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

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 Yes þ No o

ARIZONA PUBLIC SERVICE COMPANY Yes þ No o

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 Yes o No þ

ARIZONA PUBLIC SERVICE COMPANY Yes o No þ

     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 Yes þ No o

ARIZONA PUBLIC SERVICE COMPANY Yes þ No o

     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 filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o
				(Do not check if a smaller reporting company)
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o
				(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). Yes o No þ

     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) of Form 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

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

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

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.

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:

	•		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;

	•		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.

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.

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

     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.

     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.

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,

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.

				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

     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

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.

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

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 Rules On 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

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.

     Mercury On 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

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 Plan In 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.

     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.

     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 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 Sites APS 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

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

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.

     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.

     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

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.

     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.

     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

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

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.

     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;

	•		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.

     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

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.

     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

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.

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.

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.

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.

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

     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

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).

     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).

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.

     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				—				—

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

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

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.

     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

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):

		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:

	•		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):

		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	)

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):

		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:

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

     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

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

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.

     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,

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

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

     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):

						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

     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.

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):

		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

     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

     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

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

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.

FACTORS AFFECTING OUR FINANCIAL OUTLOOK

Factors Affecting Operating Revenues, Fuel and Purchased Power Costs

     General Electric 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 Proceedings Our 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 Costs Fuel 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 Growth The 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).

     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.

     Weather In 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 Market Our 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 Expenses Operations 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 Expenses Depreciation 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 Taxes Taxes 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 Expense Interest 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 Change Recent 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.

     Retail Competition Although 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.

     Subsidiaries 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. 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.

     General Our 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):

										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