinnacle West and APS as of February 18, 2009 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase the cost of and limit access to capital. It may also require substantial additional collateral related to certain derivative instruments, natural gas transportation, fuel supply, and other energy-related contracts.

	Moody’s		Standard & Poor’s		Fitch
Pinnacle West
Senior unsecured (a)	Baa3 (P)		BB+ (prelim)			N/A
Commercial paper	P	-3		A-3		F3
Outlook	Stable		Stable		Negative
APS
Senior unsecured	Baa2		BBB-		BBB
Secured lease obligation bonds	Baa2		BBB-		BBB
Commercial paper	P	-2		A-3		F3
Outlook	Stable		Stable		Stable

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(a) Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim) rating to the senior unsecured securities that can be issued under such shelf registration.

     Off-Balance Sheet Arrangements

     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them (see Note 9).

     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2008, APS would have been required to assume approximately $174 million of debt and pay the equity participants approximately $162 million.

     Guarantees and Letters of Credit

     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading relate to commodity energy products. As required by Arizona law, Pinnacle West has also obtained a $10 million bond on behalf of APS in connection with the interim base rate surcharge approved by the ACC in December 2008. See “2008 General Rate Case — Interim Rate Surcharge” in Note 3. Our credit support instruments enabled APSES to offer energy-related products and commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. At December 31, 2008, we had no guarantees that were in default. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 21 for additional information regarding guarantees and letters of credit.

Contractual Obligations

     The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2008 (dollars in millions):

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			2010-		2012-
	2009		2011		2013		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	182	$	957	$	646	$	3,549	$	5,334
SunCor		178		4		2		—		184
Pinnacle West		10		187		—		—		197
Total long-term debt payments, including interest		370		1,148		648		3,549		5,715
Short-term debt payments, including interest (b)		672		—		—		—		672
Purchased power and fuel commitments (c)		449		651		777		6,053		7,930
Operating lease payments		82		147		132		135		496
Nuclear decommissioning funding requirements		22		49		49		185		305
Purchase obligations (d)		69		76		33		172		350
Minimum pension funding requirement (e)		36		25		—		—		61
Total contractual commitments	$	1,700	$	2,096	$	1,639	$	10,094	$	15,529

(a)	The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2008 (see Note 6).
(b)	The short-term debt is primarily related to bank borrowings at Pinnacle West, APS and SunCor under their respective revolving lines of credit (see Note 5).
(c)	Our purchased power and fuel commitments include purchases of coal, electricity, natural gas, renewable energy and nuclear fuel (see Note 11).
(d)	These contractual obligations include commitments for capital expenditures and other obligations.
(e)	Future pension contributions are not determinable for plan years 2010 and beyond.

     This table excludes $69 million in unrecognized tax benefits because the timing of the future cash outflows in uncertain.

CRITICAL ACCOUNTING POLICIES

     In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

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Regulatory Accounting

     Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. A major component of our regulatory assets is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery 90% of the difference between actual retail fuel and power costs and the amount of such costs currently included in base rates. We had $795 million, including $8 million related to the PSA, of regulatory assets on the Consolidated Balance Sheets at December 31, 2008.

     Also included in the balance of regulatory assets at December 31, 2008 is a regulatory asset of $473 million in accordance with SFAS No. 158 for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.

     In addition, we had $588 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2008, which primarily are related to removal costs. See Notes 1 and 3 for more information.

Pensions and Other Postretirement Benefit Accounting

     Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

     The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2008 reported pension liability on the Consolidated Balance Sheets and our 2008 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

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	Increase (Decrease)
	Impact on			Impact on
	Pension			Pension
Actuarial Assumption (a)	Liability			Expense
Discount rate:
Increase 1%	$	(241	)	$	(8	)
Decrease 1%		277			14
Expected long-term rate of return on plan assets:
Increase 1%		—			(7	)
Decrease 1%		—			7

(a) Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

     The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2008 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2008 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

	Increase (Decrease)
	Impact on Other			Impact on Other
	Postretirement Benefit			Postretirement
Actuarial Assumption (a)	Obligation			Benefit Expense
Discount rate:
Increase 1%	$	(90	)	$	(5	)
Decrease 1%		104			5
Health care cost trend rate (b):
Increase 1%		103			9
Decrease 1%		(83	)		(7	)
Expected long-term rate of return on plan assets – pretax:
Increase 1%		—			(2	)
Decrease 1%		—			2

(a)	Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
(b)	This assumes a 1% change in the initial and ultimate health care cost trend rate.

     See Note 8 for further details about our pension and other postretirement benefit plans.

Derivative Accounting

     Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we

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use accrual accounting (for contracts designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)).

     See “Market Risks – Commodity Price Risk” below for quantitative analysis. See “Fair Value Measurements” below for additional information on valuation. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative and energy trading accounting.

Fair Value Measurements

     We apply fair value measurements to derivative instruments, nuclear decommissioning trusts and cash equivalents. We adopted SFAS No. 157, “Fair Value Measurements,” for our financial assets and liabilities on January 1, 2008. SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. In accordance with SFAS No. 157 we use inputs, or assumptions that market participants would use, to determine fair market value, and the significance of a particular input determines how the instrument is classified in the fair value hierarchy. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within the fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 14 for further fair value measurement discussion, Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative and energy trading accounting.

     Our nuclear decommissioning trusts invest in fixed income securities and equity securities. The fair values of these securities are based on observable inputs for identical or similar assets. See Note 12 for further discussion of our nuclear decommissioning trusts.

Real Estate Investment Impairments

     We had real estate investments of $415 million and home inventory of $51 million on our consolidated balance sheets at December 31, 2008. We assess impairment of these assets in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” For purposes of evaluating impairment, we classify our real estate assets, such as land under development, land held for future development, and commercial property, as “held and used.” When events or changes in circumstances indicate that the carrying value of real estate assets considered held and used may not be recoverable, we compare the undiscounted cash flows that we estimate will be generated by each asset to its carrying amount. If the carrying amount exceeds the undiscounted cash flows, we adjust the asset to fair value and recognize an impairment charge. The adjusted value becomes the new book value (carrying amount) for held and used assets. We may have real estate assets classified as held and used with fair values that are lower than their carrying amounts, but are not deemed to be impaired because the undiscounted cash flows exceed the carrying amounts.

     Real estate home inventory is considered to be held for sale for the purposes of evaluating impairment in accordance with the provisions of SFAS No. 144. Home inventories are reported at

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the lower of carrying amount or fair value less cost to sell. Fair value less cost to sell is evaluated each period to determine if it has changed. Losses (and gains not to exceed any cumulative loss previously recognized) are reported as adjustments to the carrying amount.

     We determine fair value for our real estate assets primarily based on the future cash flows that we estimate will be generated by each asset discounted for market risk. Our impairment assessments and fair value determinations require significant judgment regarding key assumptions such as future sales prices, future construction and land development costs, future sales timing, and discount rates. The assumptions are specific to each project and may vary among projects. The discount rates we used to determine fair values at December 31, 2008 ranged from 17% to 27%. Due to the judgment and assumptions applied in the estimation process, with regard to impairments, it is possible that actual results could differ from those estimates. If conditions in the broader economy or the real estate markets worsen, or as a result of a change in SunCor’s strategy, we may be required to record additional impairments.

OTHER ACCOUNTING MATTERS

     See Note 14 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted effective January 1, 2008, and the following related accounting guidance:

• FASB Staff Position, No. 157-2, “Effective Date of FASB Statement No. 157”

• FASB Staff Position, No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”

     See Notes 18 and S-3 for discussions of FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), which we adopted January 1, 2008.

     SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was effective for us on January 1, 2008. This guidance provides companies with an option to report selected financial assets and liabilities at fair value. We did not elect the fair value option for any of our financial assets or liabilities. Therefore, SFAS No. 159 did not have an impact on our financial statements.

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This guidance requires enhanced disclosures about derivative instruments and hedging activities. The Statement is effective for us on January 1, 2009. It did not have a material impact on our financial statements.

     In December 2008, the FASB issued FASB Staff Position No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This guidance requires enhanced employer disclosures about plan assets of a defined benefit pension or other postretirement plan. The guidance is effective for us on December 31, 2009. We do not expect it to have a material impact on our financial statements.

     See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which was adopted January 1, 2007.

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FACTORS AFFECTING OUR FINANCIAL OUTLOOK

Factors Affecting Operating Revenues, Fuel and Purchased Power Costs

     GeneralElectric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. For the years 2006 through 2008, retail electric revenues comprised approximately 91% of our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer growth, variations in weather from period to period, customer mix, average usage per customer, electricity rates and tariffs and the recovery of PSA deferrals. Off-System Sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess economic generation or other energy resources and wholesale market conditions, including demand and prices. Competitive retail sales of energy and energy-related products and services are made by APSES in certain western states that have opened to competition.

     Rate ProceedingsOur cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed below under “Liquidity and Capital Resources – Pinnacle West Consolidated,” are substantial because of environmental compliance and controls, system reliability, and continuing, though slowed, customer growth in APS’ service territory. APS needs timely recovery through rates of its capital and operating expenditures to maintain adequate financial health. On March 24, 2008, APS filed a rate case with the ACC, which it updated on June 2, 2008, requesting, among other things, an increase in retail rates to help defray rising infrastructure costs, approval of an impact fee and approval of new conservation rates. See Note 3 for details regarding this rate case, including the ACC’s approval of an interim base rate surcharge pending the outcome of the case.

     Fuel and Purchased Power CostsFuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and, since April 1, 2005, PSA deferrals and the amortization thereof. See Note 3 for information regarding the PSA. APS’ recovery of PSA deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.

     Customer and Sales GrowthThe customer and sales growth referred to in this paragraph apply to Native Load customers and sales to them. Customer growth in APS’ service territory was 1.4% during 2008. Customer growth averaged 3% a year for the three years 2006 through 2008. We currently expect customer growth to decline, averaging about 1% per year for 2009 through 2011 due to factors reflecting the economic conditions both nationally and in Arizona. For the three years 2006 through 2008, APS’ actual retail electricity sales in kilowatt-hours grew at an average annual rate of 2.9%; adjusted to exclude the effects of weather variations, such retail sales growth averaged 2.9% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 1% on average per year during 2009 through 2011, excluding the effects of weather variations. We currently expect our retail sales growth in 2009 to be below average because of potential effects on customer usage from the economic conditions mentioned above and retail rate increases (see Note 3).

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     Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.

     WeatherIn forecasting retail sales growth, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

     Wholesale MarketOur marketing and trading activities focus primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. Our marketing and trading activities include, subject to specified parameters, marketing, hedging and trading in electricity and fuels. See “Formula Transmission Tariff” in Note 3 for information regarding APS’ recent filing with the FERC requesting a change to the formula rate.

Other Factors Affecting Financial Results

     Operations and Maintenance ExpensesOperations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs and other factors.

     Depreciation and Amortization ExpensesDepreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Capital Expenditures” above for information regarding planned additions to our facilities.

     Property TaxesTaxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 7.8% of the assessed value for 2008, 8.3% of the assessed value for 2007 and 8.9% of assessed value for 2006. We expect property taxes to increase as we add new utility plant (including new generation, transmission and distribution facilities) and as we improve our existing facilities. See “Capital Expenditures” above for information regarding planned additions to our facilities.

     Interest ExpenseInterest expense is affected by the amount of debt outstanding and the interest rates on that debt. (See Note 6.) The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.

     Climate ChangeRecent concern over climate change could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades. The timing and type of compliance measures and related costs are impacted by current and future regulatory and legislative actions, which we are closely monitoring. See “Business of Arizona Public Service Company – Climate Change” in Item 1 for more information regarding climate change initiatives.

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     Retail CompetitionAlthough some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail electric service providers providing unbundled energy or other utility services to APS’ customers. We cannot predict when, and the extent to which, additional electric service providers will re-enter APS’ service territory.

     SubsidiariesSunCor’s net loss was approximately $26 million in 2008. SunCor’s net loss in 2008 included a $53 million (pre-tax) real estate impairment charge. SunCor’s net income was approximately $24 million in 2007 and $61 million in 2006. See Note 23 for further discussion. This estimate reflects continuation of the slowdown in the western United States real estate markets. See “Liquidity and Capital Resources – Other Subsidiaries – SunCor” and Note 6 for a discussion of SunCor’s long-term debt, liquidity, and capital requirements.

     The historical results of APSES and El Dorado are not indicative of future performance.

     GeneralOur financial results may be affected by a number of broad factors. See “Forward-Looking Statements” and “Risk Factors” above for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.

Market Risks

     Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.

     Interest Rate and Equity Risk

     We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund (see Note 12). The nuclear decommissioning trust fund also has risks associated with the changing market value of its investments. Nuclear decommissioning costs are recovered in regulated electricity prices.

     The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2008 and 2007. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2008 and 2007 (dollars in thousands):

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Pinnacle West – Consolidated

						Variable-Rate					Fixed-Rate
	Short-Term Debt					Long-Term Debt					Long-Term Debt
	Interest					Interest					Interest
2008	Rates			Amount		Rates			Amount		Rates			Amount
2009		2.24	%	$	670,469		3.88	%	$	173,619		4.62	%	$	4,027
2010		—			—		3.99	%		2,042		5.66	%		1,137
2011		—			—		6.22	%		2,259		6.23	%		576,250
2012		—			—		6.00	%		16		6.50	%		376,338
2013		—			—		6.00	%		1,864		6.00	%		231
Years thereafter		—			—		8.30	%		539,145		5.64	%		1,540,229
Total				$	670,469				$	718,945				$	2,498,212
Fair value				$	670,469				$	718,945				$	2,107,635

						Variable-Rate					Fixed-Rate
	Short-Term Debt					Long-Term Debt					Long-Term Debt
	Interest					Interest					Interest
2007	Rates			Amount		Rates			Amount		Rates			Amount
2008		5.54	%	$	340,661		7.33	%	$	159,337		4.65	%	$	4,436
2009		—			—		7.20	%		71,054		5.76	%		1,050
2010		—			—		9.20	%		201		5.71	%		1,104
2011		—			—		8.91	%		2,284		6.23	%		576,218
2012		—			—		9.50	%		103		6.50	%		376,293
Years thereafter		—			—		3.77	%		567,239		5.64	%		1,540,462
Total				$	340,661				$	800,218				$	2,499,563
Fair value				$	340,661				$	800,218				$	2,414,301

     The tables below present contractual balances of APS’ long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2008 and 2007. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2008 and 2007 (dollars in thousands):

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APS

						Variable-Rate					Fixed-Rate
	Short-Term Debt					Long-Term Debt					Long-Term Debt
	Interest					Interest					Interest
2008	Rates			Amount		Rates			Amount		Rates			Amount
2009		2.09	%	$	521,684		—		$	—		5.62	%	$	874
2010		—			—		—			—		5.60	%		1,012
2011		—			—		—			—		6.37	%		401,208
2012		—			—		—			—		6.50	%		376,325
2013		—			—		—			—		6.00	%		231
Years thereafter		—			—		8.30	%		539,145		5.64	%		1,540,229
Total				$	521,684				$	539,145				$	2,319,879
Fair value				$	521,684				$	539,145				$	1,935,160

						Variable-Rate					Fixed-Rate
	Short-Term Debt					Long-Term Debt					Long-Term Debt
	Interest					Interest					Interest
2007	Rates			Amount		Rates			Amount		Rates			Amount
2008		5.36	%	$	218,000		—		$	—		5.66	%	$	978
2009		—			—		—			—		5.60	%		934
2010		—			—		—			—		5.59	%		1,012
2011		—			—		—			—		6.37	%		401,208
2012		—			—		—			—		6.50	%		376,293
Years thereafter		—			—		3.76	%		565,855		5.64	%		1,540,462
Total				$	218,000				$	565,855				$	2,320,887
Fair value				$	218,000				$	565,855				$	2,235,624

Commodity Price Risk

     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our energy risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.

     The following tables show the net pretax changes in mark-to-market of our derivative positions in 2008 and 2007 (dollars in millions):

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	2008			2007
Mark-to-market of net positions at beginning of year	$	40		$	15
Recognized in earnings:
Change in mark-to-market losses for future period deliveries		(4	)		(2	)
Mark-to-market gains realized including ineffectiveness during the period		(5	)		(15	)
Decrease (increase) in regulatory asset		(111	)		55
Recognized in OCI:
Change in mark-to-market losses for future period deliveries (a)		(138	)		(1	)
Mark-to-market gains realized during the period		(64	)		(12	)
Change in valuation techniques		—			—
Mark-to-market of net positions at end of year	$	(282	)	$	40

(a) The changes in mark-to-market recorded in OCI are due primarily to changes in forward natural gas prices.

     The tables below show the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2008 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for more discussion of our valuation methods.

																			Total
																			fair
Source of Fair Value	2009			2010			2011			2012			2013			Years thereafter			value
Prices actively quoted	$	(50	)	$	(4	)	$	—		$	—		$	—		$	—		$	(54	)
Prices provided by other external sources		(122	)		(53	)		(43	)		(3	)		—			—			(221	)
Prices based on models and other valuation methods		—			(1	)		5			4			(3	)		(12	)		(7	)
Total by maturity	$	(172	)	$	(58	)	$	(38	)	$	1		$	(3	)	$	(12	)	$	(282	)

     The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets at December 31, 2008 and 2007 (dollars in millions):

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	December 31, 2008					December 31, 2007
	Gain (Loss)					Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%		Price Down 10%
Mark-to-market changes reported in:
Earnings
Electricity	$	2	$	(2	)	$	3	$	(3	)
Natural gas		3		(3	)		4		(4	)
Regulatory asset (liability) or OCI (a)
Electricity		20		(20	)		45		(45	)
Natural gas		64		(64	)		85		(85	)
Total	$	89	$	(89	)	$	137	$	(137	)

(a) These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

     We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 1, “Derivative Accounting” for a discussion of our credit valuation adjustment policy. See Note 18 for further discussion of credit risk.

ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS

Regulatory Matters

     See Note 3 for information about rate matters affecting APS.

2008 Compared with 2007

     APS’ net income decreased approximately $22 million, to $262 million in 2008 from $284 million in 2007. The major factors that increased (decreased) net income for the year ended December 31, 2008 compared with the prior year are summarized in the following table (dollars in millions):

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	Increase (Decrease)
	Pretax			After Tax
Impacts of retail rate increase effective July 1, 2007 and transmission rate increases:
Retail revenue increase primarily related to higher Base Fuel Rate	$	156		$	95
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(141	)		(86	)
Transmission rate increases (including related retail rates)		31			19
Lower mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals		(14	)		(9	)
Regulatory disallowance in 2007		14			8
Higher retail sales primarily due to customer growth, excluding weather effects, partially offset by lower average usage		21			13
Effects of weather on retail sales		(43	)		(26	)
Operations and maintenance expense increases primarily due to:
Customer service and other costs, including distribution system reliability		(31	)		(19	)
Generation costs, including more planned maintenance		(18	)		(11	)
Employee severance costs		(9	)		(5	)
Higher depreciation and amortization primarily due to increased utility plant in service		(18	)		(11	)
Income tax benefits related to prior years resolved in 2008		—			29
Income tax benefits related to prior years resolved in 2007		—			(11	)
Higher interest expense, net of capitalized financing costs, primarily due to higher rates on certain APS pollution control bonds and higher short-term debt balances		(11	)		(6	)
Other miscellaneous items, net		(2	)		(2	)
Decrease in net income	$	(65	)	$	(22	)

     Electric operating revenues were $197 million higher for the year ended December 31, 2008 compared with the prior year primarily because of:

• a $156 million increase in retail revenues due to a rate increase effective July 1, 2007;

• a $38 million increase in revenues from Off-System Sales due to higher prices and volumes;

• a $31 million increase due to transmission rate increases (including related retail rates);

• a $29 million increase in retail revenues primarily related to customer growth, excluding weather effects;

• a $26 million increase in revenues related to long-term traditional wholesale contracts;

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• a $14 million increase in renewable energy surcharges which are offset by operations and maintenance expense;

• a $63 million decrease in retail revenue due to the effects of weather;

• a $47 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of lower amortization of the same amount recorded as fuel and purchased power expense; and

• a $13 million net increase due to miscellaneous factors.

2007 Compared with 2006

     Our net income increased approximately $14 million, to $284 million for 2007 from $270 million for 2006. The major factors that increased (decreased) net income for the year ended December 31, 2007 compared with the prior year are contained in the following table (dollars in millions):

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	Increase (Decrease)
	Pretax			After Tax
Higher retail sales primarily due to customer growth, excluding weather effects	$	46		$	28
Effects of weather on retail sales		37			23
Impacts of retail rate increase effective July 1, 2007:
Revenue increase related to higher Base Fuel Rate		185			113
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(171	)		(104	)
Non-fuel rate increase		6			4
Net changes in fuel and purchased power costs related to price:
Higher fuel and purchased power costs related to increased commodity prices		(121	)		(74	)
Increased deferred fuel and purchased power costs related to increased prices		115			70
Mark-to-market fuel and purchased power costs, net of related deferred fuel and purchased power costs		18			11
Regulatory disallowance		(14	)		(8	)
Operations and maintenance increases primarily due to:
Increased generation costs, including increased maintenance and overhauls and Palo Verde performance improvement plan		(25	)		(15	)
Customer service and other costs		(19	)		(11	)
Higher depreciation and amortization primarily due to increased utility plant in service		(12	)		(7	)
Lower other income, net of expense, primarily due to lower interest income as a result of lower investment balances and miscellaneous asset sales in prior year		(7	)		(4	)
Income tax benefits resolved in 2007 related to prior years		—			11
Income tax credits resolved in 2006 related to prior years		—			(11	)
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates		(7	)		(4	)
Lower marketing and trading contribution primarily due to lower mark-to-market gains because of changes in forward prices		(7	)		(4	)
Other miscellaneous items, net		2			(4	)
Increase in net income	$	26		$	14

     Electric operating revenues were $278 million higher for the year ended December 31, 2007 compared with the prior year primarily because of:

• a $191 million increase in retail revenues due to a rate increase effective July 1, 2007;

• a $60 million increase in retail revenues primarily related to customer growth, excluding weather effects;

• a $50 million increase in retail revenues due to the effects of weather;

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• a $3 million increase in revenues from Off-System Sales due to higher prices and volumes;

• a $35 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 3); and

• a $9 million net increase due to miscellaneous factors.

LIQUIDITY AND CAPITAL RESOURCES – ARIZONA PUBLIC SERVICE COMPANY

Cash Flows

     The following table presents APS’ net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2008, 2007 and 2006 (dollars in millions):

	2008			2007			2006
Net cash flow provided by operating activities	$	785		$	766		$	394
Net cash flow used for investing activities		(879	)		(881	)		(714	)
Net cash flow provided by financing activities		114			86			352
Net increase (decrease) in cash and cash equivalents	$	20		$	(29	)	$	32

     2008 Compared with 2007

     The increase of approximately $19 million in net cash provided by operating activities is primarily due to lower current income taxes and increased retail revenue related to higher Base Fuel Rates, partially offset by increased collateral and margin cash provided as a result of changes in commodity prices.

     The decrease of approximately $2 million in net cash used for investing activities is primarily due to lower levels of capital expenditures (see table and discussion above) and increased contributions in aid of construction related to changes in 2008 in our line extension policy (see Note 3), substantially offset by lower cash proceeds from the net sales and purchases of investment securities.

     The increase of approximately $28 million in net cash provided by financing activities is primarily due to higher levels of short-term borrowings, partially offset by decreased equity infusions from Pinnacle West and the repurchase of pollution control bonds (see Note 6).

     2007 Compared with 2006

     The increase of approximately $372 million in net cash provided by operating activities is primarily due to a decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.

     The increase of approximately $167 million in net cash used for investing activities is primarily due to an increase in cash used for capital expenditures (see table and discussion above) and

76

increased allowance for borrowed funds used during construction, partially offset by higher cash proceeds from the net sales and purchases of investment securities.

     The decrease of approximately $266 million in net cash provided by financing activities is primarily due to a decrease in net new long-term debt (issuances net of redemptions and refinancing) and a decrease in equity infusions from Pinnacle West, partially offset by higher levels of short-term borrowings to fund day-to-day operations and liquidity needs.

     Liquidity

     For additional discussion see “Liquidity and Capital Resources – Pinnacle West Consolidated.”

     Contractual Obligations

     The following table summarizes contractual requirements for APS as of December 31, 2008 (dollars in millions):

			2010-		2012-
	2009		2011		2013		Thereafter		Total
Long-term debt payments, including interest (a)	$	182	$	956	$	646	$	3,549	$	5,333
Short-term debt payments, including interest		523		—		—		—		523
Purchased power and fuel commitments (b)		449		651		777		6,053		7,930
Operating lease payments		76		135		122		121		454
Nuclear decommissioning funding requirements		22		49		49		185		305
Purchase obligations (c)		69		76		33		172		350
Minimum pension funding requirement (d)		35		24		—		—		59
Total contractual commitments	$	1,356	$	1,891	$	1,627	$	10,080	$	14,954

(a)	The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2008 (see Note 6).
(b)	APS’ purchased power and fuel commitments include purchases of coal, electricity, natural gas, renewable energy and nuclear fuel (see Note 11).
(c)	These contractual obligations include commitments for capital expenditures and other obligations.
(d)	Future pension contributions are not determinable for plan years 2010 and beyond.

     This table excludes $68 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain.

77

ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK

     See “Factors Affecting Our Financial Outlook” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risk.

78

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULES

	Page
Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)		79
Report of Independent Registered Public Accounting Firm		80
Pinnacle West Consolidated Statements of Income for 2008, 2007 and 2006		82
Pinnacle West Consolidated Balance Sheets as of December 31, 2008 and 2007		83
Pinnacle West Consolidated Statements of Cash Flows for 2008, 2007 and 2006		85
Pinnacle West Consolidated Statements of Changes in Common Stock Equity for 2008, 2007 and 2006		86
Notes to Pinnacle West’s Consolidated Financial Statements		87
Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)		142
Report of Independent Registered Public Accounting Firm		143
APS Statements of Income for 2008, 2007 and 2006		145
APS Balance Sheets as of December 31, 2008 and 2007		146
APS Statements of Cash Flows for 2008, 2007 and 2006		148
APS Statements of Changes in Common Stock Equity for 2008, 2007 and 2006		149
Supplemental Notes to APS’ Financial Statements		151
Financial Statement Schedules for 2008, 2007 and 2006
Pinnacle West Schedule I – Condensed Statements of Income for 2008, 2007 and 2006		159
Pinnacle West Schedule I – Condensed Balance Sheets as of December 31, 2008 and 2007		160
Pinnacle West Schedule I – Condensed Statements of Cash Flows for 2008, 2007 and 2006		161
Pinnacle West Schedule II – Reserve for Uncollectibles for 2008, 2007 and 2006		162
APS Schedule II – Reserve for Uncollectibles for 2008, 2007 and 2006		163

See Note 13 and S-2 for the selected quarterly financial data (unaudited) required to be presented in this Item.

79

MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(PINNACLE WEST CAPITAL CORPORATION)

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework inInternal Control – Integrated Framework,our management concluded that our internal control over financial reporting was effective as of December 31, 2008. The effectiveness of our internal control over financial reporting as of December 31, 2008 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.

February 19, 2009

80

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedules listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

81

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

As reflected in the consolidated statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective December 31, 2006.

/s/ Deloitte & Touche LLP

DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 19, 2009

82

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)

	Year Ended December 31,
	2008			2007			2006
OPERATING REVENUES
Regulated electricity segment	$	3,127,383		$	2,918,163		$	2,635,036
Real estate segment		131,067			212,586			399,798
Marketing and trading		66,897			138,247			136,748
Other revenues		41,729			48,018			36,172
Total		3,367,076			3,317,014			3,207,754
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		1,284,116			1,140,923			960,649
Real estate segment operations		149,125			192,972			324,861
Real estate impairment charge (Note 23)		53,250			—			—
Marketing and trading fuel and purchased power		45,572			100,462			105,415
Operations and maintenance		807,852			728,340			684,020
Depreciation and amortization		390,358			372,102			358,605
Taxes other than income taxes		125,336			128,210			128,395
Other expenses		34,171			38,925			28,415
Total		2,889,780			2,701,934			2,590,360
OPERATING INCOME		477,296			615,080			617,394
OTHER
Allowance for equity funds used during construction		18,636			21,195			14,312
Other income (Note 19)		12,078			24,694			44,028
Other expense (Note 19)		(31,576	)		(25,857	)		(27,777	)
Total		(862	)		20,032			30,563
INTEREST EXPENSE
Interest charges		216,290			208,521			196,826
Capitalized interest		(18,820	)		(23,063	)		(20,989	)
Total		197,470			185,458			175,837
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		278,964			449,654			472,120
INCOME TAXES (Note 4)		65,407			150,910			155,855
INCOME FROM CONTINUING OPERATIONS		213,557			298,744			316,265
INCOME FROM DISCONTINUED OPERATIONS
Net of income tax expense of $18,489, $5,582 and $7,133 (Note 22)		28,568			8,399			10,990
NET INCOME	$	242,125		$	307,143		$	327,255
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC		100,691			100,256			99,417
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED		100,965			100,835			100,010
EARNINGS PER WEIGHTED – AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	2.12		$	2.98		$	3.18
Net income – basic		2.40			3.06			3.29
Income from continuing operations – diluted		2.12			2.96			3.16
Net income – diluted		2.40			3.05			3.27
DIVIDENDS DECLARED PER SHARE	$	2.10		$	2.10		$	2.025

See Notes to Pinnacle West’s Consolidated Financial Statements.

83

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)

	December 31,
	2008			2007
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	105,245		$	56,321
Customer and other receivables		292,682			349,134
Accrued utility revenues		100,089			106,873
Allowance for doubtful accounts		(3,383	)		(4,782	)
Materials and supplies (at average cost)		173,252			149,759
Fossil fuel (at average cost)		29,752			27,792
Deferred income taxes (Note 4)		79,729			31,510
Home inventory (Notes 1 and 23)		50,688			98,729
Assets from risk management and trading activities (Note 18)		32,581			57,605
Other current assets		21,847			33,988
Total current assets		882,482			906,929
INVESTMENTS AND OTHER ASSETS
Real estate investments – net (Notes 1, 6 and 23)		415,296			532,600
Assets from long-term risk management and trading activities (Note 18)		33,675			48,928
Nuclear decommissioning trust (Note 12)		343,052			379,347
Other assets		117,935			117,941
Total investments and other assets		909,958			1,078,816
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
Plant in service and held for future use		12,264,805			11,640,739
Less accumulated depreciation and amortization		4,141,546			4,004,944
Net		8,123,259			7,635,795
Construction work in progress		572,354			625,577
Intangible assets, net of accumulated amortization of $282,196 and $252,122		131,722			105,746
Nuclear fuel, net of accumulated amortization of $55,343 and $68,375		89,323			69,271
Total property, plant and equipment		8,916,658			8,436,389
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Notes 1, 3 and 4)		7,984			110,928
Other regulatory assets (Notes 1, 3 and 4)		787,506			514,353
Other deferred debits		115,505			114,794
Total deferred debits		910,995			740,075
TOTAL ASSETS	$	11,620,093		$	11,162,209

See Notes to Pinnacle West’s Consolidated Financial Statements.

84

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)

	December 31,
	2008			2007
LIABILITIES AND COMMON STOCK EQUITY
CURRENT LIABILITIES
Accounts payable	$	261,029		$	323,346
Accrued taxes		109,798			269,628
Accrued interest		40,741			39,836
Short-term borrowings (Note 5)		670,469			340,661
Current maturities of long-term debt (Note 6)		177,646			163,773
Customer deposits		78,745			80,010
Liabilities from risk management and trading activities (Note 18)		69,585			24,510
Other current liabilities		97,915			102,685
Total current liabilities		1,505,928			1,344,449
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)		3,031,603			3,127,125
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)		1,403,318			1,243,743
Regulatory liabilities (Notes 1, 3 and 4)		587,586			642,564
Liability for asset retirements (Note 12)		275,970			281,903
Liabilities for pension and other postretirement benefits (Note 8)		675,788			504,603
Liabilities from risk management and trading activities (Note 18)		126,532			4,701
Other		567,389			481,510
Total deferred credits and other		3,636,583			3,159,024
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
COMMON STOCK EQUITY (Note 7)
Common stock, no par value; authorized 150,000,000 shares; issued 100,948,436 at end of 2008 and 100,525,470 at end of 2007		2,151,323			2,135,787
Treasury stock at cost; 59,827 shares at end of 2008 and 39,505 at end of 2007		(2,854	)		(2,054	)
Total common stock		2,148,469			2,133,733
Accumulated other comprehensive income (loss):
Pension and other postretirement benefits (Note 8)		(47,547	)		(39,336	)
Derivative instruments		(99,151	)		23,473
Total accumulated other comprehensive loss		(146,698	)		(15,863	)
Retained earnings		1,444,208			1,413,741
Total common stock equity		3,445,979			3,531,611
TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	11,620,093		$	11,162,209

See Notes to Pinnacle West’s Consolidated Financial Statements.

85

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)

	Year Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	242,125		$	307,143		$	327,255
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		423,969			403,896			386,760
Deferred fuel and purchased power		(80,183	)		(196,136	)		(252,849	)
Deferred fuel and purchased power amortization		183,126			231,106			265,337
Deferred fuel and purchased power regulatory disallowance		—			14,370			—
Allowance for equity funds used during construction		(18,636	)		(21,195	)		(14,312	)
Real estate impairment charge		53,250			—			—
Deferred income taxes		158,024			(58,027	)		27,738
Change in mark-to-market valuations		9,074			17,579			28,464
Changes in current assets and liabilities:
Customer and other receivables		80,834			62,850			9,189
Materials, supplies and fossil fuel		(25,453	)		(29,776	)		(9,094	)
Other current assets		8,734			(10,040	)		(890	)
Accounts payable		(69,439	)		(42,004	)		(46,055	)
Home inventory		48,041			(56,883	)		11,563
Other current liabilities		(18,279	)		43,421			(566	)
Expenditures for real estate investments		(21,168	)		(121,316	)		(126,229	)
Other changes in real estate assets		18,211			82,521			34,990
Change in margin and collateral accounts – assets		17,450			(37,371	)		(249,792	)
Change in margin and collateral accounts – liabilities		(132,416	)		19,284			(46,444	)
Change in unrecognized tax benefits		(94,551	)		25,178			—
Change in other long-term assets		6,104			(23,826	)		17,541
Change in other long-term liabilities		24,751			47,162			30,896
Net cash flow provided by operating activities		813,568			657,936			393,502
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(935,577	)		(960,390	)		(788,982	)
Contributions in aid of construction		60,292			41,809			51,203
Capitalized interest		(18,820	)		(23,063	)		(20,990	)
Proceeds from the sale of Silverhawk		—			—			207,620
Proceeds from sale of investment securities		—			69,225			1,406,704
Purchases of investment securities		—			(36,525	)		(1,439,404	)
Proceeds from nuclear decommissioning trust sales		317,619			259,026			254,651
Investment in nuclear decommissioning trust		(338,361	)		(279,768	)		(275,393	)
Proceeds from sale of commercial real estate investments		94,171			58,139			39,621
Other		5,517			(1,807	)		(3,763	)
Net cash flow used for investing activities		(815,159	)		(873,354	)		(568,733	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		96,934			230,571			757,636
Repayment and reacquisition of long-term debt		(181,491	)		(162,060	)		(527,864	)
Short-term borrowings – net		331,741			304,911			9,911
Dividends paid on common stock		(204,247	)		(210,473	)		(201,220	)
Common stock equity issuance		3,687			24,089			39,548
Other		3,891			(2,509	)		30,427
Net cash flow provided by financing activities		50,515			184,529			108,438
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		48,924			(30,889	)		(66,793	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		56,321			87,210			154,003
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	105,245		$	56,321		$	87,210
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of refunds	$	24,233		$	204,643		$	157,245
Interest, net of amounts capitalized	$	191,085		$	193,533		$	153,503

See Notes to Pinnacle West’s Consolidated Financial Statements.

86

PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)

	Year Ended December 31,
	2008			2007			2006
COMMON STOCK (Note 7)
Balance at beginning of year	$	2,135,787		$	2,114,550		$	2,067,377
Issuance of common stock		10,845			24,089			39,420
Other		4,691			(2,852	)		7,753
Balance at end of year		2,151,323			2,135,787			2,114,550
TREASURY STOCK (Note 7)
Balance at beginning of year		(2,054	)		(449	)		(1,245	)
Purchase of treasury stock		(1,387	)		(1,964	)		(229	)
Reissuance of treasury stock used for stock compensation, net		587			359			1,025
Balance at end of year		(2,854	)		(2,054	)		(449	)
RETAINED EARNINGS
Balance at beginning of year		1,413,741			1,319,747			1,193,712
Net income		242,125			307,143			327,255
Common stock dividends		(211,405	)		(210,473	)		(201,220	)
Cumulative effect of change in accounting for income taxes (Note 4)		—			(2,676	)		—
Other		(253	)		—			—
Balance at end of year		1,444,208			1,413,741			1,319,747
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year		(15,863	)		12,268			165,120
Pension and other postretirement benefits (Note 8):
Unrealized actuarial loss, net of tax benefit of ($7,801) and ($13,573)		(11,053	)		(21,976	)		—
Prior service cost, net of tax benefit of ($495)		—			(769	)		—
Amortization to income:
Actuarial loss, net of tax expense of $1,578 and $1,670		2,437			2,214			—
Prior service cost, net of tax expense of $222 and $252		343			391			—
Transition obligation, net of tax expense of $40 and $43		62			67			—
Minimum pension liability adjustment, net of tax expense (benefit) of $28,425		—			—			44,086
Adjustment to reflect a change in accounting (SFAS No. 158), net of tax expense of $22,412		—			—			33,928
Derivative instruments:
Net unrealized gain (loss), net of tax expense (benefit) of ($54,490), ($414) and ($137,606)		(83,093	)		(785	)		(214,777	)
Reclassification of net realized gain to income, net of tax benefit of ($24,786), ($4,679) and ($10,308)		(39,531	)		(7,273	)		(16,089	)
Balance at end of year		(146,698	)		(15,863	)		12,268
TOTAL COMMON STOCK EQUITY	$	3,445,979		$	3,531,611		$	3,446,116
COMPREHENSIVE INCOME
Net income	$	242,125		$	307,143		$	327,255
Other comprehensive loss		(130,835	)		(28,131	)		(186,780	)
Comprehensive income	$	111,290		$	279,012		$	140,475

See Notes to Pinnacle West’s Consolidated Financial Statements.

87

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Consolidation and Nature of Operations

     Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado, Pinnacle West Marketing & Trading and Pinnacle West Energy (dissolved as of August 31, 2006). Intercompany accounts and transactions between the consolidated companies have been eliminated.

     APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. APSES provides energy-related projects and competitive commodity energy to commercial and industrial retail customers in competitive markets in the western United States. Recently, APSES has discontinued its commodity-related energy services (see Note 22). El Dorado is an investment firm. Pinnacle West Marketing & Trading began operations in early 2007. These operations were previously conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.

Accounting Records and Use of Estimates

     Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Derivative Accounting

     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity and fuels. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

     We account for our derivative contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if certain hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). To the extent the amounts that would otherwise be recognized in income are eligible to be recovered through the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings. SFAS No. 133 provides a scope

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exception for contracts that meet the normal purchases and sales criteria specified in the standard. Contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.

     Under fair value (mark-to-market) accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, as current or long-term assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets.

     We determine fair value in accordance with SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value as the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

     We determine fair market value using actively-quoted prices for identical instruments when available. When actively quoted prices are not available for the identical instruments we use prices for similar instruments or other corroborative market information or prices provided by other external sources. Quarterly and calendar year quotes from independent brokers are converted into monthly prices using historical relationships. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market transactions, or we can determine that the inputs the broker used to arrive at the quoted price are observable.

     For options, long-term contracts and other contracts for which price quotes are not available, we use unobservable inputs, such as models and other valuation methods, to determine fair market value. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.

     For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.

     The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When

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applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.

     The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.

     See Note 14 for additional information about fair value measurements. See Note 18 for additional information about our derivative and energy trading accounting policies.

Regulatory Accounting

     APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.

     Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.

     A component of our regulatory assets is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery or refund 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates, subject to specified parameters. (See Note 3).

     Also included in the balance of regulatory assets at December 31, 2008 is a regulatory asset for pension and other postretirement benefits in accordance with SFAS No. 158. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.

     The detail of regulatory assets is as follows (dollars in millions):

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	December 31,
	2008		2007
Pension and other postretirement benefits	$	473	$	338
Deferred fuel and purchased power – mark-to-market		118		7
Regulatory asset for deferred income taxes		51		40
Deferred compensation		30		30
Transmission vegetation management		20		6
Demand side management		17		3
Coal reclamation		17		18
Competition rules compliance charge (a)		16		25
Loss on reacquired debt		16		16
Deferred fuel and purchased power (a) (Note 3)		8		111
Other		29		31
Total regulatory assets (b)	$	795	$	625

(a)	Subject to a carrying charge.
(b)	There are no regulatory assets for which regulators have allowed recovery of costs but not allowed a return by exclusion from rate base.

     The detail of regulatory liabilities is as follows (dollars in millions):

	December 31,
	2008		2007
Removal costs (a)	$	388	$	392
Regulatory liability related to asset retirement obligations		103		153
Tax benefit of Medicare subsidy		16		35
Deferred gains on utility property		20		20
Spent nuclear fuel		22		11
Renewable energy standard		22		10
Deferred interest income (b)		8		13
Other		9		9
Total regulatory liabilities	$	588	$	643

(a)	In accordance with SFAS No. 71, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.
(b)	Subject to a carrying charge.

Utility Plant and Depreciation

     Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:

• material and labor;

• contractor costs;

• capitalized leases;

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• construction overhead costs (where applicable); and

• capitalized interest or an allowance for funds used during construction.

     We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.

     APS records a regulatory liability for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount that has been recovered in regulated rates and the amount calculated under SFAS No. 143 “Accounting for Asset Retirement Obligations,” as interpreted by FIN 47. APS believes it can recover in regulated rates the costs calculated in accordance with SFAS No. 143.

     We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2008 were as follows:

• Fossil plant – 16 years;

• Nuclear plant – 18 years;

• Other generation – 31 years;

• Transmission – 42 years;

• Distribution – 33 years; and

• Other – 7 years.

     For the years 2006 through 2008, the depreciation rates ranged from a low of 1.11% to a high of 12.46%. The weighted-average rate was 3.08% for 2008, 3.11% for 2007 and 3.14 % for 2006. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 years.

Investments

     El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).

     Our investments in the nuclear decommissioning trust fund are accounted for in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” See Note 12 for more information on these investments.

Capitalized Interest

     Capitalized interest represents the cost of debt funds used to finance non-regulated construction projects. The rate used to calculate capitalized interest was a composite rate of 5.2% for 2008, 5.8% for 2007 and 6.8% for 2006. Capitalized interest ceases when construction is complete.

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Allowance for Funds Used During Construction

     AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. APS’ allowance for borrowed funds is included in capitalized interest on the Consolidated Financial Statements. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

     AFUDC was calculated by using a composite rate of 7.0% for 2008, 8.2% for 2007 and 8.0% for 2006. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Electric Revenues

     We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.

     Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and purchased power and fuel costs.

     All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis.

Real Estate Revenues

     SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed under the percentage of completion method per SFAS No. 66, “Accounting for Sales of Real Estate.” SunCor recognizes income only after the asset title has passed. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided. In addition, see Note 22 – Discontinued Operations.

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Real Estate Investments

     Real estate investments primarily include SunCor’s land, home inventory, commercial property and investments in joint ventures. Land includes acquisition costs, infrastructure costs, capitalized interest and property taxes directly associated with the acquisition and development of each project. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes and condos under construction. Homes under construction are classified as “real estate investments” on the Consolidated Balance Sheets; upon completion of construction they are transferred to “home inventory” with the expectation that they will be sold in a timely manner.

     For the purposes of evaluating impairment in accordance with the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we classify our real estate assets, including land under development, land held for future development, and commercial property as “held and used.” When events or changes in circumstances indicate that the carrying values of real estate assets considered held and used may not be recoverable, we compare the undiscounted cash flows that we estimate will be generated by each asset to its carrying amount. If the carrying amount exceeds the undiscounted cash flows, we adjust the asset to fair value and recognize an impairment charge. The adjusted value becomes the new book value (carrying amount) for held and used assets.

     Real estate home inventory is considered to be held for sale for purposes of evaluating impairment in accordance with the provisions of SFAS No. 144. Home inventories are reported at the lower of carrying amount or fair value less costs to sell. Fair value less costs to sell is evaluated each period to determine if it has changed. Losses (and gains not to exceed any cumulative loss previously recognized) are reported as adjustments to the carrying amount.

     Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated, but are accounted for using the equity method of accounting. In addition, see Note 22 – Discontinued Operations and Note 23 – Real Estate Impairment Charge.

Cash and Cash Equivalents

     We consider all highly liquid investments with a maturity of three months or less at acquisition to be cash equivalents.

Nuclear Fuel

     APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.

     APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal and Note 12 for information on nuclear decommissioning costs.

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Income Taxes

     Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes” and FIN 48, “Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109.” We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax liability accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. See Note 4.

Intangible Assets

     We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’ software, on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. Amortization expense was $33 million in 2008, $37 million in 2007 and $39 million in 2006. Estimated amortization expense on existing intangible assets over the next five years is $29 million in 2009, $27 million in 2010, $21 million in 2011, $18 million in 2012 and $13 million in 2013. At December 31, 2008, the weighted average remaining amortization period for intangible assets was 8 years.

2. New Accounting Standards

     See Note 14 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted effective January 1, 2008, and the following related accounting guidance:

• FASB Staff Position, No. 157-2, “Effective Date of FASB Statement No. 157”

• FASB Staff Position, No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”

     See Notes 18 and S-3 for discussions of FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), which we adopted January 1, 2008.

     SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” was effective for us on January 1, 2008. This guidance provides companies with an option to report selected financial assets and liabilities at fair value. We did not elect the fair value option for any of our financial assets or liabilities. Therefore, SFAS No. 159 did not have an impact on our financial statements.

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This guidance requires enhanced disclosures about derivative instruments and hedging activities. The Statement is effective for us on January 1, 2009. It did not have a material impact on our financial statements.

     In December 2008, the FASB issued FASB Staff Position No. 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.” This guidance requires enhanced employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The guidance

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is effective for us on December 31, 2009. We do not expect it to have a material impact on our financial statements.

     See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which was adopted January 1, 2007.

3. Regulatory Matters

     2008 General Rate Case

     APS Request– On June 2, 2008, APS filed with the ACC updated financial statements, testimony and other data in the general rate case originally filed on March 24, 2008. As requested by the ACC staff, the updated information reflects a test year ended December 31, 2007, rather than the September 30, 2007 test year used in APS’ original filing. As a result of the updated filing, APS is requesting a net retail rate increase of $278.2 million effective no later than October 1, 2009, which represents a base rate increase of $448.2 million less the reclassification of $170 million of fuel and purchased power revenues from the existing PSA to base rates. As proposed by APS, the updated request would result in an average rate increase of 8.5% for existing customers plus the establishment of a new growth-related impact fee to be charged to new connections.

     The key financial provisions of the updated request include:

• an increase of $264.3 million in non-fuel base rates and a net increase of $13.9 million for fuel and purchased power costs reflected in base rates, and recovery of up to $53 million of such increases through the impact fee;

• a rate base of $5.4 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2007, which includes certain adjustments, such as the inclusion of Units 5 and 6 of the Yucca Power Plant (near Yuma in southwestern Arizona), the steam generator replacement at Palo Verde Unit 3, environmental upgrades to APS coal plants, and other plant additions under construction at the end of the test year that are currently in service or expected to go into service before the proposed rates are requested to become effective;

• the following proposed capital structure and costs of capital:

	Capital Structure			Cost of Capital
Long-term debt		46.2	%		5.77	%
Common stock equity		53.8	%		11.50	%
Weighted-average cost of capital					8.86	%

• a Base Fuel Rate of $0.0388 per kWh based on estimated 2010 prices (compared to the current Base Fuel Rate of $0.0325 per kWh);

• an attrition adjustment of $79.3 million to address erosion in APS’ earnings and return on equity through 2010; and

• a new super-peak residential time-of-use rate and a commercial and industrial critical peak pricing proposal to allow eligible customers additional options to manage their electric bills, as well as other conservation-related rate design proposals.

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     The update also requests that the ACC adopt certain goals for APS to improve its financial strength, which include: allowing APS’ internal cash flow generation to cover its operating and capital costs of providing service; stabilizing and improving APS’ credit ratings; and providing a meaningful and ongoing opportunity for APS to achieve a reasonable return on the fair value of its property.

     In addition, APS requested various modifications to the Environmental Improvement Surcharge and the Demand Side Management Adjustment Clause that would allow APS to expand its conservation and demand-side management programs and support environmental upgrades to APS facilities in response to and in anticipation of future environmental requirements.

     Interim Rate Surcharge– On December 18, 2008, the ACC approved an emergency interim base rate surcharge for APS. This surcharge became effective for retail customer bills issued after December 31, 2008 and will continue in effect until a decision in the general rate case becomes effective. This surcharge is expected to increase annual pretax retail revenues approximately $65.2 million, and is subject to refund with interest pending the final outcome of APS’ general retail rate case. In June 2008, APS had requested an interim increase of approximately $115 million in annual pretax retail revenues.

     The decision requires that APS (a) examine its operations and expenses, targeting additional cuts of at least $20 million, report the results of its study to the ACC no later than March 18, 2009, and reinvest the savings and surcharge revenues “in infrastructure and technology necessary to serve APS customers and reduce the need for external debt financing”; (b) file with the ACC periodic reports of communications with credit ratings agencies; and (c) post a $10 million bond or letter of credit until the ACC issues a final order in APS’ general retail rate case.

     ACC Staff Rate Case Recommendation– On December 19, 2008, the ACC staff and other intervenors filed their initial written testimony with the ACC in the general retail rate case. In its filed testimony, the ACC staff recommends a number of cost disallowances and test-year adjustments that decrease APS’ base rate request by $141.6 million. The principal components of the revenue increase recommended by the ACC staff are $155.1 million for non-fuel increases and $11.4 million for fuel and purchased power costs reflected in base rates (net of the reclassification of $140.1 million of existing PSA revenues to base rates).

     In its recommendations, the ACC staff also proposed, among other things:

• A Base Fuel Rate of $0.0377 per kWh;

• A weighted-average cost of capital of 8.58%, based on a return on common equity of 11.0% and APS’ proposed capital structure;

• A reduction to APS’ proposed rate base of $57 million, the majority of which ($45 million) results from the exclusion of post test-year plant placed into service after December 31, 2008;

• Exempting low income customers from any rate increase;

• That APS engage in a dialogue with the ACC concerning opportunities to expand the use of renewable energy beyond current ACC mandated requirements; and

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• That APS should propose in its rebuttal testimony a means to provide customers with greater rate stability, such as the use of a three-year interval between base rate filings.

     The ACC staff also recommended that the ACC reject the following APS proposals:

• The $79.3 million attrition adjustment; and

• Modifications to APS’ line extension policy that would have resulted in the establishment of the growth-related impact fee referenced above.

     Other Intervenors’ Recommendations– Other intervenors in the rate case include the Arizona Residential Utility Consumer Office (“RUCO”), an office established by the Arizona legislature to represent the interests of residential utility consumers before the ACC; and Arizonans for Electric Choice and Competition (“AECC”), a coalition that advocates on behalf of commercial and industrial utility customers. These other intervenors’ testimony includes the following recommendations:

• RUCO recommends no net rate change after reclassification of $170.0 million of PSA revenues to base rates, based on a rate base of $4.9 billion, a base fuel rate of $0.0388 per kWh, APS’ proposed capital structure, and a return on common equity of 9.6%.

• AECC recommends that APS’ request be reduced by $101.4 million (of which $42.5 million was a reduction in fuel and purchased power expense).

     Settlement Discussions and Procedural Schedule– On January 30, 2009, APS began settlement discussions with the parties to the general rate case. An ACC ALJ has issued a procedural order staying the procedural schedule in the rate case for thirty days to allow the parties to participate in settlement discussions. While it is in effect, the stay vacates previously established dates for testimony filings and the discovery process. Additional stays may be requested by the parties, depending on the settlement discussions. Hearings in the rate case were previously scheduled to begin on April 2, 2009.

     2007 Retail Rate Order

     In June 2007, the ACC issued an order in a general retail rate case that APS filed in late 2005. The order approved a $322 million increase in APS’ annual retail base revenues, effective July 1, 2007, which included a $315 million fuel-related increase and a $7 million non-fuel related increase. The order also authorized APS’ recovery of approximately $34 million of 2005 PSA deferrals through a temporary PSA surcharge over a twelve-month period beginning July 1, 2007, disallowed approximately $14 million in 2007 of 2005 PSA deferrals because it found the Palo Verde outage costs giving rise to those amounts resulted from APS’ imprudence, modified the PSA in various respects and increased the Base Fuel Rate. In addition, the order provided that the 2007 PSA adjustor, which took effect on February 1, 2007 and that was scheduled to expire on January 31, 2008, remain in effect as long as necessary to allow APS to collect $46 million of PSA deferrals resulting from the mid-2007 implementation of the new Base Fuel Rate. The 2007 PSA adjustor expired as of the last billing cycle in July 2008.

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     PSA Mechanism

     The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case, and which was modified by the ACC in 2007, provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:

• APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;

• under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchase power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate;

• an adjustment is made annually each February 1^st and goes into effect automatically unless suspended by the ACC;

• the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which will be reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point); and

• the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) an “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component.

     PSA Balance

     The following table shows the changes in the deferred fuel and purchased power regulatory asset for the year ended December 31, 2008 and 2007 (dollars in millions):

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	Year Ended
	December 31,
	2008			2007
Beginning balance	$	111		$	160
Deferred fuel and purchased power costs-current period		78			189
Regulatory disallowance		—			(14	)
Interest on deferred fuel and purchased power		2			7
Amounts recovered through revenues		(183	)		(231	)
Ending balance	$	8		$	111

     The PSA annual adjustor rate is reset for a “PSA Year” effective for a twelve-month period beginning February 1 each year. The PSA rate for the PSA Year that began February 1, 2008 was set at $0.004 per kWh. The PSA rate for the PSA year that began February 1, 2009 was set at $0.0053 per kWh. The PSA rate may not be increased more than $0.004 per kWh in a year without permission of the ACC. Any uncollected deferrals during the 2009 PSA Year resulting from this limit will be included in the historical component of the PSA rate for the PSA Year beginning February 1, 2010.

     Formula Transmission Tariff

     In July 2008, the FERC approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect the costs that APS incurs in providing transmission services. The formula rate is updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year, and projected capital expenditures. A large portion of the rate represents charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS must file an application with the ACC under the transmission cost adjustor (“TCA”) mechanism, by which changes in Retail Transmission Charges can be reflected in APS’ retail rates.

     In 2008, APS was authorized to implement increases in its annual transmission revenues based on calculations filed with the FERC using data for its 2006 and 2007 fiscal years. Increases in APS’ annual transmission revenues of $28 million became effective March 1, 2008 and $15 million became effective June 1, 2008. The ACC allowed APS to reflect the related increased Retail Transmission Charges in its retail rates through the TCA resulting in increases of annual retail revenues of $27 million effective March 1, 2008 and $13 million effective July 3, 2008.

     Equity Infusion Approval

     On May 2, 2008, Pinnacle West filed a notice with the ACC that would allow Pinnacle West to infuse up to $400 million of equity into APS in the event Pinnacle West deems it appropriate to do so to strengthen or maintain APS’ financial integrity. Under Arizona law and implementing regulatory decisions, Pinnacle West is required to give such notice at least 120 days prior to an equity infusion into APS that exceeds $150 million in a single calendar year. On August 6, 2008, the ACC issued an order permitting the infusion to occur on or before December 31, 2009.

     On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consisted of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006. In May 2007, Pinnacle West infused

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PINNACLE WEST CAPITAL CORPORATION
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approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.

Federal

     FERC Order

     On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APSES (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.

     On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ authority to make sales at market-based rates in the APS control area (the “April 17 Order”). The FERC found that the Pinnacle West Companies failed to provide the necessary information about the calculation of transmission imports into the APS control area to allow the FERC to make a determination regarding FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.

     On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on October 12, 2007. This compliance filing was accepted conditionally by the FERC in an order issued January 17, 2008. In compliance with the January 17, 2008 order, the Pinnacle West Companies filed a revised mitigation plan to implement cost-based rates for sales in the Phoenix Valley during the summer months. On May 30, 2008, the FERC issued a letter order accepting our mitigation plan. The first summer period under this cost-based mitigation began on June 1, 2008. This proceeding is now concluded.

4. Income Taxes

     Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.

     APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.

     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated income tax return was the subject of an IRS review and the IRS finalized its examination in the second quarter of 2008,

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which included a settlement on the tax accounting method change and favorable resolution of other various tax matters. As a result of this settlement and the lapse of federal statutes prior to 2005, we recognized net income tax benefits of approximately $30 million, including approximately $23 million related to interest.

     We adopted FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109,” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest. The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period that are included in accrued taxes and other deferred credits on the Consolidated Balance Sheets (dollars in thousands):

	2008			2007
Total unrecognized tax benefits, January 1	$	157,869		$	132,691
Additions for tax positions of the current year		12,923			—
Additions for tax positions of prior years		32,510			65,022
Reductions for tax positions of prior years for:
Changes in judgment		(4,454	)		(37,419	)
Settlements with taxing authorities		(35,812	)		(2,425	)
Lapses of applicable statute of limitations		(99,718	)		—
Total unrecognized tax benefits, December 31	$	63,318		$	157,869

     Included in the balance of unrecognized tax benefits at December 31, 2008 and 2007 were approximately $16 million and $5 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.

     We reflect interest and penalties, if any, on unrecognized tax benefits in the consolidated statement of income as income tax expense. The amount of interest recognized in the consolidated statement of income related to unrecognized tax benefits was a pre-tax benefit of $51 million for 2008 and pre-tax expense of $3 million for 2007.

     The total amount of accrued liabilities for interest recognized in the consolidated balance sheets related to unrecognized tax benefits as of December 31, 2008 and 2007 was $6 million and $57 million, respectively. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2008, we have recognized $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

     The tax year ended December 31, 2005 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 1999. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next 12 months.

     The components of income tax expense are as follows (dollars in thousands):

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	Year Ended December 31,
	2008			2007			2006
Current:
Federal	$	(85,866	)	$	183,547		$	110,029
State		11,738			30,972			21,507
Total current		(74,128	)		214,519			131,536
Deferred:
Income from continuing operations		158,024			(56,147	)		31,452
Discontinued operations		—			(1,880	)		—
Total deferred		158,024			(58,027	)		31,452
Total income tax expense		83,896			156,492			162,988
Less: income tax expense (benefit) on discontinued operations		18,489			5,582			7,133
Income tax expense – continuing operations	$	65,407		$	150,910		$	155,855

     The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense – continuing operations (dollars in thousands):

	Year Ended December 31,
	2008			2007			2006
Federal income tax expense at 35% statutory rate	$	97,637		$	157,379		$	165,242
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		9,601			16,801			17,250
Credits and favorable adjustments related to prior years resolved in current year		(28,873	)		(13,205	)		(14,028	)
Medicare Subsidy Part-D		(1,993	)		(3,236	)		(3,156	)
Allowance for equity funds used during construction (see Note 1)		(5,755	)		(6,899	)		(4,679	)
Other		(5,210	)		70			(4,774	)
Income tax expense – continuing operations	$	65,407		$	150,910		$	155,855

     The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):

	December 31,
	2008			2007
Current asset	$	79,729		$	31,510
Long-term liability		(1,403,318	)		(1,243,743	)
Accumulated deferred income taxes – net	$	(1,323,589	)	$	(1,212,233	)

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     The components of the net deferred income tax liability were as follows (dollars in thousands):

	December 31,
	2008			2007
DEFERRED TAX ASSETS
Risk management and trading activities	$	132,383		$	13,958
Regulatory liabilities:
Asset retirement obligation		194,326			214,607
Federal excess deferred income taxes		9,428			11,091
Tax benefit of Medicare subsidy		4,197			11,727
Other		9,789			26,579
Pension and other postretirement liabilities		281,053			211,192
Deferred gain on Palo Verde Unit 2 sale leaseback		12,665			14,408
Other		92,251			112,209
Total deferred tax assets		736,092			615,771
DEFERRED TAX LIABILITIES
Plant-related		(1,709,872	)		(1,538,183	)
Risk management and trading activities		(20,732	)		(29,531	)
Regulatory assets:
Deferred fuel and purchased power		(3,157	)		(43,661	)
Deferred fuel and purchased power – mark-to-market		(46,593	)		(2,782	)
Pension and other postretirement benefits		(186,916	)		(133,120	)
Other		(92,411	)		(80,727	)
Total deferred tax liabilities		(2,059,681	)		(1,828,004	)
Accumulated deferred income taxes – net	$	(1,323,589	)	$	(1,212,233	)

5. Lines of Credit and Short-Term Borrowings

     Pinnacle West had a committed line of credit with various banks totaling $300 million at December 31, 2008 and December 31, 2007 due to terminate in December 2010. Credit commitments totaling approximately $17 million from Lehman Brothers are no longer available due to its September 2008 bankruptcy filing. The remaining $283 million revolver is available to support the issuance of up to $250 million in commercial paper or to be used as bank borrowings, including issuances of letters of credit of up to $94 million. At December 31, 2008 Pinnacle West had $144 million of borrowings under its revolving credit facility and approximately $7 million of letters of credit. Pinnacle West had no commercial paper outstanding at December 31, 2008. In general, the Company and APS have been unable to access the commercial paper markets since September 2008. Pinnacle West had remaining capacity available under its revolver of approximately $132 million and had cash and investments of approximately $6 million. At December 31, 2007, Pinnacle West had no borrowings under the line of credit and approximately $5 million of letters of credit and commercial paper borrowings of $115 million. The commitment fees were 0.15 % in 2008 and 2007. The weighted average interest rates were 2.713% at December 31, 2008 and 5.73% at December 31, 2007. All Pinnacle West and APS bank lines of credit and commercial paper agreements are unsecured.

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PINNACLE WEST CAPITAL CORPORATION
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     APS had two committed revolving credit facilities totaling $900 million at December 31, 2008 and December 31, 2007, of which $400 million terminates in December 2010 and $500 million terminates in September 2011. Credit commitments totaling about $34 million from Lehman Brothers are no longer available due to its September 2008 bankruptcy filing. The remaining $866 million is available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuances of letters of credit of up to $583 million. At December 31, 2008, APS had borrowings of approximately $522 million and no letters of credit under its revolving lines of credit. APS had no commercial paper outstanding as of December 31, 2008. In general, the Company and APS have been unable to access the commercial paper markets since September 2008. At December 31, 2008, APS had remaining capacity available under its revolvers of $344 million and had cash and investments of approximately $72 million. At December 31, 2007, APS had borrowings of $218 million under its $500 million line of credit and $4 million of letters of credit issued under its $400 million line of credit. APS had no commercial paper outstanding at December 31, 2007. The commitment fees for the $500 million line of credit were 0.10% at December 31, 2008 and December 31, 2007. The commitment fees for the $400 million line of credit were 0.11% at December 31, 2008 and December 31, 2007. The weighted average interest rates were 2.09% at December 31, 2008 and 5.36% at December 31, 2007.

     Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million (which is required to be used for purchases of natural gas and power) and (b) APS’ long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. This financing order expires December 31, 2012; however, all debt previously authorized and outstanding on December 31, 2012 will remain authorized and valid obligations of APS.

     SunCor had two revolving lines of credit totaling $170 million at December 31, 2008, and December 31, 2007. The $150 million credit facility is secured and matures January 30, 2010 and the $20 million unsecured loan facility matured January 31, 2009. See Note 6 for additional information on the secured credit facility. The unsecured loan facility includes approximately $5 million in borrowings. SunCor is currently in the process of renegotiating this facility and, if unable to do so, will repay the amounts outstanding. At December 31, 2008 and December 31, 2007 Suncor had borrowings of $120 million and $85 million under the $150 million credit facility. At December 31, 2008 and December 31, 2007 Suncor had borrowings of $5 million and $9 million under the $20 million credit facility. The commitment fees ranged from 0.125% to 0.250% in 2008 and were 0.125% in 2007 for the $150 million line of credit. The commitment fees for the $20 million line of credit were 0.50% in 2008 and 2007. The weighted-average interest rate was 4.11% at December 31, 2008 and 7.27% at December 31, 2007. Interest was based on LIBOR plus 2.0% for 2008 and 2007. SunCor had other short-term borrowings of $5 million at December 31, 2008 and $8 million at December 31, 2007. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2008 and 2007.

6. Long-Term Debt and Liquidity Matters

     Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2008 and 2007 (dollars in thousands):

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						December 31,
	Maturity		Interest
	Dates (a)		Rates			2008			2007
APS
Pollution control bonds		2024-2034		(b	)	$	539,145		$	565,855
Pollution control bonds with senior notes		2029		5.05	%		90,000			90,000
Unsecured notes		2011		6.375	%		400,000			400,000
Unsecured notes		2012		6.50	%		375,000			375,000
Unsecured notes		2033		5.625	%		200,000			200,000
Unsecured notes		2015		4.650	%		300,000			300,000
Unsecured notes		2014		5.80	%		300,000			300,000
Unsecured notes		2035		5.50	%		250,000			250,000
Unsecured notes		2016		6.25	%		250,000			250,000
Unsecured notes		2036		6.875	%		150,000			150,000
Secured note		2014		6.00	%		1,258			1,430
Unamortized discount and premium							(7,908	)		(8,883	)
Capitalized lease obligations		2009-2012		(c	)		3,621			4,457
Subtotal (d)							2,851,116			2,877,859
SUNCOR
Notes payable		2009-2013		(e	)		182,804			237,671
Capitalized lease obligations		2009-2012		(f	)		329			368
Subtotal							183,133			238,039
PINNACLE WEST
Senior notes		2011		5.91	%		175,000			175,000
Total long-term debt							3,209,249			3,290,898
Less current maturities							177,646			163,773
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES						$	3,031,603		$	3,127,125

(a)	This schedule does not reflect the timing of redemptions that may occur prior to maturity.
(b)	The weighted-average rate was 8.3% at December 31, 2008 and 3.76% at December 31, 2007. Changes in short-term interest rates would affect the costs associated with this debt. In addition, these amounts include $343 million of auction rate debt securities backed by insurance at December 31, 2008 and 2007. On September 11, 2008, APS repurchased at par two series of pollution control bonds that had no credit enhancements. The repurchase included $7 million of its 1996 Series A Coconino County Pollution Control Bonds and $20 million of its 1999 Series A Coconino County Pollution Control Bonds. APS borrowed funds under its revolving lines of credit to re-purchase the bonds, as permitted under the bond indenture. APS intends to keep the $27 million outstanding until we complete our planned refunding and reissuance of these bonds, if market and business conditions allow, in 2009.
(c)	The weighted-average interest rate was 5.51% at December 31, 2008 and December 31, 2007.
(d)	APS’ long-term debt less current maturities was $2.850 billion at December 31, 2008 and $2.877 billion at December 31, 2007. APS’ current maturities of long-term debt were $1 million at December 31, 2008 and 2007.

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(e)

SunCor had $125 million outstanding at December 31, 2008 under its revolving lines of credit. The weighted-average interest rate was 4.11% at December 31, 2008. The remaining amount of approximately $58 million at December 31, 2008 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 1.7%, 2.0%, 2.25% and 2.5%. SunCor had $94 million outstanding at December 31, 2007 under its revolving lines of credit. The weighted-average interest rate was 7.27% at December 31, 2007. The remaining amount of approximately $143 million at December 31, 2007 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 1.7%, 2.0% and 2.25%. There is also a note at a fixed rate of 4.25% at December 31, 2008 and 2007.

(f)

The weighted-average interest rate was 6.2% at December 31, 2008 and 7.0% at December 31, 2007.

     The credit and liquidity markets experienced significant stress beginning the week of September 15, 2008. While Pinnacle West’s and APS’ ability to issue commercial paper has been negatively impacted by the market stress, they have both been able to access existing credit facilities, ensuring adequate liquidity. Cash on hand is being invested in money market funds consisting of U.S. Treasury and government agency securities and repurchase agreements collateralized fully by U.S. Treasury and government agency securities.

     The interest rates on eleven issues of APS’ pollution control bonds, in the aggregate amount of approximately $343 million, are reset every seven days through auction processes. These bonds are supported by bond insurance policies provided by Ambac, and the interest rates on the bonds can be directly affected by the rating of the bond insurer. Certain bond insurers, including Ambac, have had downgrades of their credit ratings. Downgrades of bond insurers result in downgrades of the insured bonds, which increases the possibility of a “failed auction” and results in higher interest rates during the failed auction periods. When auctions of APS bonds fail, the APS bondholders receive the maximum 14% annual interest rate for the week of the failed auction. For the twelve months ended December 31, 2008, we had ninety-nine failed auctions, which represented about 17% of all of our auctions. The average interest rate at December 31, 2008 on the auction rate securities was 12.4%. Bond auctions continued to fail through mid-January; however, since that time, we have had only one failure. The average interest rate at February 18, 2009 on the auction rate securities was 5.7%. We continue to closely monitor this market and, if market and business conditions allow, we are planning on refunding and reissuing these bonds during 2009. We do not expect, however, that our auction rate interest exposure will have a material adverse impact on our financial position, results of operations, cash flows or liquidity.

     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At December 31, 2008, the ratio was approximately 51% for Pinnacle West and 49% for APS. The provisions regarding interest coverage require a minimum cash coverage of 2 times. The interest coverage was approximately 4.5 times under APS’ bank financing agreements as of December 31, 2008. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

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     Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank financing agreements contain a pricing grid in which interest costs we pay are determined by our current credit ratings.

     All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.

     An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At December 31, 2008, APS’ common equity ratio, as defined, was 54%. Its total common equity was approximately $3.3 billion, and total capitalization was approximately $6.2 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.5 billion, assuming APS’ total capitalization remains the same.

     SunCor’s principal loan facility, the Secured Revolver, is secured primarily by an interest in land, commercial properties, land contracts and homes under construction. The Secured Revolver matures on January 30, 2010 (classified as current maturities of long-term debt at December 31, 2008). SunCor is required to repay amounts under the Secured Facility in order to reduce the lenders’ commitments. The Secured Revolver requires compliance with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow coverage and restrictions on debt. In addition to the Secured Revolver, at December 31, 2008, SunCor had approximately $68 million in borrowings under other credit facilities that mature at various dates and also contain certain loan covenants. The majority of this indebtedness is due in 2009, and SunCor is in the process of renegotiating these facilities.

     If SunCor is unable to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities, SunCor could be required to immediately repay its outstanding indebtedness under all of its credit facilities as a result of cross-default provisions. Such a debt acceleration would have a material adverse impact on SunCor’s business and its financial position. The Company has not guaranteed any SunCor indebtedness. As a result, the Company does not believe that SunCor’s inability to meet its financial covenants under the Secured Revolver or its other outstanding credit facilities would have a material adverse impact on Pinnacle West’s cash flows or liquidity, although any resulting SunCor losses would be reflected in Pinnacle West’s consolidated financial statements.

     As of December 31, 2008, the amount of SunCor’s net assets that could not be transferred to Pinnacle West in the form of cash dividends as a result of the covenants mentioned above was approximately $224 million out of a total of approximately $263 million. As a result of the restrictions under the ACC order referenced above and contained in the SunCor loan facilities, as of December 31, 2008, the restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at December 31, 2008, our consolidated net assets were approximately $3.4 billion). These restrictions do not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

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PINNACLE WEST CAPITAL CORPORATION
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     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions):

	Pinnacle West-
Year	Consolidated		APS
2009	$	178	$	1
2010		199		197
2011		578		401
2012		376		376
2013		2		—
Thereafter		1,884		1,884
Total	$	3,217	$	2,859

7. Common Stock and Treasury Stock

     Our common stock and treasury stock activity during each of the three years 2008, 2007 and 2006 is as follows (dollars in thousands):

	Common Stock					Treasury Stock
	Shares		Amount			Shares			Amount
Balance at December 31, 2005		99,077,133	$	2,067,377			(20,058	)	$	(1,245	)
Common stock issuance		883,933		39,420			—			—
Purchase of treasury stock (a)		—		—			(5,505	)		(229	)
Reissuance of treasury stock for stock compensation (net)		—		—			23,144			1,025
Other		—		7,753			—			—
Balance at December 31, 2006		99,961,066		2,114,550			(2,419	)		(449	)
Common stock issuance		564,404		24,089			—			—
Purchase of treasury stock (a)		—		—			(47,218	)		(1,964	)
Reissuance of treasury stock for stock compensation (net)		—		—			10,132			359
Other		—		(2,852	)		—			—
Balance at December 31, 2007		100,525,470		2,135,787			(39,505	)		(2,054	)
Common stock issuance		422,966		10,845			—			—
Purchase of treasury stock (a)		—		—			(39,022	)		(1,387	)
Reissuance of treasury stock for stock compensation (net)		—		—			18,700			587
Other		—		4,691			—			—
Balance at December 31, 2008		100,948,436	$	2,151,323			(59,827	)	$	(2,854	)

(a) Represents shares of common stock withheld from certain stock awards for tax purposes.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8. Retirement Plans and Other Benefits

     Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.

     We also sponsor other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.

     Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. The fair market value of investments in our retirement and postretirement plans is determined using actively-quoted prices when available. When actively-quoted prices are not available, we use prices provided by external sources, models or other valuation methods. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through the application of these methods.

     A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and therefore is recoverable in rates. Accordingly, these changes are recorded as a regulatory asset.

     The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):

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	Pension									Other Benefits
	2008			2007			2006			2008			2007			2006
Service cost-benefits earned during the period	$	54,576		$	51,803		$	47,287		$	17,793		$	18,491		$	19,968
Interest cost on benefit obligation		110,207			100,736			92,196			37,897			35,284			34,653
Expected return on plan assets		(118,309	)		(107,165	)		(95,912	)		(43,609	)		(42,177	)		(36,930	)
Amortization of:
Transition (asset) obligation		—			—			(645	)		3,005			3,005			3,005
Prior service cost (credit)		2,455			2,957			2,401			(125	)		(125	)		(125	)
Net actuarial loss		11,145			16,331			23,366			2,372			3,929			8,662
Net periodic benefit cost	$	60,074		$	64,662		$	68,693		$	17,333		$	18,407		$	29,233
Portion of cost charged to expense	$	28,854		$	28,063		$	30,912		$	8,325		$	7,989		$	13,155
APS share of cost charged to expense	$	27,491		$	26,548		$	29,203		$	7,932		$	7,557		$	12,428

     The following table shows the plans’ changes in the benefit obligations and funded status for the years 2008 and 2007 (dollars in thousands):

	Pension						Other Benefits
	2008			2007			2008			2007
Change in Benefit Obligation
Benefit obligation at January 1	$	1,720,844		$	1,670,274		$	605,125		$	616,985
Service cost		54,576			51,803			17,793			18,491
Interest cost		110,207			100,736			37,897			35,284
Benefit payments		(62,058	)		(52,168	)		(17,566	)		(17,763	)
Actuarial (gain) loss		61,087			(52,227	)		12,016			(47,872	)
Plan amendments		—			2,426			—			—
Benefit obligation at December 31		1,884,656			1,720,844			655,265			605,125
Change in Plan Assets
Fair value of plan assets at January 1		1,318,939			1,214,229			499,764			480,638
Actual return on plan assets		132,449			101,138			(64,364	)		26,952
Employer contributions		35,000			52,000			10,972			18,407
Benefit payments		(56,016	)		(48,428	)		(17,066	)		(26,233	)
Fair value of plan assets at December 31		1,430,372			1,318,939			429,306			499,764
Funded Status at December 31	$	(454,284	)	$	(401,905	)	$	(225,959	)	$	(105,361	)

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     The following table shows the projected benefit obligation and the accumulated benefit obligation for the pension plan in excess of plan assets as of December 31, 2008 and 2007 (dollars in thousands):

	2008		2007
Projected benefit obligation	$	1,884,656	$	1,720,844
Accumulated benefit obligation		1,631,909		1,484,444
Fair value of plan assets		1,430,372		1,318,939

     The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2008 and 2007 (dollars in thousands):

	Pension						Other Benefits
	2008			2007			2008			2007
Current asset	$	—		$	—		$	1,221		$	1,321
Current liability		(5,676	)		(3,984	)		—			—
Noncurrent liability		(448,608	)		(397,921	)		(227,180	)		(106,682	)
Net amount recognized	$	(454,284	)	$	(401,905	)	$	(225,959	)	$	(105,361	)

     The following table shows the details related to accumulated other comprehensive loss as of December 31, 2008 and 2007 (dollars in thousands):

	Pension						Other Benefits
	2008			2007			2008			2007
Net actuarial loss	$	304,335		$	268,532		$	224,624		$	106,407
Prior service cost (credit)		9,946			12,401			(920	)		(1,045	)
Transition obligation		—			—			12,019			15,024
APS’ portion recorded as a regulatory asset		(245,235	)		(221,787	)		(227,490	)		(116,425	)
Income tax benefit		(27,239	)		(23,233	)		(2,493	)		(538	)
Accumulated other comprehensive loss	$	41,807		$	35,913		$	5,740		$	3,423

     The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2009 (dollars in thousands):

			Other
	Pension		Benefits
Net actuarial loss	$	11,064	$	11,094
Prior service cost (credit)		2,080		(125	)
Transition obligation		—		3,004
Total amounts estimated to be amortized from accumulated other comprehensive income and regulatory assets in 2009	$	13,144	$	13,973

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     The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:

							Benefit Costs
	Benefit Obligations						For the Years Ended
	As of December 31,						December 31,
	2008			2007			2008			2007			2006
Discount rate-pension		6.11	%		6.25	%		6.25	%		5.90	%		5.66	%
Discount rate-other benefits		6.13	%		6.31	%		6.31	%		5.93	%		5.68	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%		4.00	%
Expected long-term return on plan assets		N/A			N/A			9.00	%		9.00	%		9.00	%
Initial health care cost trend rate		8.00	%		8.00	%		8.00	%		8.00	%		8.00	%
Ultimate health care cost trend rate		5.00	%		5.00	%		5.00	%		5.00	%		5.00	%
Number of years to ultimate trend rate		4			4			4			4			4

     In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2009, we are assuming a 8.25% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

     Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):

	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	9	$	(7	)
Effect on service and interest cost components of net periodic other postretirement benefit costs		11		(8	)
Effect on the accumulated other postretirement benefit obligation		103		(83	)

Plan Assets

     Pinnacle West’s qualified pension plan and other postretirement benefit plans’ asset allocation at December 31, 2008 and 2007 is as follows:

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	Pension									Other Benefits
Asset Category:	2008			2007			Target Range			2008			2007			Target Range
Equity securities		40	%		68	%		40%-55	%		52	%		70	%		40%-55	%
Fixed income		54			25			40%-55	%		46			28			40%-55	%
Other		6			7			5%-10	%		2			2			2%-5	%
Total		100	%		100	%					100	%		100	%

     The Board of Directors has delegated oversight of the plans’ assets to an Investment Management Committee, which has adopted an investment policy. The investment policy sets forth the objective of providing for future pension benefits by maximizing return consistent with acceptable levels of risk. The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, prohibition of investments in Pinnacle West securities, and external management of plan assets.

     During 2008, Pinnacle West began utilizing long-duration bonds and interest-rate swaps to better match the interest-rate sensitivity of the plans’ assets to that of the plans’ liabilities. The actual return on plan assets for the year ending December 31, 2008, included the impact of unrealized gains related to our pension plan of approximately $495 million and unrealized gains related to our postretirement plan of approximately $65 million due to the strong performance of the U.S. Treasury bond market. In late 2008 and early 2009, we closed out the swap contracts and reinvested the proceeds into long-term bonds.

Contributions

     The required minimum contribution to our pension plan is estimated to be approximately $36 million in 2009 and approximately $25 million in 2010. The contribution to our other postretirement benefit plans in 2009 is estimated to be approximately $15 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

Estimated Future Benefit Payments

     Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter are estimated to be as follows (dollars in thousands):

Year	Pension		Other Benefits (a)
2009	$	68,795	$	19,709
2010		75,553		22,039
2011		84,022		24,549
2012		94,205		27,135
2013		105,717		30,132
Years 2014-2018		702,148		196,470

(a) The expected future other benefit payments take into account the Medicare Part D subsidy.

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Employee Savings Plan Benefits

     Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2008, costs related to APS’ employees represented 96% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. At December 31, 2008, approximately 14% of total plan assets were in Pinnacle West stock. Pinnacle West recorded expenses for this plan of approximately $8 million for 2008, $7 million for 2007 and $6 million for 2006. APS recorded expenses for this plan of approximately $8 million in 2008, $6 million in 2007 and $6 million in 2006.

9. Leases

     In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases or to purchase the property for fair market value at the end of the lease terms. We are analyzing this matter, and will continue to do so as we approach the end of the lease terms, to determine which option or options to pursue. Rent expense is calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the VIE’s involved in the Palo Verde sale leaseback transactions.

     In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.

     Total lease expense recognized in the Consolidated Statements of Income was $74 million in 2008, $73 million in 2007 and $72 million in 2006. APS’ lease expense was $67 million in 2008, $66 million in 2007 and $64 million in 2006.

     The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2009 to 2016.

     Estimated future minimum lease payments for Pinnacle West’s and APS’ operating leases, excluding purchase power agreements, are approximately as follows (dollars in millions):

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	Pinnacle West
Year	Consolidated		APS
2009	$	82	$	76
2010		76		70
2011		71		65
2012		67		62
2013		65		60
Thereafter		135		121
Total future lease commitments	$	496	$	454

10. Jointly-Owned Facilities

     APS shares ownership of some of its generating and transmission facilities with other companies. Our share of operations and maintenance expense and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2008 (dollars in thousands):

								Construction
	Percent			Plant in		Accumulated		Work in
	Owned			Service		Depreciation		Progress
Generating facilities:
Palo Verde Units 1 and 3		29.1	%	$	1,989,210	$	1,032,195	$	51,621
Palo Verde Unit 2 (see Note 9)		17.0	%		670,204		309,143		26,693
Four Corners Units 4 and 5		15.0	%		167,152		102,218		2,633
Navajo Generating Station Units 1, 2 and 3		14.0	%		256,304		149,201		5,102
Cholla common facilities (a)		63.9	%(b)		130,454		42,483		3,548
Transmission facilities:
ANPP 500KV System		35.8	%(b)		82,470		25,246		3,620
Navajo Southern System		31.4	%(b)		41,690		12,998		559
Palo Verde – Yuma 500KV System		23.9	%(b)		9,408		3,994		368
Four Corners Switchyards		27.5	%(b)		3,459		1,339		—
Phoenix – Mead System		17.1	%(b)		36,032		5,577		—
Palo Verde – Estrella 500KV System		55.5	%(b)		78,078		5,044		—

(a)	PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.
(b)	Weighted average of interests.

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11. Commitments and Contingencies

Palo Verde Nuclear Generating Station

     Spent Nuclear Fuel and Waste Disposal

     Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim. In August 2008, the United States Court of Appeals for the Federal Circuit issued decisions in three damages actions brought by other nuclear utilities that could result in a decrease in the amount of our recoverable damages; however, additional appeals in those actions are possible and APS continues to monitor the status of those actions. The trial in the APS matter began on January 28, 2009. Testimony and evidence have been presented by both sides. The trial court has set a post-trial briefing schedule and is expected to hear closing arguments in the early summer of 2009.

     APS currently estimates it will incur $132 million (in 2008 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2008, APS had a regulatory liability of $22 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

     Nuclear Insurance

     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $118 million, subject to an annual limit of $18 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $103 million, with an annual payment limitation of approximately $15 million.

     The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed

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accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals approximately $21 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

Fuel and Purchased Power Commitments

     Pinnacle West and APS are parties to various fuel and purchased power contracts with terms expiring between 2009 and 2042 that include required purchase provisions. Pinnacle West and APS estimate the contract requirements to be approximately $449 million in 2009; $364 million in 2010; $287 million in 2011; $397 million in 2012; $380 million in 2013; and $6.1 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

     Of the various fuel and purchased power contracts mentioned above, some of those contracts have take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2024.

     The following table summarizes our actual and estimated take-or-pay commitments (dollars in millions):

	Actual							Estimated (a)
	2006		2007		2008		2009		2010		2011		2012		2013		Thereafter
Coal take-or-pay commitments	$	67	$	70	$	81	$	103	$	83	$	84	$	86	$	88	$	421

(a) Total take-or-pay commitments are approximately $865 million. The total net present value of these commitments is approximately $595 million.

Coal Mine Reclamation Obligations

     APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’ coal mine reclamation obligation was approximately $91 million at December 31, 2008 and December 31, 2007 and is included in Deferred Credits and Other on the Consolidated Balance Sheets.

California Energy Market Issues and Refunds in the Pacific Northwest

     FERC

     In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue and, to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. In addition, on March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including APS, failed to properly file rate information at the FERC in connection with sales to California from 2000 to March 2002 under market-based rates. Since 2004, the Ninth Circuit and the FERC have issued various decisions and orders involving the aforementioned issues, including decisions related to: entities subject to FERC jurisdiction and, therefore, potentially owing refunds; applicable refund methodologies; the temporal scope and types of transactions that are properly

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subject to the refund orders; and the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings. A settlement, resolving APS’ issues with certain California parties for the current refund period, was approved by the FERC in an order issued on June 30, 2008. The resolution of the claims related to the parties involved in this settlement had no material adverse impact on our financial position, results of operations or cash flows. We currently believe the refund claims at the FERC related to the parties not involved in this settlement will have no material adverse impact on our financial position, results of operations or cash flows.

     On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties sought rehearing of this order; however, under the settlement agreement mentioned above, these parties withdrew their request for rehearing on July 22, 2008.

     On July 25, 2001, the FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Petitions for rehearing of this opinion were filed. Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

Navajo Nation Litigation

     In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.

     In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. On July 10,

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2008, Peabody agreed to dismiss this litigation without prejudice. APS cannot currently predict whether the lawsuit will be refiled based upon the final outcome of the D.C. Lawsuit.

Superfund

     Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.

Salt River Project

     Salt River Project has notified APS that Salt River Project allegedly failed to bill APS for (a) energy losses under certain service schedules of a power contract between the parties and (b) certain other charges under the contract. Salt River Project asserts that certain of these failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims that APS owes it approximately $29 million. APS disputes that it is required to pay these amounts. No lawsuit or litigation has been initiated in the matter at this time. We do not expect that resolution of this matter will have a material adverse impact on our financial position, results of operations or cash flows.

Litigation

     We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or cash flows.

12. Asset Retirement Obligations

     APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term.

     Some of APS’ transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.

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     Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites. The generation sites are strategically located to serve APS Native Load customers. Management expects to continuously use the sites and, thus, cannot estimate a potential closure date. The asset retirement obligations associated with our non-regulated assets are immaterial.

     The following schedule shows the change in our asset retirement obligations for 2008 and 2007 (dollars in millions):

	2008			2007
Asset retirement obligations at the beginning of year	$	282		$	268
Changes attributable to:
Liabilities settled		(2	)		(2	)
Accretion expense		19			20
Estimated cash flow revisions		(23	)		(4	)
Asset retirement obligations at the end of year	$	276		$	282

     In accordance with SFAS No. 71, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 1.

     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income securities and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have recorded the offsetting amount of gains on investment securities in other regulatory liabilities or assets.The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at December 31, 2008 and December 31, 2007 (dollars in millions):

			Total		Total
			Unrealized		Unrealized
	Fair Value		Gains		Losses
2008
Equity securities	$	113	$	18	$	(18	)
Fixed income securities		228		10		(5	)
Net payables (a)		2		—		—
Total	$	343	$	28	$	(23	)
2007
Equity securities	$	175	$	68	$	—
Fixed income securities		204		5		(1	)
Total	$	379	$	73	$	(1	)

(a) Net payables relate to pending securities sales and purchases.

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     The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):

	Year Ended December 31,
	2008			2007			2006
Realized gains	$	7		$	3		$	9
Realized losses		(8	)		(4	)		—
Proceeds from the sale of securities		318			259			255

     The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2008 is as follows (dollars in millions):

	Fair Value
Less than one year	$	11
1 year - 5 years		41
5 years - 10 years		47
Greater than 10 years		129
Total	$	228

     See Note 14 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

13. Selected Quarterly Financial Data (Unaudited)

     Consolidated quarterly financial information for 2008 and 2007 is as follows (dollars in thousands, except per share amounts):

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	2008 Quarter Ended												2008
	March 31,			June 30,			September 30,			December 31,			Total
As originally reported:
Operating revenues	$	736,738		$	926,193		$	1,079,975
Operations and maintenance		194,124			194,909			212,327
Operating income		38,798			178,875			273,913
Income taxes		(557	)		17,076			75,970
Income from continuing operations		(4,668	)		114,433			150,503
Net income		(4,473	)		133,862			151,586
APSES reclassifications (see Note 22):
Operating revenues	$	(27,006	)	$	(28,165	)	$	(7,074	)
Operations and maintenance		(1,101	)		(1,209	)		(995	)
Operating income		1,643			(385	)		1,978
Income taxes		650			(148	)		789
Income from continuing operations		1,005			(229	)		1,219
Net income		—			—			—
After APSES reclassifications:
Operating revenues	$	709,732		$	898,028		$	1,072,901		$	686,415		$	3,367,076
Operations and maintenance		193,023			193,700			211,332			209,797			807,852
Operating income		40,441			178,490			275,891			(17,526	)		477,296
Income taxes		93			16,928			76,759			(28,373	)		65,407
Income from continuing operations		(3,663	)		114,204			151,722			(48,706	)		213,557
Net income		(4,473	)		133,862			151,586			(38,850	)		242,125

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	2007 Quarter Ended												2007
	March 31,			June 30,			September 30,			December 31,			Total
As originally reported:
Operating revenues	$	695,017		$	862,902		$	1,205,234		$	757,985		$	3,521,138
Operations and maintenance		171,578			177,310			178,419			207,398			734,705
Operating income		68,221			158,769			338,722			53,319			619,031
Income taxes		9,041			40,713			92,055			10,638			152,447
Income from continuing operations		16,464			79,237			201,718			3,713			301,132
Net income		16,530			78,994			208,708			2,911			307,143
APSES reclassifications (see Note 22):
Operating revenues	$	(44,501	)	$	(52,898	)	$	(57,814	)	$	(48,911	)	$	(204,124	)
Operations and maintenance		(1,509	)		(1,466	)		(1,571	)		(1,819	)		(6,365	)
Operating income		(3,264	)		275			(2,188	)		1,226			(3,951	)
Income taxes		(1,277	)		106			(852	)		486			(1,537	)
Income from continuing operations		(1,984	)		165			(1,324	)		755			(2,388	)
Net income		—			—			—			—
After APSES reclassifications:
Operating revenues	$	650,516		$	810,004		$	1,147,420		$	709,074		$	3,317,014
Operations and maintenance		170,069			175,844			176,848			205,579			728,340
Operating income		64,957			159,044			336,534			54,545			615,080
Income taxes		7,764			40,819			91,203			11,124			150,910
Income from continuing operations		14,480			79,402			200,394			4,468			298,744
Net income		16,530			78,994			208,708			2,911			307,143

Earnings per share:

	2008 Quarter Ended
	March 31,			June 30,		September 30,		December 31,
As originally reported – Basic earnings per share:
Income from continuing operations	$	(0.05	)	$	1.14	$	1.49	$
Net income		(0.04	)		1.33		1.50
After APSES reclassifications – Basic earnings per share:
Income from continuing operations	$	(0.04	)	$	1.13	$	1.51	$	(0.48	)
Net income		(0.04	)		1.33		1.50		(0.39	)
As originally reported – Diluted earnings per share:
Income from continuing operations	$	(0.05	)	$	1.13	$	1.49	$
Net income		(0.04	)		1.33		1.50
After APSES reclassifications – Diluted earnings per share:
Income from continuing operations	$	(0.04	)	$	1.13	$	1.50	$	(0.48	)
Net income		(0.04	)		1.33		1.50		(0.39	)

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	2007 Quarter Ended
	March 31,		June 30,		September 30,		December 31,
As originally reported – Basic earnings per share:
Income from continuing operations	$	0.16	$	0.79	$	2.01	$	0.04
Net income		0.17		0.79		2.08		0.03
After APSES reclassifications – Basic earnings per share:
Income from continuing operations	$	0.14	$	0.79	$	2.00	$	0.04
Net income		0.17		0.79		2.08		0.03
As originally reported – Diluted earnings per share:
Income from continuing operations	$	0.16	$	0.79	$	2.00	$	0.04
Net income		0.16		0.78		2.07		0.03
After APSES reclassifications – Diluted earnings per share:
Income from continuing operations	$	0.14	$	0.79	$	1.99	$	0.04
Net income		0.16		0.78		2.07		0.03

14. Fair Value Measurements

     We adopted SFAS No. 157, “Fair Value Measurements,” on January 1, 2008. This new standard defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The adoption of SFAS No. 157 did not have a material impact on our financial statements.

     In February 2008 the FASB issued FASB Staff Position No. 157-2 (FSP 157-2), “Effective Date of FASB Statement No. 157,” which delayed the effective date of SFAS No. 157 for all nonrecurring fair value measurements of nonfinancial assets and liabilities by one year. In accordance with FSP 157-2 we delayed the adoption of SFAS No. 157 for our nonfinancial assets and liabilities, except those items recognized or disclosed at fair value on a recurring basis, until January 1, 2009. The adoption of SFAS No. 157 for our nonfinancial assets and liabilities did not have a material impact on our financial statements.

     In October 2008, the FASB issued FASB Staff Position No. 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active.” This guidance clarifies the application of SFAS No. 157, “Fair Value Measurements,” in a market that is not active and provides guidance on key considerations in determining the fair value of a financial asset when the market for the asset is not active. This guidance did not have a material impact on our financial statements.

     SFAS No. 157 requires companies to disclose the fair value of certain assets and liabilities according to a fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:

Level 1 – Quoted prices in active markets for identical assets or liabilities. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide information on an ongoing basis. This category includes our derivative

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instruments that are exchange traded such as futures, cash equivalents invested in exchange traded money market funds, and nuclear decommissioning asset investments in Treasury securities.

Level 2 – Quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable. Derivative instruments in this category include non-exchange traded contracts such as forwards, options, and swaps. This category also includes our nuclear decommissioning trust assets in bonds and commingled equity funds.

Level 3 – Model-derived valuations with unobservable inputs that are supported by little or no market activity. Instruments in this category include long dated derivative transactions where models are required due to the length of the transaction, options, and transactions in locations where observable market data does not exist.

     As required by SFAS No. 157, assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. We maximize the use of observable inputs and minimize the use of unobservable inputs. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market transactions, and assessing the volume of transactions.

     Some of our derivative instrument transactions are valued based on unobservable inputs due to the long-term nature of contracts or the unique location of the transactions. Our long-dated energy transactions, consist of observable valuations for the near term portion and unobservable valuations for the long-term portions of the transaction. When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3. Our classification of instruments as Level 3 is primarily reflective of the long term nature of our energy transactions, and is not reflective of material inactive markets. For further discussion of how our derivative instruments are valued see Note 1.

     The nuclear decommissioning trust invests in fixed income securities directly and equity securities indirectly through commingled funds. Commingled funds are valued based on the fund share price and are classified within Level 2. The commingled funds’ underlying investments would be Level 1 if the investments were held directly by the trust. Our trustee provides valuation of our nuclear decommissioning trust assets by using pricing services to determine fair market value. We assess these valuations and verify pricing that can be supported by actual market transactions. The trust fund investments have been established to satisfy APS’ nuclear decommissioning obligations (see Note 12).

     The following table presents the fair value at December 31, 2008 of our assets and liabilities that are measured at fair value on a recurring basis for Pinnacle West Consolidated and APS (dollars in millions):

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	Quoted Prices
	in Active			Significant
	Markets for			Other			Significant
	Identical			Observable			Unobservable			Counterparty			Balance at
	Assets			Inputs			Inputs			Netting &			December 31,
Pinnacle West:	(Level 1)			(Level 2)			(Level 3)			Other (a)			2008
Assets
Cash Equivalents	$	75		$	—		$	—		$	—		$	75
Risk management and trading activities		31			76			51			(92	)		66
Nuclear decommissioning trust		33			308			—			2			343
Total	$	139		$	384		$	51		$	(90	)	$	484
Liabilities
Risk management and trading activities	$	(85	)	$	(297	)	$	(58	)	$	244		$	(196	)

(a) Primarily represents netting under master netting arrangements including margin and collateral. See Notes 12, 18 and S-3.

     The following table shows the changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the twelve months ended December 31, 2008 for Pinnacle West Consolidated and APS (dollars in millions):

	Twelve Months Ended
	December 31, 2008
Net derivative asset balance at beginning of period	$	8
Total net gains (losses) realized/unrealized:
Included in earnings		6
Included in OCI		(8	)
Deferred as a regulatory asset or liability		(39	)
Purchases, issuances, and settlements		10
Level 3 transfers (a)		16
Net derivative liability balance at end of period	$	(7	)
Net unrealized losses included in earnings related to instruments still held as of December 31, 2008	$	7

(a) Transfers reflect fair market value as of the period prior to transfer.

     We did not have any non-recurring fair value measurements during the period that required disclosure.

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     On December 31, 2008, the carrying value of our long-term debt for Pinnacle West, excluding capitalized lease obligations, was $3.21 billion, with an estimated fair value of $2.81 billion. The carrying value of our long-term debt for Pinnacle West excluding capitalized lease obligations was $3.29 billion on December 31, 2007, with an estimated fair value of $3.20 billion. On December 31, 2008, the carrying value of APS’ long-term debt, excluding capitalized lease obligations, was $2.85 billion, with an estimated fair value of $2.46 billion. The carrying value of APS’ long-term debt, excluding capital lease obligations, was $2.87 billion on December 31, 2007, with an estimated fair value of $2.79 billion. The fair value estimates are based on quoted market prices of the same or similar issues.

15. Earnings Per Share

     The following table presents earnings per weighted-average common share outstanding for the years ended December 31, 2008, 2007 and 2006:

	2008		2007		2006
Basic earnings per share:
Income from continuing operations	$	2.12	$	2.98	$	3.18
Income (loss) from discontinued operations		0.28		0.08		0.11
Earnings per share – basic	$	2.40	$	3.06	$	3.29
Diluted earnings per share:
Income from continuing operations	$	2.12	$	2.96	$	3.16
Income (loss) from discontinued operations		0.28		0.09		0.11
Earnings per share – diluted	$	2.40	$	3.05	$	3.27

     Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 274,000 shares in 2008, 579,000 shares in 2007 and 593,000 shares in 2006. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 100,964,920 shares in 2008, 100,834,871 shares in 2007 and 100,010,108 shares in 2006.

     Options to purchase 687,375 shares of common stock were outstanding at December 31, 2008 but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 114,213 at December 31, 2007 and 437,401 at December 31, 2006.

16. Stock-Based Compensation

     Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and our subsidiaries.

     The 2007 Long-Term Incentive Plan (“2007 Plan”) allows Pinnacle West to grant incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, performance cash awards, dividend equivalents and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

stock to eligible individuals. We have reserved 8 million shares of common stock for issuance under the 2007 Plan plus additional shares that become available for issuance under prior stock plans (“Prior Plans”). Under the 2007 Plan, any shares of stock that are potentially deliverable under any award granted under a Prior Plan will be added to the number of shares of stock available for grant under the 2007 Plan if the award expires or is cancelled or terminated without a delivery of such shares to the participant. In addition, any shares of stock that have been issued in connection with any award granted under a Prior Plan will be added to the number of shares available for grant under the 2007 Plan if the award is cancelled, forfeited, or terminated such that those shares are returned to the Company. No more than 500,000 shares of stock may be granted to any one participant during a calendar year. The maximum performance-based award (other than a performance cash award) payable to any one participant during a performance period is 500,000 shares of stock or the cash equivalent. The plan also provides for the granting of new incentive and non-qualified stock options at a price per share equal to at least 100% of the fair market value of the common stock at the time of grant. The terms of the options cannot be longer than 10 years and the options cannot be repriced during their terms.

     The 2002 Long-Term Incentive Plan (“2002 Plan”) relates to outstanding performance shares and stock options but no new awards may be granted under the plan. Performance share awards under the 2002 Plan contain performance criteria that affect the number of shares that ultimately vest.

     The 1994 Long-Term Incentive Plan (“1994 Plan”) relates to outstanding options and restricted stock but no new awards may be granted under the plan. Options vested by thirds over a three-year period beginning one year after the date the option was granted and expire ten years from the date of the grant. The release of the restricted stock is based on employee holdings of our common stock.

     In 2006, Retention Unit Awards (“Retention Units”) were granted to key employees. Each Retention Unit represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. The Company is required to redeem one-fourth of the Retention Units on the first business day of calendar years 2007, 2008, 2009 and 2010. In addition, the employee will receive a cash payment equal to the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. The Retention Units will fully vest on January 2, 2010; for any employee that was eligible to retire before that date, the employee’s Retention Units immediately vested and the compensation expense was immediately recognized as of the date of retirement eligibility. As this award is accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, are remeasured at each balance sheet date, using Pinnacle West’s closing stock price. The amount of cash to settle the payment on the first business day of 2008 was $1.3 million and in 2007 was $1.6 million.

     In 2008 and 2007 under the 2007 Plan, Restricted Stock Unit Awards (“Restricted Stock Units”) were granted to officers and key employees. Each officer and key employee had to elect to receive payment for the vested Restricted Stock Units in cash or in fully transferable shares of stock. The fair value of the stock election is estimated on the date of the grant using the Company’s closing stock price on the date of grant. Each Restricted Stock Unit cash election represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Restricted Stock Units will be redeemed February 20th for four years following the year of the grant. In addition, the employee will receive a cash payment equal to the amount of dividends that the employee would have received if

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the employee had owned the Restricted Stock Unit from the date of grant to the date of payment plus interest. Restricted Stock Units vest over a four-year period for the 2007 and the 2008 grant, unless the employee is eligible to retire, in which case the employee’s Restricted Stock Units are immediately vested (with the same redemption dates) and the compensation expense is immediately recognized; however, the Restricted Stock Units will be redeemed on the pre-established redemption dates. As the Restricted Stock Unit cash election award is accounted for as a liability award, the fair market value of the outstanding Restricted Stock Unit cash election is re-measured at each balance sheet date, using Pinnacle West’s closing stock price. The amount of cash required to settle the payment for the 2007 grant on February 20, 2008 was $1 million.

     In 2008 under the 2007 Plan, performance shares were granted to officers and key employees. Performance share awards under the 2007 Plan contain performance criteria that affect the number of shares that ultimately vest. Generally, each recipient of performance shares is entitled to receive shares of common stock shortly after the end of a three-year performance period. The number of shares each recipient ultimately receives, if any, is based upon the percentile ranking of Pinnacle West’s earnings per share growth rate at the end of the three-year period as compared with the earnings per share growth rate of all relevant companies in a specified utilities index. The fair value of the grant is estimated on the date of the grant using the Company’s closing stock price on the date of the grant. Management evaluates the probability of meeting the performance criteria at each balance sheet date and related compensation cost is amortized over the performance period on a straight-line basis. If the goals are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.

     In 2008 under the 2007 Plan, restricted stock unit awards and performance shares were granted to a selected set of key employees of Pinnacle West on October 21, 2008. This award of performance shares follows the same vesting schedule as the performance shares awarded in 2006, 2007 and 2008. The award of the restricted stock units follows the same vesting schedule as the 2007 and 2008 restricted stock units for the payment dates on February 20^th.

     On January 21, 2009 under the 2007 Plan, the Human Resources Committee approved payment of 2008 incentive awards to officers in the form of Pinnacle West common stock pursuant to the 2007 Plan. This incentive award is included in stock compensation expense in 2008.

     The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $8 million in 2008, $6 million in 2007 and $13 million in 2006. The compensation cost that Pinnacle West has capitalized was immaterial in 2008, 2007 and 2006. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $3 million in 2008, $2 million in 2007 and $5 million in 2006. APS’ share of compensation cost that has been charged against income was $7 million in 2008, $6 million in 2007 and $12 million in 2006.

     The following table is a summary of option activity under our equity incentive plans as of December 31, 2008 and changes during the year:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

					Weighted-
					Average		Aggregate
			Weighted-		Remaining		Intrinsic Value
	Shares		Average Exercise		Contractual Term		(dollars in
Options	(in thousands)		Price		(Years)		thousands)
Outstanding at January 1, 2008		861	$	40.84
Exercised		—		—
Forfeited or expired		165		45.18
Outstanding at December 31, 2008		696		39.81		2.6	$	—
Exercisable at December 31, 2008		696		39.81		2.6	$	—

     There were no options granted during the years 2006 through 2008. The intrinsic value of options exercised was zero for 2008, $2 million for 2007 and $5 million for 2006.

     The following table is a summary of the status of stock compensation awards, other than options, as of December 31, 2008 and changes during the year:

	Shares		Weighted-Average Grant-Date
Nonvested shares	(in thousands)		Fair Value
Nonvested at January 1, 2008		379	$	43.64
Granted		287		36.07
Vested		159		41.64
Forfeited		216		43.62
Nonvested at December 31, 2008		291		39.98

     As of December 31, 2008, there was $7 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 2.3 years. The total fair value of shares vested during 2008 was $5 million, $6 million for 2007 and $10 million for 2006.

     The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2008, 2007 and 2006:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2008		2008 Grant		2007		2007 Grant				2006 Grant
	Shares/		Date Fair		Shares/		Date Fair		2006		Date Fair
	Units		Value (a)		Units		Value (a)		Shares		Value (a)
Restricted stock award units		42,552	$	37.00		27,026	$	46.58		—	$	—
Restricted cash award units		149,856		37.00		107,891		46.58		—		—
Performance share awards		193,192		37.00		134,917		48.42		274,070		41.50
Stock ownership incentive awards		—		—		—		—		12,526		41.50
Retention unit awards		—		—		—		—		123,197		49.92
Special grant		—		—		2,000		41.88		—		—
Special award restricted stock award units		18,500	$	31.82		—		—		—		—
Special award restricted cash award units		13,750	$	31.82		—		—		—		—
Special award performance share awards		33,050	$	31.82		—		—		—		—

(a) Restricted stock units, performance shares, special grant and stock ownership incentive awards priced at the closing market price on the grant date.

     Cash received from options exercised under our share-based payment arrangements was zero for 2008, $8 million for 2007 and $22 million for 2006. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was zero for 2008, $1 million for 2007 and $2 million for 2006.

     Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans and it does not expect to repurchase any shares during 2009.

17. Business Segments

     Pinnacle West’s two reportable business segments are:

• our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and

• our real estate segment, which consists of SunCor’s real estate development and investment activities.

     Financial data for 2008, 2007 and 2006 is provided as follows (dollars in millions):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Business Segments for the Year Ended December 31, 2008
	Regulated
	Electricity
	Segment			Real Estate Segment			All other (a)		Total
Operating revenues	$	3,127		$	131		$	109	$	3,367
Purchased power and fuel costs		1,284			—			46		1,330
Other operating expenses		927			203			40		1,170
Operating margin		916			(72	)		23		867
Depreciation and amortization		383			5			2		390
Interest expense		189			6			2		197
Other expense (income)		(4	)		(3	)		8		1
Income from continuing operations before income taxes		348			(80	)		11		279
Income taxes		92			(31	)		4		65
Income from continuing operations		256			(49	)		7		214
Income from discontinued operations – net of income tax expense of $18 million (see Note 22)		—			23			5		28
Net income	$	256		$	(26	)	$	12	$	242
Total assets	$	10,951		$	523		$	146	$	11,620
Capital expenditures	$	856		$	41		$	7	$	904

	Business Segments for the Year Ended December 31, 2007
	Regulated
	Electricity
	Segment			Real Estate Segment			All other (a)			Total
Operating revenues	$	2,918		$	212		$	187		$	3,317
Purchased power and fuel costs		1,141			—			100			1,241
Other operating expenses		836			193			60			1,089
Operating margin		941			19			27			987
Depreciation and amortization		366			4			2			372
Interest expense		180			4			1			185
Other expense (income)		(18	)		(10	)		8			(20	)
Income from continuing operations before income taxes		413			21			16			450
Income taxes		139			7			5			151
Income from continuing operations		274			14			11			299
Income from discontinued operations – net of income tax expense of $6 million (see Note 22)		—			9			(1	)		8
Net income	$	274		$	23		$	10		$	307
Total assets	$	10,356		$	661		$	145		$	11,162
Capital expenditures	$	900		$	161		$	3		$	1,064

133

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Business Segments for the Year Ended December 31, 2006
	Regulated
	Electricity			Real Estate
	Segment			Segment			All other (a)		Total
Operating revenues	$	2,635		$	400		$	173	$	3,208
Purchased power and fuel costs		960			—			106		1,066
Other operating expenses		791			325			50		1,166
Operating margin		884			75			17		976
Depreciation and amortization		354			3			2		359
Interest expense		173			1			2		176
Other expense (income)		(22	)		(11	)		2		(31	)
Income from continuing operations before income taxes		379			82			11		472
Income taxes		120			32			4		156
Income from continuing operations		259			50			7		316
Income from discontinued operations – net of income tax expense of $7 million (see Note 22)		—			10			1		11
Net income	$	259		$	60		$	8	$	327
Capital expenditures	$	662		$	201		$	7	$	870

(a) All other activities relate to marketing and trading, APSES, Silverhawk and El Dorado. Income from discontinued operations for 2008 is primarily related to the resolution of certain tax issues associated with the sale of Silverhawk in 2005. None of these segments is a reportable segment.

18. Derivative and Energy Trading Accounting

     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, and in interest rates. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity and fuels. As of December 31, 2008, we hedged certain exposures to the price variability of commodities for a maximum of 39 months. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

     We recognize all derivatives, except those which qualify for a scope exception, as either assets or liabilities on the balance sheet and measure those instruments at fair value in accordance with SFAS No. 133, as amended by SFAS No. 149. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales exception and are accounted for under the accrual method of accounting. Changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)). For fair value hedges, the gain or loss on the derivative as well as the offsetting loss

134

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

or gain on the hedged item associated with the hedged risk are recognized in earnings. We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. We use fair value hedges to limit our exposure to changes in fair value of an asset or liability.

     For its regulated operations, APS defers for future rate recovery approximately 90% of gains and losses on derivatives that would otherwise be recognized in income pursuant to the PSA mechanism. In the following discussion, amounts that would otherwise be recognized in income will be recorded as either a regulatory asset or liability and have no effect on earnings to the extent these amounts are eligible to be recovered through the PSA.

     We assess hedge effectiveness both at inception and on a continuing basis. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated and is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.

     Derivatives that do not qualify for a scope exception are classified as assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets. Certain of our non-trading derivatives qualify for cash flow hedge accounting treatment. Non-trading derivatives, or any portion thereof that are not effective hedges, are adjusted to fair value through income. Realized gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings.

     All gains and losses (realized and unrealized) on trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis. Trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.

     In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Consolidated Statement of Income, but this does not impact our financial condition, net income or cash flows.

135

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Cash Flow Hedges

     The changes in the fair value of our hedged positions included in the Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2008, 2007 and 2006 are comprised of the following (dollars in thousands):

	2008			2007		2006
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(1,874	)	$	1,430	$	(5,666	)
Losses from the change in options’ time value excluded from measurement of effectiveness		—			—		(10	)
Gains from the discontinuance of Cash flow hedges		—			320		453

     During 2009, we estimate that a net loss of $91 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).

     We adopted FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1) on January 1, 2008. In accordance with this guidance, we elected to offset the fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting arrangement. The following table summarizes our assets and liabilities from risk management and trading activities in accordance with FIN 39-1 at December 31, 2008 and 2007 (dollars in thousands):

				Investments					Deferred
	Current			and Other		Current			Credits and			Net Asset
December 31, 2008	Assets			Assets		Liabilities			Other			(Liability)
Mark-to-market	$	18,759		$	33,675	$	(190,478	)	$	(144,331	)	$	(282,375	)
Margin account		15,222			—		50,136			4,247			69,605
Collateral provided to counterparties		400			—		71,008			13,552			84,960
Collateral provided from counterparties		(1,800	)		—		(251	)		—			(2,051	)
Total	$	32,581		$	33,675	$	(69,585	)	$	(126,532	)	$	(129,861	)

136

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2007	Assets		Assets		Liabilities			Other			(Liability)
Mark-to-market	$	26,333	$	48,928	$	(30,786	)	$	(4,701	)	$	39,774
Margin account		30,650		—		6,148			—			36,798
Collateral provided to counterparties		622		—		128			—			750
Collateral provided from counterparties		—		—		—			—			—
Total	$	57,605	$	48,928	$	(24,510	)	$	(4,701	)	$	77,322

     We maintain a margin account with a broker to support our risk management and trading activities. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

Credit Risk

     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 60% of Pinnacle West’s $66 million of risk management and trading assets as of December 31, 2008. This exposure relates to a long-term traditional wholesale contract with a counterparty that has very high credit quality. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ securities are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1. “Derivative Accounting,” for a discussion of our credit valuation adjustment policy.

     See Note 14 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

19. Other Income and Other Expense

     The following table provides detail of other income and other expense for 2008, 2007 and 2006 (dollars in thousands):

137

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2008			2007			2006
Other income:
Interest income	$	7,602		$	11,656		$	18,862
SunCor other income (a)		2,499			10,702			10,881
SO2 emission allowance sales and other		—			—			10,782
Investment gains – net		—			—			2,554
Miscellaneous		1,977			2,336			949
Total other income	$	12,078		$	24,694		$	44,028
Other expense:
Non-operating costs	$	(13,030	)	$	(13,993	)	$	(16,200	)
Investment losses – net		(17,703	)		(2,341	)		—
Miscellaneous		(843	)		(9,523	)		(11,577	)
Total other expense	$	(31,576	)	$	(25,857	)	$	(27,777	)

(a) Includes equity earnings from a real estate joint venture that is a pass-through entity for tax purposes.

20. Variable-Interest Entities

     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them (see Note 9).

     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2008, APS would have been required to assume approximately $174 million of debt and pay the equity participants approximately $162 million.

     SunCor has certain land development arrangements that are required to be consolidated under FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $29 million at December 31, 2008 and $38 million at December 31, 2007.

21. Guarantees

     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of some of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading and APS relate to commodity energy products. As required by Arizona law, Pinnacle West has also obtained a $10 million bond on behalf of APS in connection with the interim base rate surcharge approved by the ACC in December 2008. See “2008 General Rate Case – Interim Rate Surcharge” in Note 3. Our credit support instruments enable APSES to offer energy-related products and

138

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. At December 31, 2008 we had no guarantees that were in default. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2008 are as follows (dollars in millions):

	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
Parental:
Pinnacle West Marketing & Trading	$	2		1	$	—		—
APSES		14		1		11		1
APS		—		—		11		1
Total	$	16			$	22

     At December 31, 2008, Pinnacle West had approximately $7 million of letters of credit related to workers’ compensation expiring in 2009. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2008, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $78 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Notes 9 and 20 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

22. Discontinued Operations

     SunCor(real estate segment)–In 2008, 2007 and 2006, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144. As a result of the sales, we recorded a gain from discontinued operations of approximately $24 million ($40 million pretax) in 2008; $10 million ($17 million pretax) in 2007; and $9 million ($15 million pretax) in 2006.

139

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Silverhawk– Includes activities related to the resolution of certain tax issues in 2008 associated with the sale of Silverhawk in 2005.

     Other –Includes activities related to the APSES discontinued commodity-related energy services in 2008, and the associated revenues and costs that were reclassified to discontinued operations in 2008, 2007 and 2006.

     The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006 (dollars in millions):

	2008			2007			2006
Revenue:
SunCor – commercial operations	$	1		$	6		$	3
Other (primarily APSES) (a)		67			204			195
Total revenue	$	68		$	210		$	198
Income (loss) before taxes:
SunCor – commercial operations	$	37		$	15		$	17
Silverhawk		13			—			1
Other (primarily APSES)		(3	)		(1	)		—
Total income before taxes	$	47		$	14		$	18
Income (loss) after taxes:
SunCor – commercial operations	$	23		$	9		$	10
Silverhawk		8			—			—
Other (primarily APSES)		(3	)		(1	)		1
Total income after taxes	$	28		$	8		$	11

(a) APSES discontinued its commodity-related energy services in 2008 and the associated revenues and costs were reclassified to discontinued operations in 2008, 2007 and 2006.

23. Real Estate Impairment Charge

     During 2008, particularly late in the year, the real estate market weakened significantly resulting from the severe liquidity shortages in the financial markets, oversupply of home inventories, tight credit markets and downward pressure on residential and commercial property values. The effects of these factors have resulted in elevated cancellation rates, low sales absorption rates and overall weak consumer confidence. In recent months, the overall economy has weakened significantly and fears of a prolonged recession are now pronounced due to rising unemployment levels, further deterioration in consumer confidence and reduced consumer spending. Also, because of terms of renewal of SunCor’s Secured Revolver (see Note 6), during the fourth quarter of 2008, we revised forecasts related to potential disposal of certain assets classified as home inventory and as held and used. These factors resulted in 2008 impairment charges of $24 million related to our home inventory, which is considered held for sale and $29 million related to our held and used assets. The held and used assets include a project under development, an office building, a golf course, and completed home lots in Arizona. We determine fair value for our real estate assets primarily based on the future cash flows that we estimate will be generated by each asset discounted for market risk. Our impairment assessments and fair value determinations require significant judgment regarding key assumptions such as future sales prices, future construction and land development costs, future sales timing, and discount rates. The assumptions are specific

140

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to each project and may vary among projects. The discount rates we used to determine fair values at December 31, 2008 ranged from 17% to 27%. Due to the judgment and assumptions applied in the estimation process, with regard to impairments, it is possible that actual results could differ from those estimates. If conditions in the broader economy or the real estate markets worsen, or as a result of a change in SunCor’s strategy, we may be required to record additional impairments.

141

MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(ARIZONA PUBLIC SERVICE COMPANY)

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework inInternal Control – Integrated Framework,our management concluded that our internal control over financial reporting was effective as of December 31, 2008. The effectiveness of our internal control over financial reporting as of December 31, 2008 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s financial statements.

February 19, 2009

142

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of
Arizona Public Service Company
Phoenix, Arizona

We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”) as of December 31, 2008 and 2007, and the related statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2008, based on criteria established inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

143

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the criteria established inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

As reflected in the statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,effective December 31, 2006.

/s/ Deloitte & Touche LLP 
 

DELOITTE & TOUCHE LLP 

Phoenix, Arizona
February 19, 2009 

144

ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
(dollars in thousands)

	Year Ended December 31,
	2008			2007			2006
ELECTRIC OPERATING REVENUES	$	3,133,496		$	2,936,277		$	2,658,513
OPERATING EXPENSES
Fuel and purchased power		1,289,883			1,151,392			969,767
Operations and maintenance		787,270			710,077			665,631
Depreciation and amortization		383,098			365,430			353,057
Income taxes (Notes 4 and S-1)		113,799			155,735			144,127
Other taxes		124,046			127,648			127,989
Total		2,698,096			2,510,282			2,260,571
OPERATING INCOME		435,400			425,995			397,942
OTHER INCOME (DEDUCTIONS)
Income taxes (Notes 4 and S-1)		6,538			4,578			5,200
Allowance for equity funds used during construction		18,636			21,195			14,312
Other income (Note S-4)		6,231			16,727			31,902
Other expense (Note S-4)		(30,569	)		(21,630	)		(23,830	)
Total		836			20,870			27,584
INTEREST DEDUCTIONS
Interest on long-term debt		170,071			161,030			149,240
Interest on short-term borrowings		13,432			9,564			9,529
Debt discount, premium and expense		4,702			4,639			4,363
Allowance for borrowed funds used during construction		(14,313	)		(12,308	)		(7,336	)
Total		173,892			162,925			155,796
NET INCOME	$	262,344		$	283,940		$	269,730

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

145

ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)

	December 31,
	2008			2007
ASSETS
UTILITY PLANT (Notes 1, 6, 9 and 10)
Electric plant in service and held for future use	$	12,198,010		$	11,582,862
Less accumulated depreciation and amortization		4,129,958			3,994,777
Net		8,068,052			7,588,085
Construction work in progress		571,977			622,693
Intangible assets, net of accumulated amortization of $280,633 and $250,268		131,243			105,225
Nuclear fuel, net of accumulated amortization of $55,343 and $68,375		89,323			69,271
Total utility plant		8,860,595			8,385,274
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 12)		343,052			379,347
Assets from risk management and trading activities (Note S-3)		33,675			41,603
Other assets		60,604			69,570
Total investments and other assets		437,331			490,520
CURRENT ASSETS
Cash and cash equivalents		71,544			52,151
Customer and other receivables		262,177			295,371
Accrued utility revenues		100,089			106,873
Allowance for doubtful accounts		(3,155	)		(4,265	)
Materials and supplies (at average cost)		173,252			149,759
Fossil fuel (at average cost)		29,752			27,792
Assets from risk management and trading activities (Note S-3)		32,181			34,087
Deferred income taxes (Notes 4 and S-1)		79,694			38,707
Other		19,866			16,545
Total current assets		765,400			717,020
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Notes 1, 3, 4 and S-1)		7,984			110,928
Other regulatory assets (Notes 1, 3, 4 and S-1)		787,506			514,353
Unamortized debt issue costs		22,026			24,373
Other		82,735			78,934
Total deferred debits		900,251			728,588
TOTAL ASSETS	$	10,963,577		$	10,321,402

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

146

ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)

	December 31,
	2008			2007
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital (Note 3)		2,117,789			2,105,466
Retained earnings		1,168,901			1,076,557
Accumulated other comprehensive income (loss):
Pension and other postretirement benefits (Note 8)		(26,960	)		(21,782	)
Derivative instruments		(98,742	)		13,038
Common stock equity		3,339,150			3,351,441
Long-term debt less current maturities (Note 6)		2,850,242			2,876,881
Total capitalization		6,189,392			6,228,322
CURRENT LIABILITIES
Short-term borrowings		521,684			218,000
Current maturities of long-term debt (Note 6)		874			978
Accounts payable		233,529			239,923
Accrued taxes		219,129			374,444
Accrued interest		39,860			38,262
Customer deposits		77,452			71,376
Liabilities from risk management and trading activities (Note S-3)		69,585			19,921
Other		105,655			92,802
Total current liabilities		1,267,768			1,055,706
DEFERRED CREDITS AND OTHER
Deferred income taxes (Notes 4 and S-1)		1,401,412			1,250,028
Regulatory liabilities (Notes 1, 3, 4, and S-1)		587,586			642,564
Liability for asset retirements (Note 12)		275,970			281,903
Liabilities for pension and other postretirement benefits (Note 8)		635,327			469,945
Customer advances for construction		132,023			94,801
Liabilities from risk management and trading activities (Note S-3)		126,532			4,573
Other		347,567			293,560
Total deferred credits and other		3,506,417			3,037,374
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	10,963,577		$	10,321,402

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

147

ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
(dollars in thousands)

	Year Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	262,344		$	283,940		$	269,730
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		416,709			395,890			381,173
Deferred fuel and purchased power		(80,183	)		(196,136	)		(252,849	)
Deferred fuel and purchased power amortization		183,126			231,106			265,337
Deferred fuel and purchased power regulatory disallowance		—			14,370			—
Allowance for equity funds used during construction		(18,636	)		(21,195	)		(14,312	)
Deferred income taxes		145,157			(44,478	)		(305	)
Change in mark-to-market valuations		7,792			(6,758	)		6,893
Changes in current assets and liabilities:
Customer and other receivables		47,566			23,882			20,970
Materials, supplies and fossil fuel		(25,453	)		(29,776	)		(14,381	)
Other current assets		128			(8,056	)		3,666
Accounts payable		(5,915	)		(2,797	)		5,825
Other current liabilities		8,150			34,033			68,803
Change in margin and collateral accounts – assets		17,850			11,252			(205,752	)
Change in margin and collateral accounts – liabilities		(132,416	)		27,624			(166,088	)
Change in unrecognized tax benefits		(92,064	)		27,773			—
Change in other long-term assets		14,340			(23,577	)		2,828
Change in other long-term liabilities		36,765			48,718			22,175
Net cash flow provided by operating activities		785,260			765,815			393,713
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(910,189	)		(924,166	)		(699,946	)
Contributions in aid of construction		60,292			41,809			51,203
Allowance for borrowed funds used during construction		(14,313	)		(12,308	)		(7,336	)
Proceeds from sale of investment securities		—			69,225			1,259,203
Purchases of investment securities		—			(36,525	)		(1,291,903	)
Proceeds from nuclear decommissioning trust sales		317,619			259,026			254,651
Investment in nuclear decommissioning trust		(338,361	)		(279,768	)		(275,393	)
Other		5,517			1,211			(4,470	)
Net cash flow used for investing activities		(879,435	)		(881,496	)		(713,991	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		—			—			395,481
Short-term borrowings – net		303,684			218,000			—
Equity infusion		7,601			39,548			212,820
Dividends paid on common stock		(170,000	)		(170,000	)		(170,000	)
Repayment and reacquisition of long-term debt		(27,717	)		(1,586	)		(86,086	)
Net cash flow provided by financing activities		113,568			85,962			352,215
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		19,393			(29,719	)		31,937
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		52,151			81,870			49,933
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	71,544		$	52,151		$	81,870
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes, net of refunds	$	56,728		$	186,183		$	117,831
Interest, net of amounts capitalized	$	167,592		$	165,279		$	131,183

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

148

ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)

	Year Ended December 31,
	2008			2007			2006
COMMON STOCK	$	178,162		$	178,162		$	178,162
ADDITIONAL PAID-IN CAPITAL		2,117,789			2,105,466			2,065,918
RETAINED EARNINGS
Balance at beginning of year		1,076,557			960,405			860,675
Net income		262,344			283,940			269,730
Common stock dividends		(170,000	)		(170,000	)		(170,000	)
Cumulative effect of change in accounting for income taxes (Note S-1)		—			2,212			—
Balance at end of year		1,168,901			1,076,557			960,405
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year		(8,744	)		2,988			93,290
Pension and other postretirement benefits (Note 8):
Unrealized actuarial loss, net of tax benefit of ($5,075) and ($15,126)		(7,597	)		(23,304	)		—
Prior service cost, net of tax benefit of ($463)		—			(713	)		—
Amortization to income:
Actuarial loss, net of tax expense of $1,393 and $1,238		2,130			1,908			—
Prior service cost, net of tax expense of $189 and $212		289			327			—
Minimum pension liability adjustment, net of tax expense of $27,424		—			—			42,731
Adjustment to reflect a change in accounting (SFAS No. 158), net of tax expense of $27,760		—			—			43,401
Derivative instruments:
Net unrealized gain (loss), net of tax expense (benefit) of ($56,149), $1,369, and ($111,367)		(85,670	)		2,040			(173,872	)
Reclassification of net realized (gains) losses to income, net of tax expense (benefit) of ($16,890), $5,164, and ($1,657)		(26,110	)		8,010			(2,562	)
Balance at end of year		(125,702	)		(8,744	)		2,988
TOTAL COMMON STOCK EQUITY	$	3,339,150		$	3,351,441		$	3,207,473
COMPREHENSIVE INCOME
Net income	$	262,344		$	283,940		$	269,730
Other comprehensive loss		(116,958	)		(11,732	)		(133,703	)
Total comprehensive income	$	145,386		$	272,208		$	136,027

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

149

     Certain notes to Arizona Public Service Company’s financial statements are combined with the notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements, the majority of which also relate to Arizona Public Service Company’s financial statements. In addition, listed below are the supplemental notes which are required disclosures for Arizona Public Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s Consolidated Notes.

	Consolidated	APS’ Supplemental
	Footnote Reference	Footnote Reference
Summary of Significant Accounting Policies	Note 1	—
New Accounting Standards	Note 2	—
Regulatory Matters	Note 3	—
Income Taxes	Note 4	Note S-1
Lines of Credit and Short-Term Borrowings	Note 5	—
Long-Term Debt and Liquidity Matters	Note 6	—
Common Stock and Treasury Stock	Note 7	—
Retirement Plans and Other Benefits	Note 8	—
Leases	Note 9	—
Jointly-Owned Facilities	Note 10	—
Commitments and Contingencies	Note 11	—
Asset Retirement Obligations	Note 12	—
Selected Quarterly Financial Data (Unaudited)	Note 13	Note S-2
Fair Value Measurements	Note 14	—
Earnings Per Share	Note 15	—
Stock-Based Compensation	Note 16	—
Business Segments	Note 17	—
Derivative and Energy Trading Accounting	Note 18	Note S-3
Other Income and Other Expense	Note 19	Note S-4
Variable Interest Entities	Note 20	—
Guarantees	Note 21	—
Discontinued Operations	Note 22	—
Related Party Transactions	—	Note S-5
Real Estate Impairment Charge	Note 23	—

150

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

S-1. Income Taxes

     APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’ taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.

     Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.

     APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.

     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated income tax return was the subject of an IRS review and the IRS finalized its examination in the second quarter of 2008, which included a settlement on the tax accounting method change and favorable resolution of other various tax matters. As a result of this settlement and the lapse of federal statutes prior to 2005, we recognized net income tax benefits of approximately $30 million, including approximately $23 million related to interest.

     We adopted FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109,” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest. The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period that are included in accrued taxes and other deferred credits on the Balance Sheets (dollars in thousands):

	2008			2007
Total unrecognized tax benefits, January 1	$	154,473		$	126,700
Additions for tax positions of the current year		12,893			—
Additions for tax positions of prior years		32,481			66,610
Reductions for tax positions of prior years for:
Changes in judgment		(4,547	)		(37,419	)
Settlements with taxing authorities		(35,812	)		(1,418	)
Lapses of applicable statute of limitations		(97,079	)		—
Total unrecognized tax benefits, December 31	$	62,409		$	154,473

151

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

     Included in the balance of unrecognized tax benefits at December 31, 2008 and 2007 were approximately $15 million and $4 million, respectively, of tax positions that, if recognized, would decrease our effective tax rate.

     We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of income as income tax expense. The amount of interest recognized in the statement of income related to unrecognized tax benefits was a pre-tax benefit of $51 million for 2008 and a pre-tax expense of $3 million for 2007.

     The total amount of accrued liabilities for interest recognized in the balance sheets related to unrecognized tax benefits as of December 31, 2008 and 2007 was $5 million and $56 million, respectively. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, as of December 31, 2008, we have recognized $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.

     The tax year ended December 31, 2005 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 1999. We do not anticipate that there will be any significant increases or decreases in our unrecognized tax benefits within the next 12 months.

     The components of APS’ income tax expense are as follows (dollars in thousands):

	Year Ended December 31,
	2008			2007			2006
Current:
Federal	$	(54,719	)	$	168,607		$	114,971
State		16,823			27,028			21,442
Total current		(37,896	)		195,635			136,413
Deferred		145,157			(44,478	)		2,514
Total income tax expense	$	107,261		$	151,157		$	138,927

     On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.

     The following chart compares APS’ pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):

152

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

	Year Ended December 31,
	2008			2007			2006
Federal income tax expense at 35% statutory rate	$	129,362		$	152,284		$	143,030
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		14,956			17,540			15,684
Credits and favorable adjustments related to prior years resolved in current year		(28,873	)		(11,432	)		(10,518	)
Medicare Subsidy Part-D		(1,921	)		(3,100	)		(3,036	)
Allowance for equity funds used during construction (see Note 1)		(5,755	)		(6,900	)		(4,656	)
Other		(508	)		2,765			(1,577	)
Income tax expense	$	107,261		$	151,157		$	138,927

     The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands):

	December 31,
	2008			2007
Current asset	$	79,694		$	38,707
Long-term liability		(1,401,412	)		(1,250,028	)
Accumulated deferred income taxes – net	$	(1,321,718	)	$	(1,211,321	)

153

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

     The components of the net deferred income tax liability were as follows (dollars in thousands):

	December 31,
	2008			2007
DEFERRED TAX ASSETS
Regulatory liabilities:
Asset retirement obligation	$	194,326		$	214,607
Federal excess deferred income tax		9,428			11,091
Tax benefit of Medicare subsidy		4,197			11,727
Other		9,789			26,579
Risk management and trading activities		132,383			12,112
Pension and other postretirement liabilities		265,156			197,620
Deferred gain on Palo Verde Unit 2 sale-leaseback		12,665			14,408
Other		110,019			116,491
Total deferred tax assets		737,963			604,635
DEFERRED TAX LIABILITIES
Plant-related		(1,709,872	)		(1,538,183	)
Risk management and trading activities		(20,732	)		(17,483	)
Regulatory assets:
Deferred fuel and purchased power		(3,157	)		(43,661	)
Deferred fuel and purchased power – mark-to-market		(46,593	)		(2,782	)
Pension and other postretirement benefits		(186,916	)		(133,120	)
Other		(92,411	)		(80,727	)
Total deferred tax liabilities		(2,059,681	)		(1,815,956	)
Accumulated deferred income taxes – net	$	(1,321,718	)	$	(1,211,321	)

154

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

S-2. Selected Quarterly Financial Data (Unaudited)

     Quarterly financial information for 2008 and 2007 is as follows (dollars in thousands):

	2008 Quarter Ended,										2008
	March 31,			June 30,		September 30,		December 31,			Total
Operating revenues	$	625,576		$	831,083	$	1,042,084	$	634,753		$	3,133,496
Operations and maintenance		188,135			187,819		206,526		204,790			787,270
Operating income		33,628			163,860		202,655		35,257			435,400
Net income		(6,364	)		125,382		159,754		(16,428	)		262,344

	2007 Quarter Ended,								2007
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	538,260	$	721,759	$	1,047,062	$	629,196	$	2,936,277
Operations and maintenance		165,934		170,631		171,963		201,549		710,077
Operating income		40,589		109,643		238,144		37,619		425,995
Net income		4,317		75,090		204,257		276		283,940

S-3. Derivative and Energy Trading Accounting

     APS is exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas and coal. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity and fuels. As of December 31, 2008, APS hedged certain exposures to these risks for a maximum of 39 months.

Cash Flow Hedges

     The changes in the fair value of APS’ hedged positions included in the APS Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2008, 2007 and 2006 are comprised of the following (dollars in thousands):

	2008			2007		2006
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(1,874	)	$	1,430	$	(5,666	)
Losses from the change in options’ time value excluded from measurement of effectiveness		—			—		(10	)
Gains from the discontinuance of cash flow hedges		—			150		178

     During 2009, APS estimates that a net loss of $91 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).

155

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

     APS adopted FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1) on January 1, 2008. In accordance with this guidance, APS elected to offset the fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting arrangement. The following table summarizes our assets and liabilities from risk management and trading activities in accordance with FIN 39-1 at December 31, 2008 and 2007 (dollars in thousands):

				Investments					Deferred
				and Other		Current			Credits and			Net Asset
December 31, 2008	Current Assets			Assets		Liabilities			Other			(Liability)
Mark-to-market	$	18,759		$	33,675	$	(190,478	)	$	(144,331	)	$	(282,375	)
Margin account		15,222			—		50,136			4,247			69,605
Collateral provided to counterparties		—			—		71,008			13,552			84,560
Collateral provided from counterparties		(1,800	)		—		(251	)		—			(2,051	)
Total	$	32,181		$	33,675	$	(69,585	)	$	(126,532	)	$	(130,261	)

			Investments					Deferred
			and Other		Current			Credits and			Net Asset
December 31, 2007	Current Assets		Assets		Liabilities			Other			(Liability)
Mark-to-market	$	2,815	$	41,603	$	(26,197	)	$	(4,573	)	$	13,648
Margin account		30,650		—		6,148			—			36,798
Collateral provided to counterparties		622		—		128			—			750
Collateral provided from counterparties		—		—		—			—			—
Total	$	34,087	$	41,603	$	(19,921	)	$	(4,573	)	$	51,196

     We maintain a margin account with a broker to support our risk management and trading activities. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

     See Note 18 for discussion of credit risk and see Note 14 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

S-4. Other Income and Other Expense

     The following table provides detail of APS’ other income and other expense for 2008, 2007 and 2006 (dollars in thousands):

156

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

	2008			2007			2006
Other income:
Interest income	$	3,863		$	10,961		$	16,526
SO2 emission allowance sales and other (a)		392			1,001			10,782
Investment gains – net		—			2,429			3,645
Miscellaneous		1,976			2,336			949
Total other income	$	6,231		$	16,727		$	31,902
Other expense:
Non-operating costs (a)	$	(10,538	)	$	(12,712	)	$	(15,415	)
Asset dispositions		(5,779	)		(1,981	)		(1,851	)
Investment losses – net		(9,438	)		—			—
Miscellaneous		(4,814	)		(6,937	)		(6,564	)
Total other expense	$	(30,569	)	$	(21,630	)	$	(23,830	)

(a) As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).

S-5. Related Party Transactions

     From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s other subsidiaries. The following table summarizes the amounts included in the APS Statements of Income and Balance Sheets related to transactions with affiliated companies (dollars in millions):

	Year Ended December 31,
	2008		2007		2006
Electric operating revenues:
Pinnacle West Marketing & Trading (a)	$	4	$	4	$	6
Other:
Equity infusion from Pinnacle West	$	8	$	40	$	210

(a) Pinnacle West Marketing & Trading ended operations December 2008. These operations were conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.

	As of December 31,
	2008			2007
Net affiliate receivables (payables):
Pinnacle West Marketing & Trading (a)	$	(1	)	$	11
Pinnacle West		(11	)		(9	)
Total	$	(12	)	$	2

(a) Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.

157

ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

     Electric revenues include sales of electricity to affiliated companies at contract prices. However, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3.”

     On May 2, 2008, Pinnacle West filed a notice with the ACC that would allow Pinnacle West to infuse up to $400 million of equity into APS in the event Pinnacle West deems it appropriate to do so to strengthen or maintain APS’ financial integrity. Under Arizona law and implementing regulatory decisions, Pinnacle West is required to give such notice at least 120 days prior to an equity infusion into APS that exceeds $150 million in a single calendar year. On August 6, 2008, the ACC issued an order permitting the infusion to occur on or before December 31, 2009.

     On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consisted of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006. In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.

     Intercompany receivables primarily include amounts related to the intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

158

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME
(in thousands)

	Year Ended December 31,
	2008			2007(a)			2006
Operating revenues	$	52		$	6,708		$	119,224
Operating expenses
Fuel and purchased power		(19,970	)		(35,541	)		101,360
Other operating expenses		9,016			5,659			9,607
Total		(10,954	)		(29,882	)		110,967
Operating income		11,006			36,590			8,257
Other
Equity in earnings of subsidiaries		226,893			287,078			324,504
Other income		1,248			225			2,208
Total		228,141			287,303			326,712
Interest expense		17,550			17,190			20,522
Income from continuing operations		221,597			306,703			314,447
Income tax benefit		(12,374	)		(440	)		(12,898	)
Income from continuing operations – net of income taxes		233,971			307,143			327,345
Income (loss) from discontinued operations		8,154			—			(90	)
Net income	$	242,125		$	307,143		$	327,255

(a) Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.

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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(in thousands)

	Balance at December 31,
	2008			2007 (a)
Assets
Current assets
Cash and cash equivalents	$	6,262		$	137
Customer and other receivables		65,576			82,003
Other current assets		367			1,262
Total current assets		72,205			83,402
Investments and other assets
Investments in subsidiaries		3,661,710			3,711,737
Deferred income taxes		—			11,806
Other assets		20,029			23,591
Total investments and other assets		3,681,739			3,747,134
Total Assets	$	3,753,944		$	3,830,536
Liabilities and Common Stock Equity
Current liabilities
Accounts payable	$	6,310		$	22,177
Accrued taxes		(96,188	)		(86,081	)
Short-term borrowings		144,000			115,000
Deferred income taxes		—			7,682
Liabilities from risk management and trading activities		—			2
Other current liabilities		8,027			18,019
Total current liabilities		62,149			76,799
Long-term debt less current maturities		175,000			175,000
Deferred credits and other
Deferred income taxes		18,027			—
Pension and other postretirement liabilities		27,300			22,248
Other		25,489			24,878
Total deferred credits and other		70,816			47,126
Common stock equity
Common stock		2,148,469			2,133,733
Accumulated other comprehensive income (loss)		(146,698	)		(15,863	)
Retained earnings		1,444,208			1,413,741
Total common stock equity		3,445,979			3,531,611
Total Liabilities and Common Stock Equity	$	3,753,944		$	3,830,536

(a) Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.

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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)

	Year Ended December 31
	2008			2007(a)			2006
Cash flows from operating activities
Net Income	$	242,125		$	307,143		$	327,255
Adjustments to reconcile net income to net cash provided by operating activities:
Equity in earnings of subsidiaries – net		(226,893	)		(287,078	)		(324,504	)
Depreciation and amortization		210			320			470
Deferred income taxes		31,954			(24,192	)		30,384
Change in mark-to-market valuations		(19,975	)		53,228			21,698
Customer and other receivables		38,938			112,543			2,816
Accounts payable		(14,134	)		(57,978	)		(55,675	)
Accrued taxes		(5,230	)		25,127			(49,529	)
Change in margin and collateral accounts – net		—			(11,602	)		75,605
Other net		(7,914	)		(104,968	)		(30,718	)
Net cash flow (used for) provided by operating activities		39,081			12,543			(2,198	)
Cash flows from investing activities
Investments in subsidiaries		(18,765	)		(83,993	)		(4,677	)
Repayments of loans from subsidiaries		10,194			14,996			18,065
Advances of loans to subsidiaries		(22,554	)		(19,796	)		(15,379	)
Dividends received from subsidiaries		170,000			180,000			180,000
Purchases of investment securities		—			—			(147,501	)
Proceeds from sale of investment securities		—			—			147,501
Net cash flow provided by investing activities		138,875			91,207			178,009
Cash flows from financing activities
Issuance of long-term debt		—			—			175,000
Short-term borrowings and payments – net		28,729			87,371			27,900
Dividends paid on common stock		(204,247	)		(210,473	)		(201,221	)
Repayment of long-term debt		—			(115	)		(298,687	)
Common stock equity issuance		3,687			19,593			35,834
Net cash flow used for financing activities		(171,831	)		(103,624	)		(261,174	)
Net increase (decrease) in cash and cash equivalents		6,125			126			(85,363	)
Cash and cash equivalents at beginning of year		137			11			85,374
Cash and cash equivalents at end of year	$	6,262		$	137		$	11

(a) Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006. By the end of 2008, substantially all the contracts were transferred to APS or expired.

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PINNACLE WEST CAPITAL CORPORATION
SCHEDULE II – RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)

			Column C
	Column B		Additions						Column E
	Balance at		Charged to		Charged				Balance
Column A	beginning		cost and		to other		Column D		at end of
Description	of period		expenses		accounts		Deductions		period
Reserve for uncollectibles:
2008	$	4,782	$	6,177	$	—	$	7,576	$	3,383
2007		5,597		4,130		—		4,945		4,782
2006		4,979		4,096		—		3,478		5,597

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ARIZONA PUBLIC SERVICE COMPANY
SCHEDULE II – RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)

			Column C
	Column B		Additions						Column E
	Balance at		Charged to		Charged				Balance
Column A	beginning		cost and		to other		Column D		at end of
Description	of period		expenses		accounts		Deductions		period
Reserve for uncollectibles:
2008	$	4,265	$	5,924	$	—	$	7,034	$	3,155
2007		4,223		5,059		—		5,017		4,265
2006		3,568		4,096		—		3,441		4,223

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

     None.

ITEM 9A. CONTROLS AND PROCEDURES

     (a) Disclosure Controls and Procedures

     The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78aet seq.) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

     Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of December 31, 2008. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

     APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of December 31, 2008. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.

     (b) Management’s Annual Reports on Internal Control Over Financial Reporting

     Reference is made to “Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)” on page 79 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 142 of this report.

     (c) Attestation Reports of the Registered Public Accounting Firm

     Reference is made to “Report of Independent Registered Public Accounting Firm” on page 80 of this report and “Report of Independent Registered Public Accounting Firm” on page 143 of this report on the internal control over financial reporting of Pinnacle West and APS, respectively.

     (d) Changes In Internal Control Over Financial Reporting

     The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of

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financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

     No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended December 31, 2008 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

     None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS
AND CORPORATE GOVERNANCE OF PINNACLE WEST

     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance,” “Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting Compliance” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 20, 2009 (the “2009 Proxy Statement”) and to the Supplemental Item – “Executive Officers of Pinnacle West” in Part I of this report.

     Pinnacle West has adopted a Code of Ethics for Financial Professionals that applies to professional employees in the areas of finance, accounting, internal audit, energy risk management, marketing and trading financial control, tax, investor relations, and treasury and also includes Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and officers holding substantially equivalent positions at Pinnacle West’s subsidiaries. The Code of Ethics for Financial Professionals is posted on Pinnacle West’s website atwww.pinnaclewest.com. Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Professionals by posting such information on Pinnacle West’s website.

ITEM 11. EXECUTIVE COMPENSATION

     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance – How are directors compensated?” and “Executive Compensation” in the 2009 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS

     Reference is hereby made to “Shares of Pinnacle West Stock Owned by Management and Large Shareholders” in the 2009 Proxy Statement.

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Securities Authorized for Issuance Under Equity Compensation Plans

     The following table sets forth information as of December 31, 2008 with respect to our compensation plans and individual compensation arrangements under which our equity securities are authorized for issuance.

EQUITY COMPENSATION PLAN INFORMATION

					Number of securities
					remaining available
					for future issuance
	Number of securities		Weighted-average		under equity
	to be issued upon		exercise price of		compensation plans
	exercise of		outstanding		(excluding securities
	outstanding options,		options, warrants		reflected in column
	warrants and rights		and rights		(a))
Plan Category	(a)1		(b)2		(c)3
Equity compensation plans approved by security holders		1,987,375	$	39.81		7,078,187
Equity compensation plans not approved by security holders		—		—		—
Total		1,987,375	$	39.81		7,078,187

1	This amount includes shares subject to outstanding options as well as shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards. However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period. If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants.
2	The weighted average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price.
3	Awards can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, dividend equivalents, and restricted stock units..

     Equity Compensation Plans Approved By Security Holders

     Amounts in column (a) in the table above include shares subject to awards outstanding under three equity compensation plans that were approved by our shareholders: (a) the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan, under which no new stock awards may be granted; (b) the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan (the “2002 Plan”), under which no new stock awards may be granted; and (c) the Pinnacle West Capital

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Corporation 2007 Long-Term Incentive Plan (the “2007 Plan”), which was approved by our shareholders at our 2007 annual meeting of shareholders. Although we cannot issue additional awards under the 2002 Plan, shares subject to outstanding awards under the 2002 Plan that expire or are cancelled or terminated will be available for issuance under the 2007 Plan. See Note 16 of the Notes to Consolidated Financial Statements for additional information regarding these plans.

     Equity Compensation Plans Not Approved By Security Holders

     The Company does not have any equity compensation plans under which shares can still be issued that have not been approved by shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE

     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance” and to “Related Party Transactions” in the 2009 Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTANT
FEES AND SERVICES

Pinnacle West

     Reference is hereby made to “Audit Matters – What fees were paid to our independent registered public accountants in 2007 and 2008?” and “What are the Audit Committee’s pre-approval policies?” in the 2009 Proxy Statement.

APS

     The following fees were paid to APS’ independent registered public accountants, Deloitte & Touche LLP, for the last two fiscal years:

Type of Service	2007		2008
Audit Fees (1)	$	1,921,601	$	1,935,056
Audit-Related Fees (2)		178,840		233,025
Tax Fees (3)		7,751		8,400

(1)	The aggregate fees billed for services rendered for the audit of annual financial statements and for review of financial statements included in Reports on Form 10-Q.
(2)	The aggregate fees billed for assurance services that are reasonably related to the performance of the audit or review of the financial statements that are not included in Audit Fees reported above, which primarily consist of fees for employee benefit plan audits.
(3)	The aggregate fees billed primarily for tax compliance and tax planning.

     Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’ independent public accountants. The Audit Committee has delegated to the Chairman of the Audit Committee the authority to pre-approve audit and non-audit services to be

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performed by the independent public accountants if the services are not expected to cost more than $50,000. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS were pre-approved by the Audit Committee.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements and Financial Statement Schedules

     See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.

Exhibits Filed

     The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
3.1	Pinnacle West	Articles of Incorporation, restated as of May 21, 2008	3.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-7-08
3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of January 21, 2009
3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’ Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	9-29-93
3.4	APS	Arizona Public Service Company Bylaws, amended as of December 16, 2008
4.1	Pinnacle West	Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value	4.12 to Pinnacle West April 29, 2005 Form 8-K Report, File No. 1-8962	5-2-05

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Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
4.2	Pinnacle West APS	Indenture dated as of January 1, 1995 among APS and The Bank of New York Mellon, as Trustee	4.6 to APS’ Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473	1-11-95
4.2a	Pinnacle West APS	First Supplemental Indenture dated as of January 1, 1995	4.4 to APS’ Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473	1-11-95
4.3	Pinnacle West APS	Indenture dated as of November 15, 1996 between APS and The Bank of New York, as Trustee	4.5 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333- 15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473	11-22-96
4.3a	Pinnacle West APS	First Supplemental Indenture dated as of November 15, 1996	4.6 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473	11-22-96
4.3b	Pinnacle West APS	Second Supplemental Indenture dated as of April 1, 1997	4.10 to APS’ Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report, File No. 1-4473	4-9-97
4.3c	Pinnacle West APS	Third Supplemental Indenture dated as of November 1, 2002	10.2 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962	5-15-03

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Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
4.4	Pinnacle West	Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Senior Unsecured Debt Securities	4.1 to Pinnacle West’s Registration Statement No. 333-52476	12-21-00
4.5	Pinnacle West	Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Subordinated Unsecured Debt Securities	4.2 to Pinnacle West’s Registration Statement No. 333-52476	12-21-00
4.6	Pinnacle West APS	Indenture dated as of January 15, 1998 between APS and The Bank of New York Mellon Trust Company N.A. (successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank), as Trustee	4.10 to APS’ Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473	1-16-98
4.6a	Pinnacle West APS	Fifth Supplemental Indenture dated as of October 1, 2001	4.1 to APS’ September 30, 2001 Form 10-Q, File No. 1-4473	11-6-01
4.6b	Pinnacle West APS	Sixth Supplemental Indenture dated as of March 1, 2002	4.1 to APS’ Registration Statement Nos. 333-63994 and 333-83398 by means of February 26, 2002 Form 8-K Report, File No. 1-4473	2-28-02
4.6c	Pinnacle West APS	Seventh Supplemental Indenture dated as of May 1, 2003	4.1 to APS’ Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report, File No. 1-4473	5-9-03

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Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
4.6d	Pinnacle West APS	Eighth Supplemental Indenture dated as of June 15, 2004	4.1 to APS’ Registration Statement No. 333-106772 by means of June 24, 2004 Form 8-K Report, File No. 1-4473	6-28-04
4.6e	Pinnacle West APS	Ninth Supplemental Indenture dated as of August 15, 2005	4.1 to APS’ Registration Statements Nos. 333-106772 and 333-121512 by means of August 17, 2005 Form 8-K Report, File No. 1-4473	8-22-05
4.6f	APS	Tenth Supplemental Indenture dated as of August 1, 2006	4.1 to APS’ July 31, 2006 Form 8-K Report, File No. 1-4473	8-2-06
4.7	Pinnacle West	Amended and Restated Rights Agreement, dated as of March 26, 1999, between Pinnacle West Capital Corporation and BankBoston, N.A., as Rights Agent, including (i) as Exhibit A thereto the form of Amended Certificate of Designation of Series A Participating Preferred Stock of Pinnacle West Capital Corporation, (ii) as Exhibit B thereto the form of Rights Certificate and (iii) as Exhibit C thereto the Summary of Right to Purchase Preferred Shares	4.1 to Pinnacle West’s March 22, 1999 Form 8-K Report, File No. 1-8962	4-19-99
4.7a	Pinnacle West	Amendment to Rights Agreement, effective as of January 1, 2002	4.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	5-15-02

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Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
4.8	Pinnacle West	Second Amended and Restated Investor’s Advantage Plan dated as of June 23, 2004	4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962	8-9-04
4.8a	Pinnacle West	Third Amended and Restated Investors Advantage Plan dated as of November 25, 2008	4.1 to Pinnacle West’s Form S-3 Registration Statement No. 333-155641	11-25-08
4.9	Pinnacle West	Agreement, dated March 29, 1988, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets	4.1 to Pinnacle West’s 1987 Form 10-K Report, File No. 1-8962	3-30-88
4.9a	Pinnacle West APS	Agreement, dated March 21, 1994, relating to the filing of instruments defining the rights of holders of APS long-term debt not in excess of 10% of APS’ total assets	4.1 to APS’ 1993 Form 10-K Report, File No. 1-4473	3-30-94
10.1.1	Pinnacle West APS	Two separate Decommissioning Trust Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee	10.2 to APS’ September 30, 1991 Form 10-Q Report, File No. 1-4473	11-14-91

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Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
10.1.1a	Pinnacle West APS	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 1, 1994	10.1 to APS’ 1994 Form 10- K Report, File No. 1-4473	3-30-95
10.1.1b	Pinnacle West APS	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 1, 1994	10.2 to APS’ 1994 Form 10-K Report, File No. 1-4473	3-30-95
10.1.1c	Pinnacle West APS	Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991	10.4 to APS’ 1996 Form 10-K Report , File No. 1-4473	3-28-97
10.1.1d	Pinnacle West APS	Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991	10.6 to APS’ 1996 Form 10-K Report, File No. 1-4473	3-28-97
10.1.1e	Pinnacle West APS	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of March 18, 2002	10.2 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	5-15-02
10.1.1f	Pinnacle West APS	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of March 18, 2002	10.4 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	5-15-02
10.1.1g	Pinnacle West APS	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 19, 2003	10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04

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Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
10.1.1h	Pinnacle West APS	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 19, 2003	10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04
10.1.1i	Pinnacle West APS	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of May 1, 2007	10.1 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-9-07
10.1.1j	Pinnacle West APS	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of May 1, 2007	10.2 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 104473	5-9-07
10.1.2	Pinnacle West APS	Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992, among APS, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2	10.1 to Pinnacle West’s 1991 Form 10-K Report, File No. 1-8962	3-26-92

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Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
10.1.2a	Pinnacle West APS	First Amendment to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992	10.2 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
10.1.2b	Pinnacle West APS	Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994	10.3 to APS’ 1994 Form 10-K Report, File No. 1-4473	3-30-95
10.1.2c	Pinnacle West APS	Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 20, 1996	10.1 to APS’ June 30, 1996 Form 10-Q Report, File No. 1-4473	8-9-96
10.1.2d	Pinnacle West APS	Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of December 16, 1996	APS 10.5 to APS’ 1996 Form 10-K Report, File No. 1-4473	3-28-97
10.1.2e	Pinnacle West APS	Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 30, 2000	10.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	5-15-02
10.1.2f	Pinnacle West APS	Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of March 18, 2002	10.3 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	5-15-02

176

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
10.1.2g	Pinnacle West APS	Amendment No. 7 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of December 19, 2003	10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04
10.1.2h	Pinnacle West APS	Amendment No. 8 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of April 1, 2007	10.1.2h to Pinnacle West’s 2007 Form 10-K Report, File No. 1-8962	2-27-08
10.2.1b	Pinnacle West APS	Arizona Public Service Company Deferred Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987 respectively	10.4 to APS’ 1988 Form 10-K Report, File No. 1-4473	3-8-89
10.2.1ab	Pinnacle West APS	Third Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993	10.3A to APS’ 1993 Form 10-K Report, File No. 1-4473	3-30-94
10.2.1bb	Pinnacle West APS	Fourth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective as of May 1, 1993	10.2 to APS’ September 30, 1994 Form 10-Q Report, File No. 1-4473	11-10-94

177

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
10.2.1cb	Pinnacle West APS	Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 1997	10.3A to APS’ 1996 Form 10-K Report, File No. 1-4473	3-28-97
10.2.1db	Pinnacle West APS	Sixth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 2001	10.8A to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962	3-14-01
10.2.2b	Pinnacle West APS	Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986	10.1 to APS’ June 30, 1986 Form 10-Q Report, File No. 1-4473	8-13-86
10.2.2ab	Pinnacle West APS	Second Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of January 1, 1993	10.2A to APS’ 1993 Form 10-K Report, File No. 1-4473	3-30-94
10.2.2bb	Pinnacle West APS	Third Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of May 1, 1993	10.1 to APS’ September 30, 1994 Form 10-Q Report, File No. 1-4473	11-10-94
10.2.2cb	Pinnacle West APS	Fourth Amendment to the Arizona Public Service Company Directors Deferred Compensation Plan, effective as of January 1, 1999	10.8A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

178

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit: a	Filed
10.2.3b	Pinnacle West APS	Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996	10.14A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.2.3ab	Pinnacle West APS	First Amendment dated December 7, 1999 to the Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans	10.15A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.2.4b	Pinnacle West APS	Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996	10.10A to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96
10.2.4ab	Pinnacle West APS	First Amendment effective as of January 1, 1999, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.7A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

179

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.2.4bb	Pinnacle West APS	Second Amendment effective January 1, 2000 to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.10A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.2.4cb	Pinnacle West APS	Third Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective as of January 1, 2002	10.3 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962	5-15-03
10.2.4db	Pinnacle West APS	Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective January 1, 2003	10.64 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.2.5b	Pinnacle West APS	Schedules of William J. Post and Jack E. Davis to Arizona Public Service Company Deferred Compensation Plan, as amended	10.3A to Pinnacle West 2002 Form 10-K Report, File No. 1-8962	3-31-03

180

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.2.6b	Pinnacle West APS	Deferred Compensation Plan of 2005 for Employees of Pinnacle West Capital Corporation and Affiliates
10.3.1b	Pinnacle West APS	Pinnacle West Capital Corporation Supplement Excess Benefit Retirement Plan, amended and restated as of January 1, 2003	10.7A to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04
10.3.1ab	Pinnacle West APS	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 18, 2003	10.48b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.3.2b	Pinnacle West APS	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan of 2005
10.4.1b	Pinnacle West APS	Letter Agreement dated December 21, 1993, between APS and William L. Stewart	10.6A to APS’ 1994 Form 10-K Report, File No. 1-4473	3-30-95
10.4.2b	Pinnacle West APS	Letter Agreement dated August 16, 1996 between APS and William L. Stewart	10.8 to APS’ 1996 Form 10-K Report, File No. 1-4473	3-28-97
10.4.3b	Pinnacle West APS	Letter Agreement dated October 3, 1997 between APS and William L. Stewart	10.2 to APS’ September 30, 1997 Form 10-Q Report, File No. 1-4473	11-12-97

181

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.4.4b	Pinnacle West APS	Letter Agreement dated December 13, 1999 between APS and William L. Stewart	10.9A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.4.4ab	Pinnacle West APS	Amendment to Letter Agreement, effective as of January 1, 2002, between APS and William L. Stewart	10.1 to Pinnacle West’s June 30, 2002 Form 10-Q Report, File No. 1-8962	8-13-02
10.4.5b	Pinnacle West APS	Letter Agreement dated June 28, 2001 between Pinnacle West Capital Corporation and Steve Wheeler	10.4A to Pinnacle West’s 2002 Form 10-K Report, File No. 1-8962	3-31-03
10.4.6b	APS	Letter Agreement dated December 20, 2006 between APS and Randall K. Edington	10.78 to Pinnacle West/APS 2006 Form 10-K Report, File Nos. 1-8962 and 1-4473	2-28-07
10.4.7b	APS	Letter Agreement dated July 22, 2008 between APS and Randall K. Edington	10.3 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-4473	8-07-08
10.4.8b	Pinnacle West APS	Letter Agreement dated June 17, 2008 between Pinnacle West/APS and James R. Hatfield	10.1 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-07-08
10.4.9b	APS	Description of 2008 Palo Verde Specific Compensation Opportunity for Randall K. Edington	10.7 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-4473	8-07-08
10.4.10b	APS	Supplemental Agreement dated December 26, 2008 between APS and Randall K. Edington

182

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.5.1bd	Pinnacle West APS	Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries	10.77 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.5.1abd	Pinnacle West APS	Form of Amended and Restated Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries	10.4 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473	11-5-07
10.5.2bd	Pinnacle West APS	Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries	10.3 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473	11-5-07
10.6.1b	Pinnacle West APS	Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan, effective as of March 23, 1994	Appendix A to the Proxy Statement for the Plan Report for Pinnacle West’s 1994 Annual Meeting of Shareholders, File No. 1-8962	4-15-94
10.6.1ab	Pinnacle West APS	First Amendment dated December 7, 1999 to the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan	10.12A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.6.2b	Pinnacle West APS	Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.5A to Pinnacle West’s 2002 Form 10-K Report	3-31-03

183

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.6.2abd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	12-15-05
10.6.2bbd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.1 to Pinnacle West/APS December 31, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	2-1-06
10.6.2cd	Pinnacle West APS	Performance Accelerated Stock Option Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.98 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.6.2dbd	Pinnacle West APS	Stock Ownership Incentive Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.99 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.6.2ebd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.91 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.6.3b	Pinnacle West	Pinnacle West Capital Corporation 2000 Director Equity Plan	99.1 to Pinnacle West’s Registration Statement on Form S-8 (No. 333-40796), File No. 1-8962)	7-3-00
10.6.4b	Pinnacle West	Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	Appendix B to the Proxy Statement for Pinnacle West’s 2007 Annual Meeting of Shareholders, File No. 1-8962	4-20-07

184

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.6.4ab	Pinnacle West	First Amendment to the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	10.2 to Pinnacle West/APS April 18, 2007 Form 8-K Report, File No. 1-8962	4-20-07
10.6.4bb	Pinnacle West	Description of Annual Stock Grants to Non-Employee Directors	10.1 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962	11-5-07
10.6.4cb	Pinnacle West	Description of Stock Grant to W. Douglas Parker	10.2 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962	11-5-07
10.6.4db	Pinnacle West	Description of Annual Stock Grants to Non-Employee Directors	10.2 to Pinnacle West/APS June 30, 2008 Form 10-Q Report, File No. 1-8962	8-07-08
10.6.5bd	Pinnacle West APS	Summary of 2009 CEO Variable Incentive Plan and Officer Variable Incentive Plan
10.7.1	Pinnacle West APS	Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant	5.01 to APS’ Form S-7 Registration Statement, File No. 2-59644	9-1-77
10.7.1a	Pinnacle West APS	Supplemental and Additional Indenture of Lease, including amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant	5.02 to APS’ Form S-7 Registration Statement, File No. 2-59644	9-1-77
10.7.1b	Pinnacle West APS	Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease Four Corners, dated April 25, 1985	10.36 to Pinnacle West’s Registration Statement on Form 8-B Report, File No. 1-8962	7-25-85

185

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.7.2	Pinnacle West APS	Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site	5.04 to APS’ Form S-7 Registration Statement, File No. 2-59644	9-1-77
10.7.2a	Pinnacle West APS	Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985	10.37 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962	7-25-85
10.7.3	Pinnacle West APS	Application and Grant of Arizona Public Service Company rights- of-way and easements, Four Corners Plant Site	5.05 to APS’ Form S-7 Registration Statement, File No. 2-59644	9-1-77
10.7.3a	Pinnacle West APS	Application and Amendment No. 1 to Grant of Arizona Public Service Company rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985	10.38 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962	7-25-85
10.7.4	Pinnacle West APS	Four Corners Project Co-Tenancy Agreement Amendment No. 6	10.7 to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962	3-14-01
10.8.1	Pinnacle West APS	Indenture of Lease, Navajo Units 1, 2, and 3	5(g) to APS’ Form S-7 Registration Statement, File No. 2-36505	3-23-70
10.8.2	Pinnacle West APS	Application of Grant of rights-of-way and easements, Navajo Plant	5(h) to APS Form S-7 Registration Statement, File No. 2-36505	3-23-70

186

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.8.3	Pinnacle West APS	Water Service Contract Assignment with the United States Department of Interior, Bureau of Reclamation, Navajo Plant	5(l) to APS’ Form S-7 Registration Statement, File No. 2-394442	3-16-71
10.8.4	Pinnacle West APS	Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996; Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998	10.107 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.8.5	Pinnacle West APS	Navajo Project Participation Agreement dated as of September 30, 1969, and Amendment and Supplement No. 1 dated as of January 16, 1970, and Coordinating Committee Agreement No. 1 dated as of September 30, 1971	10.108 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06

187

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.9.1	Pinnacle West APS	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto	10. 1 to APS’ 1988 Form 10-K Report, File No. 1-4473	3-8-89
10.9.1a	Pinnacle West APS	Amendment No. 13, dated as of April 22, 1991, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	10.1 to APS’ March 31, 1991 Form 10-Q Report, File No. 1-4473	5-15-91

188

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.9.1b	Pinnacle West APS	Amendment No. 14 to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	99.1 to Pinnacle West’s June 30, 2000 Form 10-Q Report, File No. 1-8962	8-14-00
10.10.1	Pinnacle West APS	Asset Purchase and Power Exchange Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991	10.1 to APS’ June 30, 1991 Form 10-Q Report, File No. 1-4473	8-8-91
10.10.2	Pinnacle West APS	Long-Term Power Transaction Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8, 1991	10.2 to APS’ June 30, 1991 Form 10-Q Report, File No. 1-4473	8-8-91

189

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.10.2a	Pinnacle West APS	Amendment No. 1 dated April 5, 1995 to the Long-Term Power Transaction Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and APS	10.3 to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96
10.10.3	Pinnacle West APS	Restated Transmission Agreement between PacifiCorp and APS dated April 5, 1995	10.4 to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96
10.10.4	Pinnacle West APS	Contract among PacifiCorp, APS and United States Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995	10.5 to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96
10.10.5	Pinnacle West APS	Reciprocal Transmission Service Agreement between APS and PacifiCorp dated as of March 2, 1994	10.6 to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96
10.11.1	Pinnacle West APS	Amended and Restated Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, as Administrative Agent and Issuing Bank, dated as of July 22, 2002	10.100 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05

190

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.11.2	Pinnacle West APS	Three-Year Credit Agreement dated as of May 21, 2004 between APS as Borrower, and the banks, financial institutions and other institutional lenders and initial issuing banks listed on the signature pages thereof	10.101 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.11.3	Pinnacle West APS	Amended and Restated Five-Year Credit Agreement dated as of December 9, 2005 between APS, as Borrower, Citibank, N.A., as Agent, and the lenders and other parties thereto	10.95 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.11.4	Pinnacle West	$200,000,000 Senior Notes Uncommitted Master Shelf Agreement dated as of February 28, 2006	10.96 to Pinnacle West 2005 Form 10-K Report, File No. 1-8962	3-13-06
10.11.5	Pinnacle West	Amended and Restated Credit Agreement dated as of December 9, 2005 among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Agent, and the other agent parties thereto	10.97 to Pinnacle West 2005 Form 10-K Report, File No. 1-8962	3-13-06

191

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.11.5a	Pinnacle West	First Amendment to Amended and Restated Credit Agreement, dated as of May 15, 2006, supplementing and amending the Amended and Restated Credit Agreement, dated as of December 9, 2005, among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A. as Agent and the other parties thereto	10.1 to Pinnacle West’s June 30, 2006 Form 10-Q Report, File No. 1-8962	8-8-06
10.11.6	Pinnacle West APS	Credit Agreement dated as of October 19, 2004 among Pinnacle West, other lenders, and JPMorgan Chase Bank, as Administrative Agent	10.1 to Pinnacle West’s September 30, 2004 Form 10-Q Report, File No. 1-8962	11-8-04
10.11.7	APS	$500,000,000 Five-Year Credit Agreement dated as of September 28, 2006 among Arizona Public Service Company as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, The Bank of New York as Syndication Agent and Issuing Bank and the other parties thereto	10.1 to APS’ September 2006 Form 10-Q Report, File No. 1-4473	11-8-06

192

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.11.8	Pinnacle West APS	Amended and Restated Reimbursement Agreement among Arizona Public Service Company, The Banks party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and Barclays Bank PLC, as Syndication Agent, dated as of May 19, 2005	99.6 to PinnacleWest/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-9-05
10.12.1c	Pinnacle West APS	Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	4.3 to APS’ Form S-3 Registration Statement, File No. 33-9480	10-24-86
10.12.1ac	Pinnacle West APS	Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	10.5 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	12-4-86

193

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.12.1bc	Pinnacle West APS	Amendment No. 2 dated as of June 1, 1987 to Facility Lease dated as of August 1, 1986 between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.3 to APS’ 1988 Form 10-K Report, File No. 1-4473	3-8-89
10.12.1cc	Pinnacle West APS	Amendment No. 3, dated as of March 17, 1993, to Facility Lease, dated as of August 1, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.3 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
10.12.2	Pinnacle West APS	Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	10.1 to APS’ November 18, 1986 Form 8-K Report, File No. 1-4473	1-20-87

194

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.12.2a	Pinnacle West APS	Amendment No. 1, dated as of August 1, 1987, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	4.13 to APS’ Form S-3 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473	8-24-87
10.12.2b	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Facility Lease, dated as of December 15, 1986, between U.S. Bank National Association, successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.4 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
10.13.1	Pinnacle West APS	Agreement No. 13904 (Option and Purchase of Effluent) with Cities of Phoenix, Glendale, Mesa, Scottsdale, Tempe, Town of Youngtown, and Salt River Project Agricultural Improvement and Power District, dated April 23, 1973	10.3 to APS’ 1991 Form 10-K Report, File No. 1-4473	3-19-92

195

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.13.2	Pinnacle West APS	Agreement between Pinnacle West Energy Corporation and Arizona Public Service Company for Transportation and Treatment of Effluent by and between Pinnacle West Energy Corporation and APS dated as of the 10th day of April, 2001	10.102 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.13.3	Pinnacle West APS	Agreement for the Transfer and Use of Wastewater and Effluent by and between APS, SRP and PWE dated June 1, 2001	10.103 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.13.4	Pinnacle West APS	Agreement for the Sale and Purchase of Wastewater Effluent dated November 13, 2000, by and between the City of Tolleson, Arizona, APS and SRP	10.104 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.13.5	Pinnacle West APS	Operating Agreement for the Co-Ownership of Wastewater Effluent dated November 16, 2000 by and between APS and SRP	10.105 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05

196

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.13.6	Pinnacle West APS	Agreement for the Sale and Purchase of Wastewater Effluent with City of Tolleson and Salt River Agricultural Improvement and Power District, dated June 12, 1981, including Amendment No. 1 dated as of November 12, 1981 and Amendment No. 2 dated as of June 4, 1986	10.4 to APS’ 1991 Form 10-K Report, File 1-4473	3-19-92
10.14.1	Pinnacle West APS	Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high-level radioactive waste, ANPP	10.31 to Pinnacle West’s Form S-14 Registration Statement, File No. 2-96386	3-13-85
10.15.1	Pinnacle West APS	Territorial Agreement between APS and Salt River Project	10.1 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473	5-15-98
10.15.2	Pinnacle West APS	Power Coordination Agreement between APS and Salt River Project	10.2 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473	5-15-98
10.15.3	Pinnacle West APS	Memorandum of Agreement between APS and Salt River Project	10.3 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473	5-15-98
10.15.3a	Pinnacle West APS	Addendum to Memorandum of Agreement between APS and Salt River Project dated as of May 19, 1998	10.2 to APS’ May 19, 1998 Form 8-K Report, File No. 1-4473	6-26-98
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges

197

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
21.1	Pinnacle West	Subsidiaries of Pinnacle West
23.1	Pinnacle West	Consent of Deloitte & Touche LLP
23.2	APS	Consent of Deloitte & Touche LLP
31.1	Pinnacle West	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of James R. Hatfield, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3	APS	Certificate of Donald E. Brandt, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

198

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
31.4	APS	Certificate of James R. Hatfield, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Pinnacle West APS	Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	4.2 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.1a	Pinnacle West APS	Supplemental Indenture to Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	4.3 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93

199

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
99.2c	Pinnacle West	Participation	28.1 to APS’ September 30, 1992 Form	11-9-92
	APS	Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	10-Q Report, File No. 1-4473
99.2ac	Pinnacle West APS	Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	10.8 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8, File No. 1-4473	12-4-86

200

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
99.2bc	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	28.4 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.3c	Pinnacle West APS	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.5 to APS’ Form S-3 Registration Statement, File No. 33-9480	10-24-86

201

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
99.3ac	Pinnacle West APS	Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	10.6 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	12-4-86
99.3bc	Pinnacle West APS	Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee	4.4 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.4c	Pinnacle West APS	Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.3 to APS’ Form S-3 Registration Statement, File No. 33-9480	10-24-86

202

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
99.4ac	Pinnacle West APS	Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	10.10 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8, File No. 1-4473	12-4-86
99.4bc	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.6 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.5	Pinnacle West APS	Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Report Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, APS, and the Owner Participant named therein	28.2 to APS’ September 30, 1992 Form 10-Q Report, File No. 1-4473	11-9-92

203

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
99.5a	Pinnacle West APS	Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, APS, and the Owner Participant named therein	28.20 to APS’ Form S-3 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473	8-10-87
99.5b	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Owner Participant named therein	28.5 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93

204

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
99.6	Pinnacle West APS	Trust Indenture, Mortgage Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	10.2 to APS’ November 18, 1986 Form 10-K Report, File No. 1-4473	1-20-87
99.6a	Pinnacle West APS	Supplemental Indenture No. 1, dated as of August 1, 1987, to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.13 to APS’ Form S-3 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473	8-24-87

205

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
99.6b	Pinnacle West APS	Supplemental Indenture No. 2 to Trust Indenture Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee	4.5 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.7	Pinnacle West APS	Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	10.5 to APS’ November 18, 1986 Form 8-K Report, File No. 1-4473	1-20-87
99.7a	Pinnacle West APS	Amendment No. 1, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.7 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.8c	Pinnacle West APS	Indemnity Agreement dated as of March 17, 1993 by APS	28.3 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93

206

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
99.9	Pinnacle West APS	Extension Letter, dated as of August 13, 1987, from the signatories of the Participation Agreement to Chemical Bank	28.20 to APS’ Form S-3 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473	8-10-87
99.10	Pinnacle West APS	Arizona Corporation Commission Order, Decision No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules	10.2 to APS’ September 30, 1999 Form 10-Q Report, File No. 1-4473	11-15-99
99.11	Pinnacle West	Purchase Agreement by and among Pinnacle West Energy Corporation and GenWest, L.L.C. and Nevada Power Company, dated June 21, 2005	99.5 to Pinnacle West/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-9-05

a	Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.
b	Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K.
c	An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.
d	Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.

207

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 20, 2009	PINNACLE WEST CAPITAL CORPORATION                                (Registrant)
	/s/ William J. Post
	(William J. Post, Chairman of the
	Board of Directors and Chief Executive Officer)

Power of Attorney

     We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint James R. Hatfield, Chris N. Froggatt and Nancy C. Loftin, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ William J. Post(William J. Post, Chairman of the Board of Directors and Chief Executive Officer)	Principal Executive Officer and Director	February 20, 2009
/s/ James R. Hatfield(James R. Hatfield, Senior Vice President and Chief Financial Officer)	Principal Financial Officer and Principal Accounting Officer	February 20, 2009

208

Signature	Title	Date
/s/ Edward N. Basha, Jr.(Edward N. Basha, Jr.)	Director	February 20, 2009
/s/ Donald E. Brandt(Donald E. Brandt)	Director	February 20, 2009
/s/ Susan Clark-Johnson(Susan Clark-Johnson)	Director	February 20, 2009
/s/ Michael L. Gallagher(Michael L. Gallagher)	Director	February 20, 2009
/s/ Pamela Grant(Pamela Grant)	Director	February 20, 2009
/s/ Roy A. Herberger, Jr.(Roy A. Herberger, Jr.)	Director	February 20, 2009
/s/ William S. Jamieson(William S. Jamieson)	Director	February 20, 2009
/s/ Humberto S. Lopez(Humberto S. Lopez)	Director	February 20, 2009
/s/ Kathryn L. Munro(Kathryn L. Munro)	Director	February 20, 2009
/s/ Bruce J. Nordstrom(Bruce J. Nordstrom)	Director	February 20, 2009
/s/ W. Douglas Parker(W. Douglas Parker)	Director	February 20, 2009
/s/ William L. Stewart(William L. Stewart)	Director	February 20, 2009

209

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ARIZONA PUBLIC SERVICE COMPANY                             (Registrant)
Date: February 20, 2009	/s/ Donald E. Brandt
	(Donald E. Brandt, Chief Executive Officer)

Power of Attorney

     We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint James R. Hatfield, Chris N. Froggatt and Nancy C. Loftin, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ William J. Post(William J. Post, Chairman of the Board of Directors)	Director	February 20, 2009
/s/ Donald E. Brandt(Donald E. Brandt, Chief Executive Officer)	Principal Executive Officer	February 20, 2009
/s/ James R. Hatfield(James R. Hatfield, Senior Vice President and Chief Financial Officer)	Principal Financial Officer and Principal Accounting Officer	February 20, 2009

210

Signature	Title	Date
/s/ Edward N. Basha, Jr.(Edward N. Basha, Jr.)	Director	February 20, 2009
/s/ Donald E. Brandt(Donald E. Brandt)	Director	February 20, 2009
/s/ Susan Clark-Johnson(Susan Clark-Johnson)	Director	February 20, 2009
/s/ Michael L. Gallagher(Michael L. Gallagher)	Director	February 20, 2009
/s/ Pamela Grant(Pamela Grant)	Director	February 20, 2009
/s/ Roy A. Herberger, Jr.(Roy A. Herberger, Jr.)	Director	February 20, 2009
/s/ William S. Jamieson(William S. Jamieson)	Director	February 20, 2009
/s/ Humberto S. Lopez(Humberto S. Lopez)	Director	February 20, 2009
/s/ Kathryn L. Munro(Kathryn L. Munro)	Director	February 20, 2009
/s/ Bruce J. Nordstrom(Bruce J. Nordstrom)	Director	February 20, 2009
/s/ W. Douglas Parker(W. Douglas Parker)	Director	February 20, 2009
/s/ William L. Stewart(William L. Stewart)	Director	February 20, 2009

211