Pinnacle West Capital (PNW) 10-K 2005 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2005

OR

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

For the transition period from                    to                    

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

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	Pacific Stock Exchange
ARIZONA PUBLIC SERVICE COMPANY	None	None

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

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

PINNACLE WEST CAPITAL CORPORATION            Yesþ           Noo

ARIZONA PUBLIC SERVICE COMPANY                      Yeso           Noþ

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

PINNACLE WEST CAPITAL CORPORATION            Yeso           Noþ

ARIZONA PUBLIC SERVICE COMPANY                      Yesþ           Noo

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

PINNACLE WEST CAPITAL CORPORATION            Yesþ           Noo

ARIZONA PUBLIC SERVICE COMPANY                      Yesþ           Noo

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

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.

PINNACLE WEST CAPITAL CORPORATION

     Large accelerated filerþ           Accelerated filero          Non-accelerated filero

ARIZONA PUBLIC SERVICE COMPANY

     Large accelerated filero           Accelerated filero           Non-accelerated filerþ

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

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

PINNACLE WEST CAPITAL CORPORATION $4,359,721,018. as of June 30, 2005

ARIZONA PUBLIC SERVICE COMPANY        $0 as of June 30, 2005

     The number of shares outstanding of each registrant’s common stock as of March 7, 2006

PINNACLE WEST CAPITAL CORPORATION	99,166,990 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 17, 2006 are incorporated by reference into Part III hereof.

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

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

TABLE OF CONTENTS

			Page
GLOSSARY				1
PART I				3
	Item 1.	Business		3
	Item 1A.	Risk Factors		16
	Item 1B.	Unresolved Staff Comments		22
	Item 2.	Properties		23
	Item 3.	Legal Proceedings		28
	Item 4.	Submission of Matters to a Vote of Security Holders		28
	Supplemental Item
		Executive Officers of Pinnacle West		29
PART II				31
	Item 5.	Market for Registrants’ Common Equity, Pinnacle West Related Stockholder Matters and Issuer Purchases of Equity Securities		31
	Item 6.	Selected Financial Data		32
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		65
	Item 8.	Financial Statements and Supplementary Data		66
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		145
	Item 9A.	Controls and Procedures		145
	Item 9B.	Other Information		146
PART III				146
	Item 10.	Directors and Executive Officers of Pinnacle West		146
	Item 11.	Executive Compensation		146
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		146
	Item 13.	Certain Relationships and Related Transactions		149
	Item 14.	Principal Accountant Fees and Services		149
PART IV				150
	Item 15.	Exhibits and Financial Statement Schedules		150
SIGNATURES				190
Exhibit 10.48b
Exhibit 10.64b
Exhibit 10.77bd
Exhibit 10.91bd
Exhibit 10.92bd
Exhibit 10.95
Exhibit 10.96
Exhibit 10.97
Exhibit 10.107
Exhibit 10.108
Exhibit 12.1
Exhibit 12.2
Exhibit 12.3
Exhibit 21.1
Exhibit 23.1
Exhibit 23.2
Exhibit 31.1
Exhibit 31.2
Exhibit 31.3
Exhibit 31.4
Exhibit 32.1
Exhibit 32.2
EX-99.29
EX-99.30

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GLOSSARY

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

AFUDC – Allowance for Funds Used During Construction

ALJ – Administrative Law Judge

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

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

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

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

Financing Order – ACC Order that authorized APS’ $500 million loan to Pinnacle West Energy in May 2003

FIP – Federal Implementation Plan

Four Corners – Four Corners Power Plant

FSP – FASB Staff Position

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-hours, one million watts per hour

NAC – collectively, NAC Holding Inc. and NAC International Inc., subsidiaries of El Dorado that were sold in November 2004

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

NPC – Nevada Power Company

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

Off-System Sales – sales of electricity from generation owned 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, also known as ANPP

Pinnacle West – Pinnacle West Capital Corporation, the Company

Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company

PPL Sundance – PPL Sundance Energy, LLC

PRP – potentially responsible parties under the Superfund Act

PSA – power supply adjustor

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

PX – California Power Exchange

RFP – request for proposals

RTO – regional transmission organization

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

SEC – United States Securities and Exchange Commission

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

Sundance Plant – 420 megawatt generating facility located approximately 55 miles southeast of Phoenix, Arizona

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

Trading – energy-related activities entered into with the objective of generating profits on changes in market prices

2004 Settlement Agreement – an agreement proposing terms under which APS’ general rate case was settled, as approved by the ACC in 2005

VIE – variable-interest entity

WestConnect – WestConnect RTO, LLC, a proposed RTO to be formed by owners of electric transmission lines in the southwestern United States

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INTRODUCTION

Filing Format

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

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

• Pinnacle West Consolidated—This section describes the financial condition and results of operations of Pinnacle West and its subsidiaries on a consolidated basis. It includes discussions of Pinnacle West’s regulated utility and non-utility operations. A substantial part of Pinnacle West’s revenues and earnings are 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 relate 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 significant subsidiaries are SunCor, which is engaged in real estate development and investment activities, and APS Energy Services, which provides competitive energy services and products in the western United States. 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 owns any generating plants and has ceased operations. Each of these subsidiaries, and El Dorado Investment Company, another subsidiary, are discussed in greater detail below. See “Business of SunCor Development Company,” “Business of APS Energy Services

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Company, Inc.,” “Business of Pinnacle West Energy Corporation,” and “Business of El Dorado Investment Company,” in this Item 1.

Business Segments

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

• the regulated electricity segment (75% of operating revenues in 2005), 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;

• the real estate segment (11% of operating revenues in 2005), which consists of SunCor’s real estate development and investment activities; and

• the marketing and trading segment (12% of operating revenues in 2005), which consists of competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services.

          See Note 17 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for financial information about the business segments.

APS Rate Proceedings

          The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8, APS has pending before the ACC a general retail rate case, an application for an emergency interim rate increase, and an application for two separate surcharges under the PSA.

Employees

          At December 31, 2005, Pinnacle West employed approximately 7,300 people, including the employees of its subsidiaries. Of these employees, approximately 6,400 were employees of APS, including employees at jointly-owned generating facilities (approximately 3,000 employees) for which APS serves as the generating facility manager. Approximately 900 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 internet site, (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.

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          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 and Operating Committee and Human Resources Committee;

• Code of Ethics for Financial Professionals; and

• Ethics Policy and Standards of Business Practices.

          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 internet site. The information on Pinnacle West’s internet site 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 and timing of APS’ retail rate proceedings pending before the ACC;

• the timely recovery of PSA deferrals;

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

• the outcome of regulatory, legislative and judicial proceedings, both current and future, relating to the restructuring;

• market prices for electricity and natural gas;

• power plant performance and outages;

• transmission outages and constraints;

• weather variations affecting local and regional customer energy usage;

• customer growth and energy usage;

• regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile fuel and

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	purchased power costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;
•	the cost of debt and equity capital and access to capital markets;
•	current credit ratings remaining in effect for any given period of time;
•	our ability to compete successfully outside traditional regulated markets (including the wholesale market);
•	the performance of our marketing and trading activities due to volatile market liquidity and 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 and the interpretation of those principles;
•	the performance of the stock market and the changing interest rate environment, which affect the amount of required contributions to Pinnacle West’s pension plan and APS’ nuclear decommissioning trust funds, as well as the reported costs of providing pension and other postretirement benefits;
•	technological developments in the electric industry;
•	the strength of 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 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.

          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 unconstitutional, 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. In 2005, the Arizona Supreme Court declined to review the Court of Appeals decision. To date, the ACC has taken no action on either the rules or the orders authorizing competitive electric service providers in response to the final Court of Appeals decision. As a result, 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.

          APS is subject to varying degrees of competition from other investor-owned utilities in Arizona (such as Tucson Electric Power Company and Southwest Gas Corporation) as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit

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organizations (principally Salt River Project). APS also faces competition from low-cost, hydroelectric power and parties that have access to low-priced preferential, federal power and other governmental subsidies. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet their own energy requirements.

Wholesale

          General

          The FERC regulates rates for wholesale power sales and transmission services. During 2005, approximately 5.3% of APS’ electric operating revenues resulted from such sales and services. APS’ marketing and trading division focuses primarily on managing APS’ fuel and purchased power risks in connection with its costs of serving retail customer energy requirements. The division also sells, in the wholesale market, APS’ 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, the marketing and trading division, subject to specified parameters, markets, hedges and trades principally in electricity and fuels.

          Regional Transmission Organizations

          In a December 1999 order, the FERC established characteristics and functions that must be met by utilities in forming and operating RTOs. The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to support efficient and non-discriminatory markets and exclusive authority to maintain short-term reliability. On October 16, 2001, APS and other owners of electric transmission lines in the southwestern U.S. filed with the FERC a request for a declaratory order confirming that their proposal to form WestConnect RTO, LLC would satisfy the FERC’s requirements for the formation of an RTO. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if modified to address specified issues, could meet the FERC’s RTO requirements and provide the basic framework for a standard market design for the southwestern United States. Since that time, APS and other supporters of the WestConnect efforts have been evaluating a phased approach to RTO implementation of regional structures in the desert Southwest.

BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY

General

          APS was incorporated in 1920 under the laws of the state of Arizona and currently has approximately 1,033,500 customers. APS does not distribute any products. During 2005, no single purchaser or user of energy (other than Pinnacle West) accounted for more than 7.5% of electric revenues. See “Overview – General” and “Regulation and Competition” above for additional background information about APS’ business.

          At December 31, 2005, APS employed approximately 6,400 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).

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Purchased Power and Generating Fuel

          See “Properties – Capacity” in Item 2 for information about APS’ power plants by fuel types.

          2005 Energy Mix

          APS’ sources of energy during 2005 were: purchased power – 51.8%; coal – 26.3%; nuclear – 15.1%; and gas – 6.8%. In accordance with GAAP, a substantial portion of our purchased power contracts was netted against wholesale sales contracts on the Statements of Income. See Note 18 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.

          Coal Supply

          ChollaCholla is a coal-fired power plant located in northeastern Arizona. It is a jointly-owned facility operated by APS. APS purchases most of Cholla’s coal requirements from coal suppliers that mine all of the coal under a long-term lease of coal reserves with the Navajo Nation, the federal government and private landholders. 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.

          Four CornersFour Corners is a coal-fired power plant located in the northwestern corner of New Mexico. It is a jointly-owned facility operated by APS. 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 July 2016, with options to extend the contract for five to fifteen additional years beyond the current plant site lease expiration in 2017.

          Navajo Generating StationThe Navajo Generating Station is a coal-fired power plant located in northern Arizona. It is a jointly-owned facility operated by Salt River Project. 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 the current plant site lease expiration in 2019. The Navajo Generating Station lease waives certain taxes through the lease expiration in 2019. Items that may impact the fuel price include lease provisions that allow for a renegotiation of the coal royalty in 2007 and 2017 and a fuel contract requirement for a five-year price review in 2007. In addition, the December 31, 2005 closure of the Mohave Generating Station has not had a significant impact on the cost structure for the Black Mesa – Kayenta Mine complex. APS does not have an ownership interest in the Mohave Generating Station, but understands the plant could be restarted. However, if the Mohave Generating Station is permanently closed, there is a potential for increased costs to the Navajo Generating Station, which is served by the Kayenta Mine. APS does not currently expect this matter to have a material adverse effect on its financial position, results of operations, cash flows or liquidity.

          See “Legal Proceedings” in Item 3 for information about a lawsuit relating to royalties for coal paid by the participants at the Navajo Generating Station.

          See “Properties – Capacity” in Item 2 for information about APS’ ownership interests in Cholla, Four Corners and the Navajo Generating Station. See Note 11 of Notes to Pinnacle West’s

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Consolidated Financial Statements in Item 8 for information regarding APS’ coal mine reclamation obligations.

          Natural Gas Supply

          See Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of APS’ natural gas supply.

          Nuclear Fuel Supply

          Palo Verde Fuel CyclePalo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. It is a jointly-owned facility operated by APS. 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 have contracted for all of Palo Verde’s requirements for uranium concentrates and conversion services through 2008. The Palo Verde participants have also contracted for all of Palo Verde’s enrichment services through 2010, 80% of enrichment services through 2013, and all of Palo Verde’s fuel assembly fabrication services until at least 2015.

          Spent Nuclear Fuel and Waste DisposalSee “Palo Verde Nuclear Generating Station” in Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of spent nuclear fuel and waste disposal.

          Purchased Power

          In addition to its own available generating capacity (see “Properties” in Item 2), APS purchases electricity under various arrangements. One of the most important of these is a long-term contract with Salt River Project. The amount of electricity available to APS is based in large part on customer demand within certain areas now served by APS pursuant to a related territorial agreement. The generating capacity available to APS pursuant to the contract is 350 MW. In 2005, APS received 552,014 MWh of energy under the contract and paid about $66.6 million for capacity availability and energy received. This contract may be canceled by Salt River Project on three years’ notice. By letter dated June 7, 2004, Salt River Project gave notice to APS to reduce capacity by 150 MW effective June 16, 2007. To date, this letter is the only notice Salt River Project has given under the contract. APS may also cancel the contract on five years’ notice, which may be given no earlier than December 31, 2006.

          In September 1990, APS entered into a thirty-year seasonal capacity exchange agreement with PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and APS returns electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW

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of capacity and a related amount of energy available to it under the agreement for its respective seasons. In 2005, APS received 571,492 MWh of energy under the capacity exchange. APS must also make additional offers of energy to PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2005, PacifiCorp received offers of 1,090,700 MWh and purchased 372,473 MWh.

          APS continually assesses its need for additional capacity resources to assure system reliability. Under the terms of the 2004 Settlement Agreement, APS committed to seek proposals from the competitive wholesale market for filling its future resource needs. The current reliability RFP identifies the amount of capacity and energy needed to reliably meet expected customer demands and sought proposals for at least 1,000 MW of new generating capacity for 2007 and beyond. APS has entered into contracts for more than 650 MW of capacity and expects to finalize the remaining contract by the end of the first quarter of 2006.

          APS also has a renewable RFP seeking at least 100 MW of renewable capacity with a capability of producing at least 250,000 MWh annually. In accordance with the terms of the 2004 Settlement Agreement, power must be deliverable to the APS transmission system and its pricing must not exceed 125% of conventional resource alternatives. During 2005, APS conducted a competitive procurement process for renewable energy resources. The process resulted in the acquisition of approximately 145 MW of renewable energy resources via purchased power agreements. At an ACC Open Meeting on November 8, 2005, the ACC approved APS’ acquisition of out-of-state renewable resources. The ACC also ordered APS to work with the ACC staff to evaluate two in-state projects and report back within two months. APS has completed this evaluation process and has filed a report with the ACC. The ACC agreed with APS’ evaluation that the in-state projects were not economical.

Construction Program

          During the years 2003 through 2005, APS incurred approximately $1.7 billion in capital expenditures. APS’ capital expenditures for the years 2006 through 2008 are expected to be primarily for expanding transmission and distribution capabilities to meet growing customer needs, for upgrading existing utility property and for environmental purposes. APS’ capital expenditures were approximately $809 million in 2005. APS’ capital expenditures, including expenditures for environmental control facilities, for the years 2006 through 2008, net of contributions in aid of construction, have been estimated as follows (dollars in millions):

	Estimate
Major facilities:	2006		2007		2008
Distribution	$	322	$	323	$	362
Transmission		120		169		203
Generation		184		207		279
Other		23		16		13
Total	$	649	$	715	$	857

          The above amounts exclude capitalized interest costs and include capitalized property taxes and approximately $35 million per year for nuclear fuel. APS conducts a continuing review of its construction program.

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          See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Needs and Resources by Company” in Item 7 for additional information about APS’ construction programs.

Environmental Matters

          EPA Environmental Regulation

          Regional Haze RulesOn April 22, 1999, the EPA announced final regional haze rules. These regulations require states to submit state implementation plans by 2008 to make reasonable progress towards achieving natural visibility conditions in certain specified areas, including Class I Areas in the Colorado Plateau, and to consider and potentially apply the best available retrofit technology (“BART”) for major stationary sources.

          The rules allow nine western states and tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule. Five western states, including Arizona, have submitted proposed state implementation plans to the EPA to implement the Annex Rule.

          On February 18, 2005, the U.S. Court of Appeals for the District of Columbia granted a petition for review of the Annex Rule, filed by the Center for Energy and Economic Development (CEED). APS, Phelps Dodge Corporation, and the Environmental Defense were intervenors in the litigation in support of the EPA and the Annex Rule. Although the Court concluded that the EPA has the authority to promulgate a BART alternative, the Court ruled that the EPA must first conduct a BART analysis of eligible sources to demonstrate that the alternate plan would achieve greater emissions reductions than BART. On June 15, 2005, 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. On August 1, 2005, the EPA proposed a rule to, among other things, reconcile the Annex Rule with the CEED decision. We are currently evaluating the impact of this proposed rule. The Company cannot currently predict the outcome of this matter.

          MercuryOn March 15, 2005, the EPA issued the Clean Air Mercury Rule to regulate 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 trading program. Under the trading program, the EPA has assigned each state a “budget” for reducing coal-fired power plant mercury emissions, and each state must submit to the EPA a plan detailing how it will meet its “budget.” In the first phase of the program, beginning in 2010, mercury emissions will be reduced from a total of 48 tons per year to 38 tons. In 2018, mercury emissions will be further reduced to 15 tons. APS is currently evaluating the potential impact of this rule and, as a result, cannot currently estimate the expenditures which may be required.

          By November 2006, the ADEQ will submit a state implementation plan to the EPA to implement the Clean Air Mercury Rule or an alternative mercury program, as authorized by the EPA. The mercury program for Four Corners will be implemented by EPA Region IX or, if it seeks and obtains program approval, by the Navajo Nation. APS is still evaluating the potential impacts of the state implementation plan on Cholla and of the Clean Air Mercury Rule on Cholla and Four Corners and cannot currently estimate the expenditures which may be required.

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          Federal Implementation PlanIn September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and Four Corners. The FIP is similar to current Arizona regulation of the Navajo Generating Station and New Mexico regulation of Four Corners, with minor modifications. APS does not currently expect the FIP to have a material adverse effect on its financial position, results of operations, cash flows or liquidity.

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

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

          Navajo Nation Environmental Issues

          Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. APS is the Four Corners operating agent. APS owns all of Four Corners Units 1, 2 and 3, and a 15% interest in Four Corners Units 4 and 5. APS owns a 14% interest in Navajo Generating Station Units 1, 2 and 3.

          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.

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          On May 18, 2005, APS, Salt River Project and the Navajo Nation executed a Voluntary Compliance Agreement (“VCA”) to resolve their disputes regarding the Navajo Nation Air Pollution Prevention and Control Act. The fundamental premise of the VCA is that the Navajo Nation EPA may regulate air issues for Four Corners and the Navajo Generating Station only because the participants have agreed to submit to such regulation for the term of the agreement and under certain circumstances. If the EPA approves the Navajo Nation’s air programs consistent with the VCA, APS would seek dismissal of the pending litigation in the Navajo Nation Supreme Court and the pending litigation in the Navajo Nation District Court to the extent the claims relate to the Clean Air Act. The agreement does not address or resolve any dispute relating to other Navajo Acts. APS cannot currently predict the outcome of this matter.

          West Phoenix Power Plant

          During the period from November 2004 through March 2005, the Maricopa County Air Quality Department (“MCAQD”) issued a series of Notices of Violation (“NOVs”) to APS’ West Phoenix Power Plant that generally allege that the plant failed to comply with applicable permit requirements. APS is currently engaged in discussions with MCAQD concerning the NOVs. We do not expect the resolution of these matters to have a material adverse effect on our financial position, results of operations, or cash flows.

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 before a state 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 Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As project manager 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

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interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Court has not yet ruled on the petition. 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. APS’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore 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, neither APS nor Pinnacle West expects 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 operations of the plant for 2006 and later years. 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.

Federal Energy Legislation

          On August 8, 2005, the President signed the Energy Policy Act of 2005 into law. The Company does not expect the Act to materially affect its operations.

BUSINESS OF SUNCOR DEVELOPMENT COMPANY

          SunCor was incorporated in 1965 under the laws of the State 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 700 employees at December 31, 2005.

          At December 31, 2005, SunCor had total assets of about $487 million. SunCor’s assets consist primarily of land with improvements, commercial buildings, golf courses and other real estate investments. SunCor intends to continue its focus on real estate development of master-planned communities, mixed-use residential, commercial, office and industrial projects. During the past several years, SunCor has focused its business strategy on real estate development and investment activities.

          SunCor projects under development include five master-planned communities and several commercial and residential projects. The commercial and residential projects and two of the master-planned communities are in Arizona. Other master-planned communities are located near St. George, Utah, Boise, Idaho and Santa Fe, New Mexico.

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          SunCor’s operating revenues were approximately $338 million in 2005, $350 million in 2004 and $362 million in 2003. SunCor’s net income was approximately $56 million in 2005, $45 million in 2004 and $56 million in 2003. 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 Note 22 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.

          See Note 6 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for information regarding SunCor’s long-term debt and “Liquidity and Capital Resources” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of SunCor’s capital requirements.

BUSINESS OF PINNACLE WEST ENERGY CORPORATION

          Pinnacle West Energy was incorporated in 1999 under the laws of the State of Arizona and was formerly engaged principally in the operation of unregulated generating plants. Pinnacle West Energy had approximately 30 employees as of December 31, 2005. Pinnacle West Energy’s principal offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-4145).

          Pinnacle West Energy transferred the PWEC Dedicated Assets to APS on July 29, 2005 and sold its 75% interest in Silverhawk to NPC on January 10, 2006. As a result Pinnacle West Energy no longer owns any generating plants and has ceased operations. At December 31, 2005, Pinnacle West Energy had total assets of $217 million, substantially all of which were assets held for sale related to Silverhawk.

BUSINESS OF APS ENERGY SERVICES COMPANY, INC.

          APS Energy Services was incorporated in 1998 under the laws of the State of Arizona and provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in the western United States. APS Energy Services had approximately 80 employees as of December 31, 2005. APS Energy Services’ principal offices are located at 400 East Van Buren Street, Phoenix, Arizona 85004 (telephone 602-250-5000).

          APS Energy Services had a net loss of $6 million in 2005, and net income of $3 million in 2004 and $16 million in 2003. At December 31, 2005, APS Energy Services had total assets of $88 million.

BUSINESS OF EL DORADO INVESTMENT COMPANY

          El Dorado was incorporated in 1983 under the laws of the State 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

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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 pretax income of $4 million in 2005, $40 million in 2004 and $7 million in 2003. Income taxes related to El Dorado are recorded by Pinnacle West. At December 31, 2005, El Dorado had total assets of $38 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.

          We are subject to comprehensive government regulation by several federal, state and local regulatory agencies that significantly affect our business and our results of operations.

          APS is subject to comprehensive regulation by several federal, state and local regulatory agencies that significantly influence its business 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. Our financial condition and results of operations are dependent upon the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. See Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.

          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. 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.

We cannot predict the outcome of APS’ retail rate proceedings pending before the ACC.

          As noted above, our financial condition and results of operations are dependent upon the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. These proceedings consist of a general retail rate case, an application for an emergency interim rate increase, and an application for two separate surcharges under the PSA. See Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8. We cannot predict the timing or the outcome of these proceedings or the resulting levels of regulated revenues.

          We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact our business plans, or expose us to environmental liabilities.

          We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid

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waste, and hazardous waste. 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 us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. 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 are not fully recoverable from APS’ customers, could have a material adverse effect on our financial position, results of operations or cash flows.

          There are inherent risks in the operation of nuclear facilities, such as environmental, health 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, and the costs of securing the facilities against possible terrorist attacks and unscheduled outages due to equipment and other problems. We maintain nuclear decommissioning trust funds and external insurance coverage to minimize our 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 fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. 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 or 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.

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

          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 us 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 the service area of APS 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 our 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.

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

          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, we have 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.

          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 indefinitely 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. As defined in the ACC financing order approving the arrangement, common equity ratio is common equity divided by common equity plus long-term debt, including current maturities of long-term debt. At December 31, 2005, APS’ common equity ratio, as defined, was approximately 54%.

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          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.

          If we are not able to access capital at competitive rates, our ability to implement our financial strategy will be adversely affected.

          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 based upon current credit ratings. 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:

• an 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; or

• the overall health of the utility industry.

     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 to our competitors that have less debt.

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          A further 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 could increase our borrowing costs, which would diminish our financial results. We would likely 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 could also require us to provide 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 limit our 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 and changing interest rates and market conditions 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, coal, and emissions allowances. 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, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity.

          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, resulting in a material adverse impact on our earnings for a given period.

          Changing interest rates will affect interest paid on variable-rate debt and interest earned on variable-rate securities in our pension 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 is also impacted by the discount rate, which is the interest rate used to discount future pension obligations. Declining interest rates impact the discount rate, and may result in increases in pension costs, cash contributions, and charges to other comprehensive income. The pension plan 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 all of the nuclear decommissioning costs are recovered in regulated electricity prices.

Actual results could differ from estimates used to prepare our financial statements.

          In preparing our financial statements in accordance with accounting principles generally accepted in the United States of America, management must often make estimates and assumptions

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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 purchased power costs deferred under the PSA. APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. We had $324 million, including $173 million related to the PSA, of regulatory assets on the Consolidated Balance Sheets at December 31, 2005. Included in the $173 million is approximately $45 million related to the 2005 unplanned Palo Verde outages, which currently are the subject of inquiry by the ACC. Since December 25, 2005, Palo Verde Unit 1 has been operating at reduced power levels due to a non-safety related acoustic impact in one of the unit’s shutdown cooling lines. Unit 1 is currently operating at approximately 25% power. APS estimates that these reduced power levels and a planned Unit 1 outage to resolve the Unit 1 issue will result in additional PSA deferrals of approximately $85 million pretax in 2006. See Notes 1 and 3 for more information about regulatory assets and liabilities, APS’ pending retail rate proceedings, and the PSA.

• 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.

• 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, will determine 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 fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item associated with the hedged risk are recognized in earnings. For cash flow hedges, the effective portion of changes in the fair value of the derivative are recognized in common stock

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equity (as a component of other comprehensive income (loss)) and are recognized in earnings when the related transaction occurs.

     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 developments;

• our dividend policy;

• future sale of our 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.

          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. At December 31, 2005, there were no material restrictions on our ability to pay dividends under any such agreement.

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 2005 fiscal year and that remain unresolved.

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ITEM 2. PROPERTIES

Capacity

     APS’ present generating facilities have capacities as follows:

	Capacity (kW)
Coal:
Units 1, 2 and 3 at Four Corners		560,000
15% owned Units 4 and 5 at Four Corners		222,000
Units 1, 2 and 3 at Cholla		615,000
14% owned Units 1, 2 and 3 at the Navajo Generating Station		315,000
Subtotal		1,712,000
Gas or Oil:1
Two steam units at Ocotillo and two steam units at Saguaro		430,000
Twenty-two combustion turbine units		993,000
Seven combined cycle units		1,965,000
Subtotal		3,388,000
Nuclear:
29.1% owned or leased Units 1, 2, and 3 at Palo Verde		1,107,000
Solar		5,715
Total		6,212,715

¹ APS purchased a ten-unit (42,000 kW each) combustion turbine site (Sundance) on May 15, 2005.

Reserve Margin

     APS’ 2005 peak one-hour demand on its electric system was recorded on July 18, 2005 at 6,999,600 kW, compared with the 2004 peak of 6,402,100 kW recorded on August 11, 2004. 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 July 18, 2005, amounted to 6,383,000 kW, for an installed reserve margin of negative 13.3%. 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 2005 peak amounted to 3,820,000 kW, for a margin of a negative 51.4%. Firm purchases totaling 4,653,000 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 19.3%.

     See “Business of Arizona Public Service Company – Purchased Power and Generating Fuel – Purchased Power” in Item 1 for information about certain of APS’ long-term power agreements.

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Plant Sites Leased from Navajo Nation

     The Navajo Generating Station and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Nation. These are long-term agreements with options to extend, and APS does not believe that the risks with respect to enforcement of these easements and leases are material. The majority of coal contracted for use in these plants and certain associated transmission lines are also located on Indian reservations. See “Business of Arizona Public Service Company – Purchased Power and Generating Fuel – Coal Supply” in Item 1.

Palo Verde Nuclear Generating Station

     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.

     In 2004, the NRC determined that there had been a safety concern with Palo Verde’s procedures related to safety injection system piping. This led to a “yellow” finding under the NRC’s inspection criteria and put Palo Verde in the “degraded safety cornerstone” column of the NRC’s performance matrix, resulting in a supplemental NRC inspection. The NRC completed its supplemental inspection during 2005 and issued its report, closing one finding and indicating it would follow up on another finding at some later time upon notice from APS.

     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, including costs for low income programs, demand side management, consumer education, environmental, renewables, etc. “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 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for additional information about APS’ nuclear decommissioning costs.

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     Palo Verde Liability and Insurance Matters

     See “Palo Verde Nuclear Generating Station” in Note 11 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.

Property Not Held in Fee or Subject to Encumbrances

     Jointly-Owned Facilities

     APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2005:

	Percent Owned
Generating facilities (a):
Palo Verde Units 1 and 3		29.1	%
Palo Verde Unit 2 (see “Palo Verde Leases” below)		17.0	%
Four Corners Units 4 and 5		15.0	%
Navajo Generating Station Units 1, 2, and 3		14.0	%
Cholla common facilities (b)		62.6	%(c)
Transmission facilities:
ANPP 500KV System		35.8	%(c)
Navajo Southern System		31.4	%(c)
Palo Verde – Yuma 500KV System		23.9	%(c)
Four Corners Switchyards		27.5	%(c)
Phoenix – Mead System		17.1	%(c)
Palo Verde – Estrella 500KV System		55.5	%(c)
Harquahala		80.0	%(c)

(a)	This table does not reflect Pinnacle West Energy’s 75% interest in Silverhawk at December 31, 2005. Pinnacle West Energy sold this interest to NPC on January 10, 2006.
(b)	PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.
(c)	Weighted-average of interests.

     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 and to purchase the property for fair market value at the end of the lease terms. See Notes 9 and 20 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.

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Transmission Access

     APS’ transmission facilities consist of approximately 5,613 pole miles of overhead lines and approximately 42 miles of underground lines, 5,457 miles of which are located within the State of Arizona. APS’ distribution facilities consist of approximately 12,262 pole miles of overhead lines and approximately 14,430 miles of underground lines, all of which are located within the State of Arizona.

Other Information Regarding Our 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 — Overview” in Item 7 for a discussion of issues relating to Palo Verde Unit 1.

     See “Business of Arizona Public Service Company – Construction Program” in Item 1 and “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.

Information Regarding SunCor’s Properties

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

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APS Service Territory Map

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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 11 of Notes to the Pinnacle West Consolidated Financial Statements in Item 8 with regard to a lawsuit against APS and the other Navajo Generating Station participants and for information relating to the FERC proceedings on California energy market issues.

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

     Not applicable.

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SUPPLEMENTAL ITEM.

EXECUTIVE OFFICERS OF PINNACLE WEST

Pinnacle West’s executive officers are as follows:

Name	Age at March 1, 2006		Position(s) at March 1, 2006
William J. Post		55	Chairman of the Board and Chief Executive Officer (1)
Jack E. Davis		59	President and Chief Operating Officer, and President and Chief Executive Officer, APS (1)
Donald E. Brandt		51	Executive Vice President and Chief Financial Officer
Armando B. Flores		62	Executive Vice President, Corporate Business Services, APS
Chris N. Froggatt		48	Vice President and Controller, APS
Barbara M. Gomez		51	Vice President and Treasurer
James M. Levine		56	Executive Vice President, Generation, APS and President, Pinnacle West Energy
Nancy C. Loftin		52	Vice President, General Counsel and Secretary
Donald G. Robinson		52	Vice President, Planning, APS
Steven M. Wheeler		57	Executive Vice President, Customer Service and Regulation, APS

(1) Member of the Board of Directors.

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

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     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 is also a director of APS, Pinnacle West Energy and Phelps Dodge Corporation.

     Mr. Davis was elected President effective February 2001 and Chief Operating Officer effective September 2003. Prior to that time he was Chief Operating Officer and Executive Vice President of Pinnacle West (April 2000 – February 2001) and Executive Vice President, Commercial Operations of APS (September 1996 – October 1998). Mr. Davis is also President of APS (since October 1998) and Chief Executive Officer of APS (since October 2002). He is a director of APS and Pinnacle West Energy.

     Mr. Brandt was elected to his present position in September 2003 and was Senior Vice President and Chief Financial Officer (December 2002 – September 2003). Prior to that time, he was Senior Vice President and Chief Financial Officer of Ameren Corporation (diversified energy services company). Mr. Brandt was elected Executive Vice President and Chief Financial Officer of APS in September 2003. He was also Senior Vice President and Chief Financial Officer of APS (January 2003 – September 2003).

     Mr. Flores was elected to his present position in September 2003. Prior to that time, he was Executive Vice President, Corporate Business Services of Pinnacle West (July 1999 – September 2003). He was also Executive Vice President, Corporate Business Services of APS (October 1998 – July 1999).

     Mr. Froggatt was elected to his present position in October 2002. Prior to that time, he was 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 February 2004. Prior to that time, she was Treasurer (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.

     Mr. Levine was elected Executive Vice President of APS in July 1999 and President and Chief Executive Officer of Pinnacle West Energy in January 2003. Prior to that time, he was Senior Vice President, Nuclear Generation of APS (September 1996 – July 1999).

     Ms. Loftin was elected Vice President and General Counsel in July 1999 and Secretary in 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 in September 2003. Prior to that time, he was Vice President, Finance and Planning of APS (October 2002 – September 2003), Vice President, Regulation and Planning of Pinnacle West (June 2001 – October 2002) and Director, Accounting, Regulation and Planning of Pinnacle West (prior to June 2001).

     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). Prior to that time he was a partner with Snell & Wilmer L.L.P.

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PART II

ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED

STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     Pinnacle West’s common stock is publicly held and is traded on the New York and Pacific Stock Exchanges. At the close of business on March 7, 2006, Pinnacle West’s common stock was held of record by approximately 32,846 shareholders.

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

							Dividends
2005	High		Low		Close		Per Share
1st Quarter	$	44.87	$	40.99	$	42.51	$	0.475
2nd Quarter		45.34		41.29		44.45		0.475
3rd Quarter		46.68		43.13		44.08		0.475
4th Quarter		44.97		39.81		41.35		0.500

							Dividends
2004	High		Low		Close		Per Share
1st Quarter	$	40.81	$	36.90	$	39.35	$	0.450
2nd Quarter		41.50		36.30		40.39		0.450
3rd Quarter		42.99		39.63		41.50		0.450
4th Quarter		45.84		41.61		44.41		0.475

     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 declared on APS’ common stock for each of the four quarters for 2005 and 2004.

Common Stock Dividends
(Dollars in Thousands)

Quarter	2005		2004
1st Quarter	$	42,500	$	42,500
2nd Quarter		—		42,500
3rd Quarter		—		42,500
4th Quarter		127,500		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, 2005, APS did not have any outstanding preferred stock.

     Pinnacle West did not purchase any of its common stock during the fourth quarter of 2005.

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ITEM 6. SELECTED FINANCIAL DATA

PINNACLE WEST CAPITAL CORPORATION SELECTED CONSOLIDATED FINANCIAL DATA

	2005			2004			2003		2002			2001
	(dollars in thousands, except per share amounts)
OPERATING RESULTS
Operating revenues:
Regulated electricity segment	$	2,237,145		$	2,035,247		$	1,978,075	$	1,890,391		$	1,984,305
Marketing and trading segment (a)		351,558			400,628			391,196		286,879			469,784
Real estate segment (a)		338,031			350,315			361,604		201,081			168,908
Other revenues		61,221			42,816			27,929		26,899			11,771
Total operating revenues	$	2,987,955		$	2,829,006		$	2,758,804	$	2,405,250		$	2,634,768
Income from continuing operations (b)		223,163			246,590			225,384		236,563			327,367
Discontinued operations – net of income taxes (c)		(46,896	)		(3,395	)		15,195		(21,410	)		—
Cumulative effect of change in accounting – net of income taxes (d) (e)		—			—			—		(65,745	)		(15,201	)
Net income	$	176,267		$	243,195		$	240,579	$	149,408		$	312,166
COMMON STOCK DATA
Book value per share – year-end	$	34.58		$	32.14		$	30.97	$	29.40		$	29.46
Earnings (loss) per weighted average common share outstanding:
Continuing operations – basic	$	2.31		$	2.70		$	2.47	$	2.79		$	3.86
Discontinued operations (c)		(0.48	)		(0.04	)		0.17		(0.26	)		—
Cumulative effect of change in accounting (d) (e)		—			—			—		(0.77	)		(0.18	)
Net income – basic	$	1.83		$	2.66		$	2.64	$	1.76		$	3.68
Continuing operations – diluted	$	2.31		$	2.69		$	2.47	$	2.78		$	3.85
Net income – diluted	$	1.82		$	2.66		$	2.63	$	1.76		$	3.68
Dividends declared per share	$	1.925		$	1.825		$	1.725	$	1.625		$	1.525
Indicated annual dividend rate per share – year-end	$	2.00		$	1.90		$	1.80	$	1.70		$	1.60
Weighted-average common shares outstanding – basic		96,483,781			91,396,904			91,264,696		84,902,946			84,717,649
Weighted-average common shares outstanding – diluted		96,589,949			91,532,473			91,405,134		84,963,921			84,930,140
BALANCE SHEET DATA
Total assets	$	11,322,645		$	9,896,747		$	9,519,042	$	9,139,157		$	8,529,124
Liabilities and equity:
Long-term debt less current maturities	$	2,608,455		$	2,584,985		$	2,616,585	$	2,743,741		$	2,673,078
Other liabilities		5,289,226			4,361,566			4,072,678		3,709,263			3,356,723
Total liabilities		7,897,681			6,946,551			6,689,263		6,453,004			6,029,801
Common stock equity		3,424,964			2,950,196			2,829,779		2,686,153			2,499,323
Total liabilities and equity	$	11,322,645		$	9,896,747		$	9,519,042	$	9,139,157		$	8,529,124

(a)	Includes reclassifications of revenue in 2004 and 2003 related to items accounted for as discontinued operations of SunCor and Silverhawk. See Note 22 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.
(b)	Includes regulatory disallowance of $84 million after tax in 2005. See Note 3 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.
(c)	Amounts related to Silverhawk, SunCor and NAC discontinued operations. Prior year amounts have been reclassified to discontinued operations to conform to current year presentation. See Note 22 of Notes to Pinnacle West’s Consolidated Financial Statements in Item 8.
(d)	Represents change in accounting standards related to energy trading activities in 2002.
(e)	Represents change in accounting standards related to derivatives in 2001.

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SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY

	2005			2004		2003		2002			2001
	(dollars in thousands)
OPERATING RESULTS
Electric operating revenues:
Regulated electricity	$	2,244,951		$	2,051,602	$	1,999,390	$	1,902,112		$	1,984,305
Marketing and trading		25,842			145,519		105,541		34,054			367,793
Total electric operating revenues		2,270,793			2,197,121		2,104,931		1,936,166			2,352,098
Fuel and purchased power costs:
Regulated electricity		656,654			612,300		606,251		438,141			649,405
Marketing and trading		32,328			150,954		97,180		32,662			132,544
Operating expenses		1,200,198			1,104,886		1,103,342		1,136,363			1,171,171
Operating income		381,613			328,981		298,158		329,000			398,978
Other income (deductions)		(69,171	)		15,328		26,347		(8,041	)		(79	)
Interest deductions – net		141,963			144,682		143,568		121,616			118,211
Income before cumulative effect adjustment		170,479			199,627		180,937		199,343			280,688
Cumulative effect of change in accounting – net of income taxes (a)		—			—		—		—			(15,201	)
Net income	$	170,479		$	199,627	$	180,937	$	199,343		$	265,487
BALANCE SHEET DATA
Total assets	$	9,707,441		$	8,098,552	$	7,722,533	$	7,122,238		$	6,815,458
Capital structure:
Common stock equity	$	2,985,225		$	2,232,402	$	2,203,630	$	2,159,312		$	2,150,690
Long-term debt less current maturities		2,479,703			2,267,094		2,135,606		2,217,340			1,949,074
Total capitalization		5,464,928			4,499,496		4,339,236		4,376,652			4,099,764
Commercial paper		—			—		—		—			171,162
Current maturities of long-term debt		85,620			451,247		487,067		3,503			125,451
Total	$	5,550,548		$	4,950,743	$	4,826,303	$	4,380,155		$	4,396,377

(a) Change in accounting standards related to derivatives.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

     The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and Arizona Public Service Company’s 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. Customer growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.

     The ACC regulates APS’ retail electric rates. The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 3, APS has pending before the ACC:

• a general retail rate case pursuant to which APS is requesting a 21.3%, or $453.9 million, increase in its annual retail electricity revenues effective no later than December 31, 2006;

• an application for an emergency interim rate increase of $299 million, or approximately 14%, to be effective April 1, 2006 (the increase would accelerate recovery of the fuel and purchased power component of APS’ general rate case and is not an additional increase and would be subject to refund); and

• an application for a temporary rate increase of approximately 2.6%, through two separate PSA surcharges, to recover $59.9 million in retail fuel and purchased power costs deferred by APS in 2005 under the PSA.

     APS has been operating Palo Verde Unit 1 at reduced power levels since December 25, 2005 due to a non-safety related acoustic impact in one of the unit’s shutdown cooling lines. Unit 1 is currently operating at approximately 25% power. APS has concluded after comprehensive analysis that the preferred solution will require Unit 1 to undergo an outage of approximately five weeks in order for APS to effect the necessary modifications to the Unit. APS anticipates that Unit 1 will begin this outage in the June timeframe. In addition, an outage for preparatory work of approximately one week, beginning March 18, 2006, will take place prior to this outage. This preferred solution was initially planned for installation in the spring of 2007. APS estimates that, through February 28, 2006, Unit 1’s reduced power level has resulted in incremental replacement power costs of approximately $20 million after income taxes, approximately $18 million of which has been incurred since January 1, 2006. Based on current forward market energy prices, APS estimates that (a) operating Unit 1 at reduced power levels until the assumed outage in the June timeframe will result in additional incremental replacement power costs of approximately $25 million after income taxes and (b) the June Unit 1 outage will result in additional incremental replacement power costs of approximately $15 million after income taxes. APS estimates that these reduced power levels and the June Unit 1 outage will result in additional PSA deferrals of $50 million after tax ($85 million pretax) in 2006. See “Deferred Fuel and Purchased Power Costs” below.

     SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow. Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial and

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industrial retail customers in the western United States. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures.

     Pinnacle West Energy is our subsidiary that previously owned and operated unregulated generating plants. Pursuant to the ACC’s April 7, 2005 order in APS’ 2003 rate case, on July 29, 2005, Pinnacle West Energy transferred the PWEC Dedicated Assets to APS. See “APS 2003 Rate Case” in Note 3. Pinnacle West Energy sold its 75% interest in Silverhawk to NPC on January 10, 2006. As a result Pinnacle West Energy no longer owns any generating plants and has ceased operations.

     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 resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.

     See “Pinnacle West Consolidated – 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

     We have three principal business segments (determined by products, services and the regulatory environment):

• 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;

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

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services.

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     The following table summarizes net income for 2005, 2004 and 2003 (dollars in millions):

	2005			2004			2003
Regulated electricity	$	167		$	152		$	170
Real estate		35			40			45
Marketing and trading		16			29			8
Other (a)		5			26			2
Income from continuing operations		223			247			225
Discontinued operations – net of tax:
Real estate (b)		17			4			10
Marketing and trading (c)		(67	)		(12	)		1
Other (d)		3			4			5
Net income	$	176		$	243		$	241

(a)	Includes a $21 million after-tax gain in 2004 related to the sale of a limited partnership interest in the Phoenix Suns.
(b)	Primarily relates to sales of commercial properties.
(c)	See “Sale of Silverhawk” below.
(d)	Relates to the 2004 sale of NAC.

PINNACLE WEST CONSOLIDATED — RESULTS OF OPERATIONS

General

     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less fuel and purchased power costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with Securities and Exchange Commission rules. Exhibit 99.29 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior year amounts to conform to our current-period presentation.

Sale of Silverhawk

     In June 2005, we entered into an agreement to sell our 75% interest in Silverhawk to NPC. As a result of the sale, we recorded an after-tax loss from discontinued operations of approximately $56 million in the second quarter of 2005. The marketing and trading segment discontinued operations in the chart above include this loss as well as revenues and expenses related to the operations of Silverhawk. The sale was completed on January 10, 2006.

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Deferred Fuel and Purchased Power Costs

     The settlement of APS’ 2003 general retail rate case became effective April 1, 2005. As part of the settlement, the ACC approved a 4.2% annual retail rate increase and the PSA, which provides mechanisms for adjusting rates to reflect variations in fuel and purchased power costs. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual fuel and purchased power costs, net of Off-System Sales margins, and the amount for such costs currently included in base rates. The current base rate for fuel and purchased power costs is based on 2003 price levels and spot prices for natural gas and wholesale power have increased over 40% since then. Although APS defers actual fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual PSA adjustments and ACC approval of periodic surcharge applications.

     Actual fuel and purchased power costs are higher than in prior periods primarily due to higher fuel prices and increased plant outage days.

     APS’ pretax PSA deferrals were approximately $173 million at December 31, 2005. Based on recent forward market prices for natural gas and purchased power (which are subject to change), and assuming no interim rate relief, APS estimates that its pretax PSA deferrals in 2006 will be approximately $240 million to $250 million. In January 2006, the ACC approved the first annual adjustment under the PSA mechanism, which is expected to recover approximately $110 million of the 2005 balance of $173 million from retail customers over twelve months beginning February 1, 2006. In this same order, the ACC granted APS the authority to continue to defer fuel costs in excess of the $776.2 million annual fuel cost cap established in the 2005 rate order and to seek recovery of those amounts in a future proceeding. On February 2, 2006, APS filed a request with the ACC to recover the remainder of the retail portion of the 2005 deferred fuel balance of $173 million — approximately $60 million — through two surcharges. The first surcharge is to recover $15 million over a twelve-month period proposed to begin with the date of the ACC’s decision in APS’ pending emergency interim rate case. The second surcharge is to recover approximately $45 million over a twelve-month period proposed to begin no later than the ACC’s completion of its inquiry regarding unplanned 2005 outages at Palo Verde. The $45 million of PSA deferrals represents additional replacement power costs associated with these outages. See Note 3. See “Overview” in this Item 7 for information about Palo Verde Unit 1 operating at reduced power levels and the related economic impact.

2005 Compared with 2004

     Our consolidated net income for 2005 was $176 million compared with $243 million for the prior year. The current-year net income included an after-tax net loss from discontinued operations of $47 million compared with a $4 million after-tax loss in the prior year, which for both years is related primarily to the sale and operations of Silverhawk (see “Sale of Silverhawk” above), partially offset by sales of commercial properties at SunCor. Income from continuing operations decreased $24 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

• Regulated Electricity Segment – Income from continuing operations increased approximately $15 million primarily due to deferred fuel and purchased power costs; a retail price increase effective April 1, 2005; higher retail sales volumes due to

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	customer growth; lower depreciation due to lower depreciation rates; lower regulatory asset amortization; and effects of weather on retail sales. These positive factors were partially offset by the regulatory disallowance of plant costs in accordance with the APS retail rate case settlement; higher fuel and purchased power costs primarily due to higher prices and more plant outage days; higher operations and maintenance expense related to generation and customer service; and higher property taxes due to increased plant in service.
•	Real Estate Segment – Income from continuing operations decreased approximately $5 million primarily due to decreased parcel sales, partially offset by increased margins on home sales. Income from discontinued real estate operations increased $13 million due to higher commercial property sales.
•	Marketing and Trading Segment – Income from continuing operations decreased approximately $13 million primarily due to lower unit margins on competitive retail sales in California; the absence of Off-System Sales that we began reporting in the regulated electricity segment in April 2005; and lower mark-to-market gains on contracts for future delivery.
•	Other Segment – Income from continuing operations decreased approximately $21 million primarily due to an after-tax gain related to the sale of a limited partnership interest in the Phoenix Suns recorded in the prior year.

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Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Deferred fuel and purchased power costs (see discussion above)	$	171		$	104
Retail price increase effective April 1, 2005		65			40
Higher retail sales volumes due to customer growth, excluding weather effects		58			35
Effects of weather on retail sales		14			9
Higher fuel and purchased power costs primarily due to higher prices and more plant outage days		(126	)		(77	)
Miscellaneous items, net		(8	)		(5	)
Net increase in regulated electricity segment gross margin		174			106
Marketing and trading segment gross margin:
Lower unit margins on competitive retail sales in California		(13	)		(8	)
Lower realized margins on wholesale sales primarily due to the absence of sales that we began reporting in the regulated segment in April 2005		(4	)		(3	)
Lower mark-to-market gains on contracts for future delivery due to changes in forward prices		(4	)		(2	)
Net decrease in marketing and trading segment gross margin		(21	)		(13	)
Net increase in gross margin for regulated electricity and marketing and trading segments		153			93
Regulatory disallowance, in accordance with the APS retail rate case settlement		(139	)		(84	)
Lower real estate segment contribution primarily related to decreased parcel sales, partially offset by increased margins on home sales		(8	)		(5	)
Lower other income primarily due to sale of limited partnership interest in Phoenix Suns recorded in the prior year, partially offset by higher interest income		(30	)		(18	)
Operations and maintenance increases primarily due to:
Generation costs, including maintenance and overhauls		(20	)		(12	)
Customer service costs, including regulatory demand-side management programs and planned maintenance		(20	)		(12	)
Miscellaneous items, net		(4	)		(2	)
Depreciation and amortization decreases primarily due to:
Lower regulatory asset amortization		22			13
Lower depreciation rates, partially offset by increased depreciable assets		22			13
Higher property taxes primarily due to increased plant in service		(11	)		(7	)
Miscellaneous items, net		2			(3	)
Net decrease in income from continuing operations	$	(33	)		(24	)
Discontinued operations related to:
Sale of Silverhawk (see discussion above)					(56	)
Sales of real estate assets and other					13
Net decrease in net income				$	(67	)

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     Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $202 million higher for 2005 compared with the prior year primarily as a result of:

• an $81 million increase in retail revenues related to customer growth, excluding weather effects;

• a $65 million increase in retail revenues due to a price increase effective April 1, 2005;

• a $40 million increase in Off-System Sales primarily resulting from sales previously reported in the marketing and trading segment that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate case settlement;

• an $11 million increase in retail revenues related to weather; and

• a $5 million increase due to miscellaneous factors.

     Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $49 million lower for 2005 compared with the prior year primarily as a result of:

• a $40 million decrease in Off-System Sales due to the absence of sales previously reported in the marketing and trading segment that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate case settlement;

• a $4 million decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices;

• a $3 million decrease in marketing and trading revenues due to lower sales volumes; and

• a $2 million decrease from lower volumes of competitive retail sales in California.

     Real Estate Revenues

     Real estate revenues were $12 million lower for 2005 compared with the prior year primarily due to decreased parcel sales, partially offset by increased home sales at SunCor.

Other Revenues

     Other revenues were $18 million higher for 2005 compared with the prior year primarily due to increased sales of energy-related products and services by APS Energy Services.

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2004 Compared with 2003

     Our consolidated net income for 2004 was $243 million compared with $241 million for the prior year. 2004 net income included an after-tax net loss from discontinued operations of $4 million primarily related to Silverhawk. The 2003 net income included a $16 million after-tax gain from discontinued operations primarily related to sales of commercial properties at SunCor. Income from continuing operations increased $22 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

• Regulated Electricity Segment – Income from continuing operations decreased approximately $18 million primarily due to higher costs (primarily interest expense, depreciation, operation and maintenance costs and property taxes, net of gross margin contributions) related to a new power plant placed in service in mid-2003; increased operations and maintenance costs primarily related to customer service and personnel costs; lower income tax credits; higher depreciation related to delivery and other assets; the effects of milder weather on retail sales; and a retail electricity rate decrease in mid-2003. These negative factors were partially offset by lower regulatory asset amortization, and higher retail sales volumes due to customer growth and usage.

• Real Estate Segment – Income from continuing operations decreased approximately $5 million due to decreased asset sales, partially offset by increased land sales. Income from discontinued operations decreased $6 million primarily due to the 2003 gain on the sale of SunCor’s water utility company (see Note 22).

• Marketing and Trading Segment – Income from continuing operations increased approximately $21 million primarily due to higher forward and realized prices for wholesale electricity, partially offset by lower margins in California by APS Energy Services. Income from discontinued operations decreased $13 million due to Silverhawk (see Note 22).

• Other Segment – Income from continuing operations increased approximately $24 million primarily due to a $21 million after-tax gain related to the sale of El Dorado’s limited partnership interest in the Phoenix Suns.

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     Additional details on the major factors that increased (decreased) income from continuing operations and net income are contained in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Higher retail sales volumes due to customer growth, excluding weather effects	$	43		$	26
Lower replacement power costs due to fewer unplanned outages		6			4
Effects of weather on retail sales		(17	)		(10	)
Retail electricity price reduction effective July 1, 2003		(13	)		(8	)
Increased purchased power and fuel costs due to higher fuel and power prices		(4	)		(2	)
Miscellaneous factors, net		(8	)		(6	)
Net increase in regulated electricity segment gross margin		7			4
Marketing and trading segment gross margin:
Higher mark-to-market gains on contracts for future delivery due to higher forward prices for wholesale electricity		28			17
Higher realized margins on energy trading primarily due to higher electricity prices		18			11
Increase in Off-System Sales due to higher sales volumes and higher unit margins		10			6
Lower unit margins and lower competitive retail sales volumes in California by APS Energy Services		(22	)		(13	)
Net increase in marketing and trading segment gross margin		34			21
Net increase in gross margin for regulated electricity and marketing and trading segments		41			25
Lower real estate segment contributions primarily due to decreased asset sales, a portion of which was recorded in other income in the prior period, partially offset by higher land sales (see Note 22)		(7	)		(5	)
Higher other income due to the sale of El Dorado’s limited partnership interest in the Phoenix Suns		35			21
Higher operations and maintenance expense primarily related to customer service costs, new power plants in service and personnel costs		(44	)		(26	)
Interest expense net of capitalized financing costs, decreases (increases):
New power plants in service		(16	)		(10	)
Lower other debt balances and rates partially offset by increased utility plant in service		9			5
Depreciation and amortization decreases (increases):
Lower regulatory asset amortization		68			41
New power plants in service		(4	)		(2	)
Increased delivery and other assets		(20	)		(12	)
Higher property taxes due to increased plant in service		(10	)		(6	)
Lower income tax credits		—			(17	)
Miscellaneous items, net		3			8
Net increase in income from continuing operations	$	55			22
Discontinued operations (see Note 22)					(20	)
Net increase in net income				$	2

     The increase in net costs (primarily interest expense, depreciation and operations and maintenance expense, net of gross margin contributions) related to new power plants placed in service in mid-2003 and mid-2004 by Pinnacle West Energy totaled approximately $26 million after income taxes in 2004 compared with the prior year.

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Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $57 million higher for 2004 compared with the prior year primarily as a result of:

• a $101 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;

• a $42 million decrease in retail revenues related to milder weather;

• a $13 million decrease in retail revenues related to a reduction in retail electricity prices; and

• an $11 million increase due to miscellaneous factors.

Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $9 million higher for 2004 compared with the prior year primarily as a result of:

• $28 million in higher mark-to-market gains for future-period deliveries primarily as a result of higher forward prices for wholesale electricity;

• a $25 million decrease from lower competitive retail sales volumes in California by APS Energy Services;

• $20 million of higher energy trading revenues on realized sales of electricity primarily due to higher electricity prices; and

• a $14 million decrease in Off-System Sales primarily due to lower wholesale unit margins and lower sales volumes.

Other Revenues

     Other revenues were $15 million higher for 2004 compared with the prior year primarily due to higher non-commodity revenues at APS Energy Services.

LIQUIDITY AND CAPITAL RESOURCES

Capital Needs and Resources – Pinnacle West Consolidated

     Capital Expenditure Requirements

     The following table summarizes the actual capital expenditures for the year ended 2005 and estimated capital expenditures for the next three years:

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CAPITAL EXPENDITURES
(dollars in millions)

	Actual		Estimated
	2005		2006		2007		2008
APS
Distribution	$	325	$	322	$	323	$	362
Transmission		92		120		169		203
Generation (a)		356		184		207		279
Other (b)		36		23		16		13
Subtotal		809		649		715		857
SunCor (c)		106		232		142		119
Other		13		6		2		6
Total	$	928	$	887	$	859	$	982

(a)	Includes $185 million in 2005 for the acquisition of the Sundance Plant.
(b)	Primarily information systems and facilities projects.
(c)	Consists primarily of capital expenditures for land development and retail and office building construction reflected in “Real estate investments” on the Consolidated Statements of Cash Flows.

     Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth.

     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants, the acquisition of the Sundance Plant and the replacement of Palo Verde steam generators (see below). 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. Generation also includes nuclear fuel expenditures of approximately $35 million annually for 2006 through 2008.

     Replacement of the steam generators at Palo Verde Unit 1 was completed during the fall 2005 outage at a cost to APS of approximately $70 million. The Palo Verde owners have approved the manufacture of one additional set of steam generators. These generators will be installed in Unit 3 and are scheduled for completion in the fall of 2007 at an approximate cost of $75 million (APS’ share). Approximately $20 million of the Unit 3 steam generator costs have been incurred through 2005 with the remaining $55 million included in future years in the capital expenditure table above. Capital expenditures will be funded with internally generated cash or external financings.

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Contractual Obligations

     The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2005 (dollars in millions):

			2007-		2009-
	2006		2008		2010		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	219	$	259	$	480	$	3,350	$	4,308
Pinnacle West		312		—		—		—		312
SunCor		9		143		—		—		152
Total long-term debt payments, including interest		540		402		480		3,350		4,772
Short-term debt payments, including interest (b)		16		—		—		—		16
Capital lease payments		2		2		2		2		8
Operating lease payments		74		144		133		303		654
Minimum pension funding requirement (c)		37		—		—		—		37
Purchased power and fuel commitments (d)		316		419		256		908		1,899
Purchase obligations (e)		25		9		—		75		109
Nuclear decommissioning funding requirements		21		42		46		259		368
Total contractual commitments	$	1,031	$	1,018	$	917	$	4,897	$	7,863

(a)	The long-term debt matures at various dates through 2035 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using the rates at December 31, 2005 (see Note 6).
(b)	The short-term debt matures within 12 months and is primarily related to short-term loans at SunCor. These loans are made up of multiple notes primarily with variable interest rates based on prime plus 1.75% or LIBOR plus 2.25% and 2.50% at December 31, 2005 (see Note 5).
(c)	Future pension contributions are not determinable for time periods after 2006.
(d)	Our fuel and purchased power commitments include purchases of coal, electricity, natural gas and nuclear fuel (see Note 11).
(e)	These contractual obligations include commitments for capital expenditures and other obligations.

     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.

     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

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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, 2005, APS would have been required to assume approximately $234 million of debt and pay the equity participants approximately $185 million.

     Guarantees and Letters of Credit

     We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Consolidated Balance Sheets with respect to these obligations. 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.

     Credit Ratings

     The ratings of securities of Pinnacle West and APS as of March 7, 2006 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 those companies’ cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 18).

	Moody’s		Standard & Poor’s
Pinnacle West
Senior unsecured	Baa2		BB+
Commercial paper	P	-2		A-3
Outlook	Under Review for		Stable
	Possible Downgrade
APS
Senior unsecured	Baa1		BBB-
Secured lease obligation bonds	Baa1		BBB-
Commercial paper	P	-2		A-3
Outlook	Under Review for		Stable
	Possible Downgrade

     Debt Provisions

     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt to capitalization ratio. 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 each of

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Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At December 31, 2005, the ratio was approximately 49% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage is approximately 4 times under APS’ bank financing agreements as of December 31, 2005. 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.

     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, in the event of a further rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

     All of Pinnacle West’s bank 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.

Capital Needs and Resources

     Pinnacle West (Parent Company)

     Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. On October 19, 2005, our Board of Directors increased the common stock dividend to an indicated annual rate of $2.00 per share from $1.90 per share, effective with the December 1, 2005 dividend payment. The level of our common 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.

     Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2003 through 2005, total dividends from APS were $510 million and total cash contributions from SunCor were $243 million. For the year ended December 31, 2005 cash contributions from APS were approximately $170 million and distributions from SunCor were approximately $50 million. An ACC financing 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. At December 31, 2005, APS’ common equity ratio, as defined, was approximately 54%.

     At December 31, 2005, Pinnacle West’s outstanding long-term debt, including current maturities, was $299 million. In December 2005, we replaced the existing revolving credit facility with a $300 million revolving credit facility that terminates in December 2010. This line of credit is available to support the issuance of up to $250 million in commercial paper or to be used as bank borrowings, including issuances of letters of credit. At December 31, 2005, we had no commercial paper or short-term borrowings outstanding. We ended 2005 in an invested position.

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     Pinnacle West sponsors a qualified pension plan for the employees of Pinnacle West and our subsidiaries. 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 the fund assets and our pension obligation. The assets in the plan are comprised of common stocks, bonds, common and collective trusts and short-term investments. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. We contributed $53 million in 2005. The contribution to our pension plan in 2006 is estimated to be approximately $50 million. The expected contribution to our other postretirement benefit plans in 2006 is estimated to be approximately $29 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

     On May 2, 2005, Pinnacle West redeemed at par all of its $165 million Floating Rate Senior Notes due November 1, 2005. The Company used cash on hand to redeem the notes.

     On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the net proceeds for general corporate purposes, including making capital contributions to APS, which, in turn, used a portion of such funds to acquire the Sundance Plant and fund other capital expenditures to meet the growing needs of APS’ service territory.

     On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million aggregate principal amount of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”). Pinnacle West will use the proceeds of the Series A Notes to repay at maturity a portion of the $300 million aggregate principal amount of its 6.40% Senior Notes due April 1, 2006 or for other general corporate purposes.

     See “Equity Infusions” in Note 3 for information regarding the ACC approval of Pinnacle West’s infusion of more than $450 million of equity into APS, consisting of about $250 million of the proceeds of Pinnacle West’s common equity issuance and about $210 million of the proceeds from the sale of Silverhawk in January 2006.

     APS

     APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, 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.

     On January 15, 2005, APS repaid its $100 million 6.25% Notes due 2005. APS used cash on hand to redeem these notes.

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     On March 1, 2005, Maricopa County, Arizona Pollution Control Corporation issued $164 million of variable interest rate pollution control bonds, 2005 Series A-E, due 2029. The bonds were issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Maricopa County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Balance Sheets.

     On May 12, 2003, APS issued $500 million of debt and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to Pinnacle West to fund the repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated Assets. On April 11, 2005, this loan was repaid with the proceeds of a new debt issuance by Pinnacle West Energy.

     On August 1, 2005, APS repaid $300 million of its 7.625% Notes due 2005. APS used cash on hand to repay these notes.

     On August 22, 2005, APS issued $250 million of 5.50% Senior Unsecured Notes due September 1, 2035. A portion of the net proceeds from the sale of the notes was used for general corporate purposes and, on October 3, 2005, APS used the balance of the proceeds, along with cash on hand, to fund the $500 million that it was obligated to transfer to Pinnacle West Energy in connection with APS’ acquisition of the PWEC Dedicated Assets. See “Related Party Transactions” in Note S-6 for information regarding the $500 million intercompany payable to Pinnacle West Energy. APS satisfied this obligation to Pinnacle West Energy on October 3, 2005.

     APS’ outstanding debt was approximately $2.6 billion at December 31, 2005. In December 2005, APS replaced its $325 million revolving credit facility that would have terminated in May 2007 with a $400 million revolving credit facility that terminates in December 2010. This line of credit 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. At December 31, 2005, APS had no outstanding commercial paper or bank borrowings. APS ended 2005 in an invested position.

     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.

     See “Deferred Fuel and Purchased Power Costs” above and “Power Supply Adjustor” in 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 PSA adjustments and ACC approval of periodic surcharge applications.

     See “Cash Flow Hedges” in Note 18 for information related to increased collateral provided to us by counterparties.

Pinnacle West Energy

     On April 11, 2005, Pinnacle West Energy issued $500 million Floating Rate Senior Notes due April 1, 2007. Pinnacle West unconditionally guaranteed these notes. Pinnacle West Energy used the proceeds of this issuance to repay the $500 million loan from APS to Pinnacle West Energy described under “Capital Needs and Resources — APS” above. On October 3, 2005, Pinnacle West

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Energy repaid the Floating Rate Senior Notes due April 1, 2007 with $500 million received from APS in connection with the transfer of the PWEC Dedicated Assets.

     See Note 22 of Notes to Consolidated Financial Statements above for a discussion of the sale of our 75% ownership interest in Silverhawk.

     Other Subsidiaries

     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 2005 and projected capital expenditures for the next three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.

     SunCor’s total outstanding debt was approximately $145 million as of December 31, 2005, including $123 million of debt outstanding, which is classified as long-term debt, under a $150 million line of credit. SunCor’s total short-term debt was $16 million at December 31, 2005. SunCor’s long-term debt, including current maturities, totaled $129 million at December 31, 2005. See Note 6.

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

     APS Energy Services expects minimal capital expenditures over the next three years.

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 $324 million, including $173 million related to the PSA, of regulatory assets on the Consolidated Balance Sheets at December 31, 2005. Included in the $173 million is approximately $45 million related to the 2005 unplanned Palo Verde outages, which currently are the subject of inquiry by the ACC. In addition, we had $592 million of regulatory liabilities on the Consolidated Balance Sheets at December 31,

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2005, which primarily are related to removal costs. See Notes 1 and 3 for more information about regulatory assets, APS’ general rate case and power supply adjustor.

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, 2005 projected benefit obligation, our December 31, 2005 reported pension liability on the Consolidated Balance Sheets and our 2005 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
	Projected			Impact on			Impact on
	Benefit			Pension			Pension
Actuarial Assumption (a)	Obligation			Liability			Expense
Discount rate:
Increase 1%	$	(207	)	$	(170	)	$	(8	)
Decrease 1%		237			195			8
Expected long-term rate of return on plan assets:
Increase 1%		—			—			(4	)
Decrease 1%		—			—			4

(a) Each fluctuation assumes that the other assumptions of the calculation are held constant.

     The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2005 accumulated other postretirement benefit obligation and our 2005 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):

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	Increase(Decrease)
	Impact on Accumulated			Impact on Other
	Other Postretirement			Postretirement
Actuarial Assumption (a)	Benefit Obligation			Benefit Expense
Discount rate:
Increase 1%	$	(84	)	$	(4	)
Decrease 1%		106			5
Health care cost trend rate (b):
Increase 1%		100			7
Decrease 1%		(79	)		(6	)
Expected long-term rate of return on plan assets – pretax:
Increase 1%		—			(1	)
Decrease 1%		—			1

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

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

Derivative Accounting

     Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we 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 fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item associated with the hedged risk are recognized in earnings. For cash flow hedges, the effective portion of changes in the fair value of the derivative are recognized in common stock equity (as a component of other comprehensive income (loss)).

     The fair value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio consists of structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. See “Market Risks – Commodity Price Risk” below for quantitative analysis. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative and energy trading accounting.

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PINNACLE WEST CONSOLIDATED – FACTORS AFFECTING
OUR FINANCIAL OUTLOOK

Factors Affecting Operating Revenues, Fuel and Purchased Power Costs

     GeneralElectric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity rates and tariffs and variations in weather from period to period. Competitive sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition.

     Retail Rate ProceedingsThe key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 3, APS has pending before the ACC a general retail rate case, an application for an emergency interim rate increase, and an application for two separate surcharges under the PSA.

     Fuel and Purchased Power CostsFuel and purchased power costs 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, variances in deferrals and amortization of fuel and purchased power beginning on April 1, 2005 and our hedging program for managing such costs. See “Power Supply Adjustor” in Note 3 for information regarding the PSA approved by the ACC. See “Natural Gas Supply” in Note 11 for more information on fuel costs. See “Overview” in this Item 7 for information about Palo Verde Unit 1 operating at reduced power levels and the related economic impact.

     Customer and Sales GrowthThe customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory averaged about 3.8% a year for the three years 2003 through 2005; we currently expect customer growth to average about 3.8% per year from 2006 to 2008. We currently estimate that total retail electricity sales in kilowatt-hours will grow 3.7% on average, from 2006 through 2008, before the effects of weather variations. Customer growth for 2005 was 4.3%.

     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 can result in increases or decreases in annual net income of up to $10 million.

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

     Wholesale Power Market ConditionsThe marketing and trading division focuses primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. The marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and

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credits. Our future earnings will be affected by the strength or weakness of the wholesale power market.

Other Factors Affecting Financial Results

     Operations and Maintenance ExpensesOperations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.

     Depreciation and Amortization ExpensesDepreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction or acquisition, changes in depreciation and amortization rates (see Note 1), and changes in regulatory asset amortization. See Note 7 for information on APS’ acquisition of the Sundance Plant in 2005. See “Purchased Power” in Part I, Item 1 of this report, for more information on requests for proposal to acquire additional long-term resources in 2006 and 2007.

     Property TaxesTaxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed value for 2005 and 2004. We expect property taxes to increase as new power plants, the acquisition of the Sundance Plant and our additions to transmission and distribution facilities are included in the property tax base.

     Interest ExpenseInterest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our 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. Interest expense is also affected by interest rates on variable-rate debt.

     Retail CompetitionAlthough some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail competitors providing 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.

     SubsidiariesSunCor’s net income was $56 million in 2003, $45 million in 2004 and $56 million in 2005. See Note 22 for further discussion.

     APS Energy Services’ and El Dorado’s historical results are not indicative of future performance.

     GeneralOur financial results may be affected by a number of broad factors. See “Forward-Looking Statements” 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.

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     Interest Rate and Equity Risk

     Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund (see Note 12). Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The nuclear decommissioning fund also has risk associated with the changing market value of equity 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, 2005 and 2004. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2005 and 2004 (dollars in thousands):

						Variable-Rate					Fixed-Rate
	Short-Term Debt					Long-Term Debt					Long-Term Debt
	Interest					Interest					Interest
2005	Rates			Amount		Rates			Amount		Rates			Amount
2006		7.11	%	$	15,673		5.38	%	$	350		6.47	%	$	386,624
2007		—			—		5.38	%		350		5.90	%		1,271
2008		—			—		5.93	%		128,178		5.85	%		1,318
2009		—			—		—			—		5.73	%		1,014
2010		—			—		—			—		5.69	%		1,077
Years thereafter		—			—		3.25	%		565,855		5.79	%		1,918,026
Total				$	15,673				$	694,733				$	2,309,330
Fair value				$	15,673				$	694,733				$	2,326,235

						Variable-Rate					Fixed-Rate
	Short-Term Debt					Long-Term Debt					Long-Term Debt
	Interest					Interest					Interest
2004	Rates			Amount		Rates			Amount		Rates			Amount
2005		4.21	%	$	71,030		1.99	%	$	165,447		7.27	%	$	402,198
2006		—			—		6.55	%		2,918		6.45	%		395,314
2007		—			—		4.81	%		302		5.99	%		1,154
2008		—			—		5.22	%		5,294		5.51	%		1,055
2009		—			—		—			—		5.51	%		818
Years thereafter		—			—		1.89	%		565,860		4.79	%		1,669,901
Total				$	71,030				$	739,821				$	2,470,440
Fair value				$	71,030				$	740,271				$	2,574,608

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     The tables below present contractual balances of APS’ long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2005 and 2004. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2005 and 2004 (dollars in thousands):

	Variable-Rate					Fixed-Rate
	Long-Term Debt					Long-Term Debt
	Interest					Interest
2005	Rates			Amount		Rates			Amount
2006		—		$	—		6.71	%	$	86,165
2007		—			—		5.76	%		1,075
2008		—			—		5.74	%		1,271
2009		—			—		5.70	%		1,005
2010		—			—		5.69	%		1,077
Years thereafter		3.25	%		565,855		5.79	%		1,918,026
Total				$	565,855				$	2,008,619
Fair value				$	565,855				$	2,025,001

	Variable-Rate					Fixed-Rate
	Long-Term Debt					Long-Term Debt
	Interest					Interest
2004	Rates			Amount		Rates			Amount
2005		—		$	—		7.27	%	$	401,727
2006		—			—		6.72	%		86,082
2007		—			—		5.51	%		867
2008		—			—		5.51	%		1,054
2009		—			—		5.51	%		818
Years thereafter		1.89	%		565,860		4.79	%		1,669,901
Total				$	565,860				$	2,160,449
Fair value				$	565,799				$	2,254,061

Commodity Price Risk

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

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     The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:

• Regulated Electricity – non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and

• Marketing and Trading – non-trading and trading derivative instruments of our competitive business segment.

     The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions in 2005 and 2004 (dollars in millions):

	2005						2004
	Regulated			Marketing and			Regulated			Marketing and
	Electricity			Trading			Electricity			Trading
Mark-to-market of net positions at beginning of period	$	33		$	107		$	—		$	69
Recognized in earnings:
Change in mark-to-market gains for future period deliveries		14			20			9			20
Mark-to-market (gains) losses realized including ineffectiveness during the period		(8	)		(14	)		3			(15	)
Deferred as a regulatory liability		31			—			—			—
Recognized in OCI:
Change in mark-to-market gains for future period deliveries (a)		359			102			42			37
Mark-to-market gains realized during the period		(94	)		(34	)		(21	)		(6	)
Change in valuation techniques		—			—			—			2
Mark-to-market of net positions at end of period	$	335		$	181		$	33		$	107

(a) The increase in regulated mark-to-market recorded in OCI is due primarily to increases in forward natural gas prices.

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     The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at December 31, 2005 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” for more discussion of our valuation methods.

Regulated Electricity

																			Total
																Years			fair
Source of Fair Value	2006			2007			2008			2009			2010			thereafter			value
Prices actively quoted	$	162		$	58		$	39		$	7		$	—		$	—		$	266
Prices provided by other external sources		21			61			1			—			—			—			83
Prices based on models and other valuation methods		(3	)		(2	)		(1	)		(2	)		(1	)		(5	)		(14	)
Total by maturity	$	180		$	117		$	39		$	5		$	(1	)	$	(5	)	$	335

Marketing and Trading

																	Total
															Years		fair
Source of Fair Value	2006			2007			2008		2009			2010			thereafter		value
Prices actively quoted	$	22		$	—		$	—	$	(1	)	$	(1	)	$	—	$	20
Prices provided by other external sources		76			87			20		—			—			—		183
Prices based on models and other valuation methods		(26	)		(12	)		16		(1	)		(1	)		2		(22	)
Total by maturity	$	72		$	75		$	36	$	(2	)	$	(2	)	$	2	$	181

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     The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets at December 31, 2005 and 2004 (dollars in millions).

	December 31, 2005					December 31, 2004
	Gain (Loss)					Gain (Loss)
	Price Up 10%		Price Down 10%			Price Up 10%			Price Down 10%
Mark-to-market changes reported in earnings (a):
Electricity	$	—	$	—		$	(4	)	$	4
Natural gas		—		—			2			(2	)
Other		—		—			1			(1	)
Mark-to-market changes reported in OCI (b):
Electricity		66		(66	)		35			(35	)
Natural gas		103		(103	)		43			(43	)
Total	$	169	$	(169	)	$	77		$	(77	)

(a)	These contracts are primarily structured sales activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.
(b)	These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

Credit Risk

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

ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS

General

     Throughout the following explanations of our results of operations, we refer to “gross margin.” Gross margin refers to electric operating revenues less fuel and purchased power costs. Gross margin is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.30 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior-period amounts to conform to our current-period presentation.

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Deferred Fuel and Purchased Power Costs

     The settlement of APS’ 2003 general retail rate case became effective April 1, 2005. As part of the settlement, the ACC approved a 4.2% annual retail rate increase and the PSA, which provides mechanisms for adjusting rates to reflect variations in fuel and purchased power costs. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual fuel and purchased power costs, net of Off-System Sales margins, and the amount for such costs currently included in base rates. The current base rate for fuel and purchased power costs is based on 2003 price levels and spot prices for natural gas and wholesale power have increased over 40% since then. Although APS defers actual fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual PSA adjustments and ACC approval of periodic surcharge applications.

     Actual fuel and purchased power costs are higher than in prior periods primarily due to higher fuel prices and increased plant outage days.

     APS’ pretax PSA deferrals were approximately $173 million at December 31, 2005. Based on recent forward market prices for natural gas and purchased power (which are subject to change), and assuming no interim rate relief, APS estimates that its pretax PSA deferrals in 2006 will be approximately $240 million to $250 million. In January 2006, the ACC approved the first annual adjustment under the PSA mechanism, which is expected to recover approximately $110 million of the 2005 balance of $173 million from retail customers over twelve months beginning February 1, 2006. In this same order, the ACC granted APS the authority to continue to defer fuel costs in excess of the $776.2 million annual fuel cost cap established in the 2005 rate order and to seek recovery of those amounts in a future proceeding. On February 2, 2006, APS filed a request with the ACC to recover the remainder of the retail portion of the 2005 deferred fuel balance of $173 million — approximately $60 million — through two surcharges. The first surcharge is to recover $15 million over a twelve-month period proposed to begin with the date of the ACC’s decision in APS’ pending emergency interim rate case. The second surcharge is to recover approximately $45 million over a twelve-month period proposed to begin no later than the ACC’s completion of its inquiry regarding unplanned 2005 outages at Palo Verde. The $45 million of PSA deferrals represents additional replacement power costs associated with these outages. See Note 3. See “Overview” in this Item 7 for information about Palo Verde Unit 1 operating at reduced power levels and the related economic impact.

2005 Compared with 2004

     APS’ net income for 2005 was $170 million compared with $200 million for the prior year. The $30 million decrease was primarily due to the regulatory disallowance of plant costs in accordance with the APS retail rate case settlement; higher fuel and purchased power costs primarily due to higher prices and more plant outage days; higher operations and maintenance expense related to generation and customer service costs; and higher property taxes due to increased plant in service. These negative factors were partially offset by deferred fuel and purchased power costs; a retail price increase effective April 1, 2005; higher retail sales volumes due to customer growth; lower depreciation due to lower depreciation rates; lower regulatory asset amortization; and effects of weather on retail sales.

     Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

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	Increase (Decrease)
	Pretax			After Tax
Gross margin:
Deferred fuel and purchased power costs	$	171		$	104
Retail price increase effective April 1, 2005		65			40
Higher retail sales volumes due to customer growth, excluding weather effects		58			35
Effects of weather on retail sales		14			9
Higher fuel and purchased power costs primarily due to higher prices and more plant outage days		(146	)		(89	)
Miscellaneous items, net		(14	)		(9	)
Net increase in gross margin		148			90
Regulatory disallowance, in accordance with the retail rate settlement		(139	)		(84	)
Operations and maintenance increases primarily due to:
Customer service costs, including regulatory demand-side management programs and planned maintenance		(22	)		(13	)
Generation costs, including planned maintenance and overhauls		(16	)		(10	)
Costs of PWEC Dedicated Assets not included in prior year		(14	)		(9	)
Depreciation and amortization decreases primarily due to:
Lower regulatory asset amortization		22			13
Higher depreciable assets due to transfer of PWEC
Dedicated Assets, partially offset by lower depreciation rates		(11	)		(7	)
Higher property taxes due to increased plant in service		(12	)		(7	)
Miscellaneous items, net		(7	)		(3	)
Net decrease in net income	$	(51	)	$	(30	)

Regulated Electricity Revenues

     Regulated electricity revenues were $193 million higher for 2005 compared with the prior year primarily as a result of:

• an $81 million increase in retail revenues related to customer growth, excluding weather effects;

• a $65 million increase in retail revenues due to a price increase effective April 1, 2005;

• a $40 million increase in Off-System Sales primarily resulting from sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in regulated electricity in accordance with the APS retail rate case settlement;

• an $11 million increase in retail revenues related to weather; and

• a $4 million decrease due to miscellaneous factors.

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     Marketing and Trading Revenues

     Marketing and trading revenues were $120 million lower for 2005 compared with the prior-year period primarily as a result of:

• a $69 million decrease in energy trading revenues on realized sales of electricity primarily due to lower delivered electricity prices and lower volumes;

• a $40 million decrease in Off-System Sales due to the absence of sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in regulated electricity in accordance with the APS retail rate case settlement; and

• an $11 million decrease on future mark-to-market gains due to higher prices.

2004 Compared with 2003

     APS’ net income for 2004 was $200 million compared with $181 million for the prior year. The $19 million increase in the period-to-period comparison reflects lower regulatory asset amortization; the benefit of customer growth; decreased purchased power and fuel costs primarily due to lower prices for capacity purchases; increased interest income and lower replacement power costs due to fewer unplanned outages. These positive factors were partially offset by increased operations and maintenance costs related to increased generation, customer service and personnel costs; the effects of weather on retail sales; higher depreciation and amortization related to increased delivery and other assets; lower realized margins on energy trading due to higher wholesale electricity prices; a retail electricity price reduction; lower income tax credits; and higher interest expense primarily due to increased utility plant in service.

     Additional details on the major factors that increased (decreased) net income for 2004 compared with the prior year are contained in the following table (dollars in millions).

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	Increase (Decrease)
	Pretax			After Tax
Gross margin:
Higher retail sales volumes due to customer growth, excluding weather effects	$	43		$	26
Decreased purchased power and fuel costs primarily due to lower prices for capacity purchases		30			18
Lower replacement power costs due to fewer unplanned outages		6			4
Effects of weather on retail sales		(17	)		(10	)
Lower margins on energy trading primarily due to higher wholesale electricity prices		(14	)		(9	)
Retail electricity price reduction effective July 1, 2003		(13	)		(8	)
Miscellaneous factors, net		(3	)		(2	)
Net increase in gross margin		32			19
Higher operations and maintenance expense primarily related to increased generation, customer service, and personnel costs		(27	)		(16	)
Higher interest expense primarily due to increased utility plant in service		(10	)		(6	)
Depreciation and amortization decreases (increases):
Lower regulatory asset amortization		68			41
Increased delivery and other assets		(16	)		(10	)
Higher other income primarily due to increased interest income		10			6
Lower income tax credits		—			(11	)
Miscellaneous items, net		(6	)		(4	)
Net increase in net income	$	51		$	19

Regulated Electricity Revenues

     Regulated electricity revenues were $52 million higher in 2004 compared with the prior year, primarily as a result of:

• an $101 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;

• a $42 million decrease in retail revenues related to weather;

• a $13 million decrease in retail revenues related to a reduction in retail electricity prices; and

• a $6 million increase due to miscellaneous factors.

Marketing and Trading Revenues

     Marketing and trading revenues were $40 million higher in 2004 compared with the prior year, primarily as a result of:

• a $13 million decrease from Off-System Sales due to substantially lower sales volumes, resulting from lower market spark spreads;

63

• $49 million of higher energy trading revenues on realized sales of electricity primarily due to higher electricity prices; and

• $4 million in higher mark-to-market gains for future-period deliveries primarily as a result of higher forward prices for wholesale electricity.

LIQUIDITY AND CAPITAL RESOURCES – ARIZONA PUBLIC SERVICE COMPANY

     Contractual Obligations

     The following table summarizes contractual requirements for APS as of December 31, 2005 (dollars in millions):

			2007-		2009-		There-
	2006		2008		2010		after		Total
Long-term debt payments, including interest (a)	$	219	$	259	$	480	$	3,350	$	4,308
Capital lease payments		2		2		2		2		8
Operating lease payments		66		129		122		288		605
Purchase power and fuel commitments (b)		265		331		256		896		1,748
Minimum pension funding requirement (c)		36		—		—		—		36
Purchase obligations (d)		25		9		—		75		109
Nuclear decommissioning funding requirements		21		42		46		259		368
Total contractual commitments	$	634	$	772	$	906	$	4,870	$	7,182

(a)	The long-term debt matures at various dates through 2035 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by the rates at December 31, 2005.
(b)	APS’ purchase power and fuel commitments include purchases of coal, electricity, natural gas, and nuclear fuel (see Note 11).
(c)	Future pension contributions are not determinable for time periods after 2006.
(d)	These contractual obligations include commitments for capital expenditures and other obligations.

64

ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK

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

65

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE

	Page
Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)	67
Report of Independent Registered Public Accounting Firm	68
Pinnacle West Consolidated Statements of Income for 2005, 2004 and 2003	70
Pinnacle West Consolidated Balance Sheets as of December 31, 2005 and 2004	71
Pinnacle West Consolidated Statements of Cash Flows for 2005, 2004 and 2003	73
Pinnacle West Consolidated Statements of Changes in Common Stock Equity for 2005, 2004 and 2003	74
Notes to Pinnacle West’s Consolidated Financial Statements	75
Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)	126
Report of Independent Registered Public Accounting Firm	127
APS Statements of Income for 2005, 2004 and 2003	129
APS Balance Sheets as of December 31, 2005 and 2004	130
APS Statements of Cash Flows for 2005, 2004 and 2003	132
APS Statements of Changes in Common Stock Equity for 2005, 2004 and 2003	133
Supplemental Notes to APS’ Financial Statements	135
Financial Statement Schedule for 2005, 2004 and 2003
Pinnacle West Schedule II – Valuation and Qualifying Accounts for 2005, 2004 and 2003	143
APS Schedule II –Reserve for Uncollectibles for 2005, 2004 and 2003	144

See Note 13 for the selected quarterly financial data required to be presented in this Item.

66

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

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13(a)-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework inInternal Control – Integrated Framework,our management concluded that our internal control over financial reporting was effective as of December 31, 2005. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s consolidated financial statements.

March 8, 2006

67

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

68

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP
Phoenix, Arizona

March 8, 2006

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(dollars and shares in thousands, except per share amounts)

	Year Ended December 31,
	2005			2004			2003
OPERATING REVENUES
Regulated electricity segment	$	2,237,145		$	2,035,247		$	1,978,075
Marketing and trading segment		351,558			400,628			391,196
Real estate segment		338,031			350,315			361,604
Other revenues		61,221			42,816			27,929
Total		2,987,955			2,829,006			2,758,804
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		595,141			567,433			517,320
Marketing and trading segment fuel and purchased power		293,091			320,667			344,862
Operations and maintenance		635,827			592,320			548,732
Real estate segment operations		278,366			284,194			305,974
Depreciation and amortization		347,652			391,597			435,140
Taxes other than income taxes		132,040			120,722			110,270
Other expenses		51,987			34,108			23,254
Regulatory disallowance (Note 3)		138,562			—			—
Total		2,472,666			2,311,041			2,285,552
OPERATING INCOME		515,289			517,965			473,252
OTHER
Allowance for equity funds used during construction		11,191			4,885			14,240
Other income (Note 19)		23,360			53,289			35,563
Other expense (Note 19)		(26,716	)		(21,340	)		(20,574	)
Total		7,835			36,834			29,229
INTEREST EXPENSE
Interest charges		185,087			183,527			193,973
Capitalized interest		(12,018	)		(11,460	)		(19,078	)
Total		173,069			172,067			174,895
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		350,055			382,732			327,586
INCOME TAXES		126,892			136,142			102,202
INCOME FROM CONTINUING OPERATIONS		223,163			246,590			225,384
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of ($29,797), ($1,805) and $9,887		(46,896	)		(3,395	)		15,195
NET INCOME	$	176,267		$	243,195		$	240,579
WEIGHTED-AVERAGE COMMON SHARES
OUTSTANDING – BASIC		96,484			91,397			91,265
WEIGHTED-AVERAGE COMMON SHARES
OUTSTANDING DILUTED		96,590			91,532			91,405
EARNINGS PER WEIGHTED – AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	2.31		$	2.70		$	2.47
Net income – basic		1.83			2.66			2.64
Income from continuing operations – diluted		2.31			2.69			2.47
Net income – diluted		1.82			2.66			2.63
DIVIDENDS DECLARED PER SHARE	$	1.925		$	1.825		$	1.725

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2005			2004
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	154,003		$	163,366
Investment in debt securities		—			181,175
Customer and other receivables		502,681			461,090
Allowance for doubtful accounts		(4,979	)		(4,896	)
Materials and supplies (at average cost)		109,736			101,333
Fossil fuel (at average cost)		23,658			20,512
Assets from risk management and trading activities (Note 18)		827,779			166,896
Assets held for sale (Note 22)		202,645			—
Other current assets		75,869			47,654
Total current assets		1,891,392			1,137,130
INVESTMENTS AND OTHER ASSETS
Real estate investments – net (Notes 1 and 6)		390,702			382,398
Assets from long-term risk management and trading activities (Note 18)		597,831			224,341
Decommissioning trust accounts (Note 12)		293,943			267,700
Other assets		111,931			107,212
Total investments and other assets		1,394,407			981,651
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
Plant in service and held for future use		10,727,695			10,486,648
Less accumulated depreciation and amortization		3,622,884			3,365,954
Total		7,104,811			7,120,694
Construction work in progress		327,172			258,119
Intangible assets, net of accumulated amortization of $182,576 and $158,584		90,916			105,486
Nuclear fuel, net of accumulated amortization of $53,984 and $59,020		54,184			51,188
Net property, plant and equipment		7,577,083			7,535,487
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Notes 1, 3 and 4)		172,756			—
Other regulatory assets (Notes 1, 3 and 4)		151,123			135,051
Other deferred debits		135,884			107,428
Total deferred debits		459,763			242,479
TOTAL ASSETS	$	11,322,645		$	9,896,747

See Notes to Pinnacle West’s Consolidated Financial Statements.

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

	December 31,
	2005			2004
LIABILITIES AND COMMON STOCK EQUITY
CURRENT LIABILITIES
Accounts payable	$	377,107		$	373,526
Accrued taxes		289,235			245,611
Accrued interest		31,774			38,795
Short-term borrowings (Note 5)		15,673			71,030
Current maturities of long-term debt (Note 6)		384,947			617,165
Customer deposits		60,509			55,558
Deferred income taxes (Note 4)		94,710			9,057
Liabilities from risk management and trading activities (Note 18)		720,693			113,406
Other current liabilities		297,425			101,748
Total current liabilities		2,272,073			1,625,896
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)		2,608,455			2,584,985
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)		1,225,253			1,227,553
Regulatory liabilities (Notes 1, 3 and 4)		592,494			506,646
Liability for asset retirements (Note 12)		269,011			251,612
Pension liability (Note 8)		264,476			234,445
Liabilities from risk management and trading activities (Note 18)		256,413			156,262
Unamortized gain – sale of utility plant (Note 9)		45,757			50,333
Other		363,749			308,819
Total deferred credits and other		3,017,153			2,735,670
COMMITMENTS AND CONTINGENCIES (Notes 3, 11, 12 and 21)
COMMON STOCK EQUITY (Note 7)
Common stock, no par value; authorized 150,000,000 shares; issued 99,077,133 at end of 2005 and 91,802,861 at end of 2004		2,067,377			1,769,047
Treasury stock at cost; 20,058 shares at end of 2005 and 9,522 shares at end of 2004		(1,245	)		(428	)
Total common stock		2,066,132			1,768,619
Accumulated other comprehensive income (loss):
Minimum pension liability adjustment		(97,277	)		(81,788	)
Derivative instruments		262,397			59,243
Total accumulated other comprehensive income (loss)		165,120			(22,545	)
Retained earnings		1,193,712			1,204,122
Total common stock equity		3,424,964			2,950,196
TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	11,322,645		$	9,896,747

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2005			2004 (a)			2003 (a)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	176,267		$	243,195		$	240,579
Adjustments to reconcile net income to net cash provided by operating activities:
Silverhawk impairment loss		91,025			—			—
Regulatory disallowance		138,562			—			—
Equity earnings in Phoenix Suns partnership		—			(34,594	)		—
Depreciation and amortization including nuclear fuel		381,604			432,161			466,900
Deferred fuel and purchased power		(172,756	)		—			—
Allowance for equity funds used during construction		(11,191	)		(4,885	)		(14,240	)
Deferred income taxes		(23,806	)		(113,850	)		85,462
Change in mark-to-market valuations		(11,670	)		(18,915	)		17,410
Changes in current assets and liabilities:
Customer and other receivables		(38,763	)		(11,056	)		2,346
Materials, supplies and fossil fuel		(16,836	)		2,621			(4,629	)
Other current assets		(28,215	)		25,380			(6,646	)
Accounts payable		(6,392	)		85,344			(34,303	)
Accrued taxes		43,624			175,842			(1,338	)
Other current liabilities		1,567			10,561			3,725
Proceeds from the sale of real estate assets		16,218			80,035			130,597
Real estate investments		(88,055	)		(62,812	)		(51,837	)
Change in risk management and trading – assets		(62,100	)		(2,549	)		46,911
Change in risk management and trading – liabilities		110,393			13,018			(11,613	)
Collateral		192,040			12,619			(10,453	)
Change in other long-term assets		(35,793	)		(36,666	)		(6,099	)
Change in other long-term liabilities		74,573			55,443			49,251
Net cash flow provided by operating activities		730,296			850,892			902,023
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(633,532	)		(538,842	)		(713,256	)
Purchase of Sundance Plant		(185,046	)		—			—
Proceeds from sale of Silverhawk		—			90,967			—
Capitalized interest		(12,018	)		(16,311	)		(29,444	)
Proceeds from the sale of the Phoenix Suns partnership		—			23,101			—
Purchases of investment securities		(2,962,278	)		(1,040,955	)		(877,660	)
Proceeds from sale of investment securities		3,143,481			951,630			785,810
Proceeds from nuclear decommissioning trust sales		186,215			123,795			168,874
Investment in nuclear decommissioning trust		(204,633	)		(135,239	)		(180,319	)
Proceeds from real estate investments		82,719			—			46,781
Other		—			(3,072	)		(9,595	)
Net cash flow used for investing activities		(585,092	)		(544,926	)		(808,809	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		1,088,815			478,328			656,850
Short-term borrowings and payments – net		(46,413	)		(15,051	)		(173,303	)
Dividends paid on common stock		(186,677	)		(166,772	)		(157,417	)
Repayment of long-term debt		(1,288,034	)		(604,015	)		(368,162	)
Common stock equity issuance		298,168			18,291			—
Other		(20,426	)		9,690			8,181
Net cash flow used for financing activities		(154,567	)		(279,529	)		(33,851	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(9,363	)		26,437			59,363
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		163,366			136,929			77,566
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	154,003		$	163,366		$	136,929
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid, net of refunds	$	86,711		$	66,447		$	32,816
Interest paid, net of amounts capitalized	$	181,975		$	191,865		$	161,581

See Notes to Pinnacle West’s Consolidated Financial Statements.

(a) See “Cash and Cash Equivalents” in Note 1 for information regarding revisions and certain reclassifications of prior year amounts.

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PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(dollars in thousands)

	Year Ended December 31,
	2005			2004			2003
COMMON STOCK (Note 7)
Balance at beginning of year	$	1,769,047		$	1,744,354		$	1,737,258
Issuance of common stock		298,330			18,291			—
Other		—			6,402			7,096
Balance at end of year		2,067,377			1,769,047			1,744,354
TREASURY STOCK (Note 7)
Balance at beginning of year		(428	)		(3,273	)		(4,358	)
Purchase of treasury stock		(1,601	)		(2,986	)		—
Reissuance of treasury stock used for stock compensation, net		784			5,831			1,085
Balance at end of year		(1,245	)		(428	)		(3,273	)
RETAINED EARNINGS
Balance at beginning of year		1,204,122			1,127,699			1,044,537
Net income		176,267			243,195			240,579
Common stock dividends		(186,677	)		(166,772	)		(157,417	)
Balance at end of year		1,193,712			1,204,122			1,127,699
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year		(22,545	)		(39,001	)		(91,284	)
Minimum pension liability adjustment, net of tax expense (benefit) of ($9,526), ($9,756) and $3,700		(15,489	)		(15,224	)		4,700
Unrealized gain on derivative instruments, net of tax expense of $179,927, $31,117 and $33,298		281,019			48,226			51,089
Reclassification of realized gain to income, net of tax benefit of ($50,056), ($10,695) and ($2,343)		(77,865	)		(16,546	)		(3,506	)
Balance at end of year		165,120			(22,545	)		(39,001	)
TOTAL COMMON STOCK EQUITY	$	3,424,964		$	2,950,196		$	2,829,779
COMPREHENSIVE INCOME
Net income	$	176,267		$	243,195		$	240,579
Other comprehensive income		187,665			16,456			52,283
Comprehensive income	$	363,932		$	259,651		$	292,862

See Notes to Pinnacle West’s Consolidated Financial Statements.

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Consolidation and Nature of Operations

     Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally NAC). See Note 22 for a discussion of the sale of NAC in November 2004. Significant intercompany accounts and transactions between the consolidated companies have been eliminated.

     APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. Pinnacle West Energy, which was formed in 1999, was the subsidiary through which we conducted our unregulated generation operations. See Note 3 for a discussion of the transfer of the PWEC Dedicated Assets from Pinnacle West Energy to APS. As of January 10, 2006, Pinnacle West Energy no longer owns any generating plants and has ceased operations. APS Energy Services was formed in 1998 and provides competitive commodity energy and energy-related products to key customers in competitive markets in the western United States. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. El Dorado is an investment firm.

Accounting Records and Use of Estimates

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

Derivative Accounting

     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

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

75

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

recognized in income are eligible to be recovered through the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings. SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard. Contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.

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

     We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted.

     When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers, which we convert into monthly prices using historical relationships.

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

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

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

     The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities

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hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.

     See Note 18 for additional information about our derivative and energy trading accounting policies.

Regulatory Accounting

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

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

     A 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.

     As part of a 1999 retail rate case settlement agreement, APS amortized certain regulatory assets over a period that ended June 30, 2004. Amortization was $18 million in 2004 and $86 million in 2003.

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

	December 31,
	2005		2004
Deferred fuel and purchased power (Note 3)	$	173	$	—
Competition rules compliance charge		42		50
Deferred compensation		25		24
Regulatory asset for deferred income taxes		19		12
Loss on reacquired debt (a)		18		17
Capital contributions on the Mead-Phoenix transmission line		14		13
Coal reclamation		13		—
Bark beetle remediation		6		—
Spent nuclear fuel storage (Note 11)		6		11
Other		8		8
Total regulatory assets	$	324	$	135

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     (a) See “Reacquired Debt Costs” below.

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

	December 31,
	2005		2004
Removal costs (a)	$	385	$	376
Regulatory liability related to asset retirement obligations		101		86
Deferred fuel and purchased power – mark-to-market		31		—
Regulatory liability for deferred income taxes		24		—
Deferred interest income		22		22
Deferred gains on utility property		20		20
Demand-side management		7		—
Other		2		3
Total regulatory liabilities	$	592	$	507

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

Utility Plant and Depreciation

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

• material and labor;

• contractor costs;

• capitalized leases;

• construction overhead costs (where applicable); and

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

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

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

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     We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2005 were as follows:

• Fossil plant – 19 years;

• Nuclear plant – 20 years;

• Other generation – 28 years;

• Transmission – 40 years;

• Distribution – 32 years; and

• Other – 6 years.

     For the years 2003 through 2005, the depreciation rates ranged from a low of 1.2% to a high of 11.43%. The weighted-average rate was 3.0% for 2005, 3.36% for 2004 and 3.35% for 2003. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 years. See “APS 2003 Rate Case” in Note 3 for a discussion of changes in depreciation rates.

Investments

     El Dorado accounts for its investments using the equity (if significant influence) and cost (less than 20% ownership) methods. See Note 22 for a discussion of the sale of NAC.

     The Company’s investments are reviewed in accordance with EITF 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.”

Capitalized Interest

     Capitalized interest represents the cost of debt funds used to finance non-regulated construction projects. The rate used to calculate capitalized interest was a composite rate of 5.7% for 2005, 4.9% for 2004 and 4.7% for 2003. Capitalized interest ceases to accrue when construction is complete.

Allowance for Funds Used During Construction

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

     AFUDC was calculated by using a composite rate of 7.7% for 2005, 8.4% for 2004 and 8.6% for 2003. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Electric Revenues

     We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of

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electricity are generally recorded when service is rendered or electricity is delivered to customers. However, the determination and billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers since the date of the last meter reading and billing and the corresponding unbilled revenue are estimated. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Beginning April 2005 in accordance with the order in the APS 2003 Rate Case, we exclude city franchise fees from both electric revenues and operating expenses.

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

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

Real Estate Revenues

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

Real Estate Investments

     Real estate investments primarily include SunCor’s land, home inventory and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except that, to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting. In addition, see Note 22 – Discontinued Operations.

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Cash and Cash Equivalents

     We consider all highly liquid investments with an initial maturity of three months or less to be cash equivalents.

     We have investments in auction rate securities in which interest rates are reset on a short-term basis; however, the underlying contract maturity dates extend beyond three months. We classify the investments in auction rate securities as investment in debt securities on our Consolidated Balance Sheets.

     We have changed the presentation of our nuclear decommissioning trust investment in our Consolidated Statements of Cash Flows for the year ended December 31, 2005, to present investing cash outflows separately from investing cash inflows. Investing cash inflows and outflows in the nuclear decommissioning trust investment amounts were previously presented in Other within the investing section of the Consolidated Statements of Cash Flows. In addition, we changed the presentation of prior year amounts in order to be consistent with the 2005 presentation. There was no impact to net cash provided by (used in) operating, investing or financing activities as a result of this change in presentation.

     During 2005, we revised the presentation of our Consolidated Statements of Cash Flows to include the cash flows from discontinued operations within the categories of operating, investing, and financing activities. A summary of the effects of the change in presentation on the Consolidated Statements of Cash Flows for the years ended December 31, 2004 and 2003, is as follows (dollars in millions):

	Year Ended December 31,
	2004			2003
Net cash flows from operating activities as previously reported	$	842		$	901
Change in net cash flows from discontinued operations		9			1
Net cash flows from operating activities as currently reported	$	851		$	902
Net cash flows used for investing activities as previously reported	$	(532	)	$	(815	)
Change in net cash flows used for discontinued operations		(13	)		6
Net cash flows used for investing activities as currently reported	$	(545	)	$	(809	)
Net cash flows used for financing activities as previously reported	$	(278	)	$	(32	)
Change in net cash flows used for discontinued operations		(2	)		(2	)
Net cash flows used for financing activities as currently reported	$	(280	)	$	(34	)

Nuclear Fuel

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

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

Income Taxes

     Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes.” We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each subsidiary as though each subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. See Note 4.

Reacquired Debt Costs

     APS defers gains and losses incurred upon early retirement of debt. These costs are amortized equally on a monthly basis over the remaining life of the original debt consistent with its ratemaking treatment.

Stock-Based Compensation

     We apply the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” The fair value method of accounting is the preferred method. In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” In addition, SFAS No. 123R is effective for us as of January 1, 2006. We have evaluated the impacts of this new guidance and do not believe it will have a material impact on our financial statements.

     The following chart compares our net income, stock compensation expense and earnings per share to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through 2005 (dollars in thousands, except per share amounts):

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	2005			2004			2003
Net Income as reported:	$	176,267		$	243,195		$	240,579
Add: Stock compensation expense included in reported net income (net of tax)		3,738			4,690			3,514
Deduct: Total stock compensation expense determined under fair value method (net of tax)		(3,738	)		(5,311	)		(5,220	)
Pro forma net income	$	176,267		$	242,574		$	238,873
Earnings per share – basic:
As reported	$	1.83		$	2.66		$	2.64
Pro forma (fair value method)	$	1.83		$	2.65		$	2.62
Earnings per share – diluted:
As reported	$	1.82		$	2.66		$	2.63
Pro forma (fair value method)	$	1.82		$	2.65		$	2.61

     In order to calculate the fair value of the 2004 and 2003 stock option grants (no stock options were granted in 2005) and the pro forma information above, we calculated the fair value of each stock option granted under the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated as of the date the option was granted. The following weighted-average assumptions were used to calculate the fair value of the stock options:

	2004			2003
Risk-free interest rate		3.15	%		3.35	%
Dividend yield		4.76	%		5.26	%
Volatility		17.04	%		38.03	%
Expected life (months)		60			60

     See Note 16 for further discussion about our stock compensation plans.

Intangible Assets

     We have no goodwill recorded and have separately disclosed other intangible assets, primarily software, on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. Amortization expense was $33 million in 2005, $34 million in 2004, and $25 million in 2003. Estimated amortization expense on existing intangible assets over the next five years is $31 million in 2006, $25 million in 2007, $14 million in 2008, $4 million in 2009, and $3 million in 2010. At December 31, 2005, the weighted average remaining amortization period for intangible assets is 3 years.

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2. New Accounting Standards

     In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” The standard establishes accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. In 2002, we began accounting for stock-based compensation using the fair value method. We adopted SFAS No. 123R on January 1, 2006. We believe the impacts of this new guidance on our financial statements will be immaterial.

     Effective December 31, 2005, we adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143.” FIN 47 clarifies that an entity must record a liability for the fair value of an asset retirement obligation for which the timing and/or method of settlement are conditional on a future event if the liability’s fair value can be reasonably estimated. We have evaluated our asset retirement obligations under this new guidance and determined that no additional liabilities need to be recorded at this time.

3. Regulatory Matters

APS General Rate Case

     On January 31, 2006, APS filed with the ACC updated financial schedules, testimony and other data in the general rate case that APS originally filed on November 4, 2005. As requested by the ACC staff, the updated information uses the twelve months ended September 30, 2005 as the test period instead of the test year ended December 31, 2004 used in APS’ original filing. As a result of the updated filing, APS is requesting a 21.3%, or $453.9 million, increase in its annual retail electricity revenues effective no later than December 31, 2006. The original filing requested a 19.9%, or $409.1 million, retail rate increase.

     The updated requested rate increase is designed to recover the following (dollars in millions):

	Updated Filing						Original Filing
	(January 31, 2006)						(November 4, 2005)
	Annual						Annual
	Revenue			Percentage			Revenue			Percentage
	Increase			Increase			Increase			Increase
Increased fuel and purchased power	$	299.0			14.0	%	$	246.8			12.0	%
Capital structure update		98.3			4.6	%		96.8			4.7	%
Rate base update, including acquisition of Sundance Plant		46.2			2.2	%		42.5			2.1	%
Pension funding		41.3			1.9	%		41.2			2.0	%
Other items		(30.9	)		(1.4	)%		(18.2	)		(0.9	)%
Total increase	$	453.9			21.3	%	$	409.1			19.9	%

     The request is based on (a) a rate base of $4.4 billion, which approximates the ACC-jurisdictional portion of the book value of utility plant, net of accumulated depreciation, as of

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September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.031904 per kilowatt-hour based on estimated 2006 prices; and (c) a proposed capital structure of 45% long-term debt and 55% common stock equity, with a weighted-average cost of capital of 8.73% (5.41% for long-term debt and 11.50% for common stock equity). The requested increase in annual retail electricity revenues from the original filing is based solely on increased fuel and purchased power costs, slightly offset by other items (see the above chart). If the ACC approves the requested base rate increase for fuel and purchased power costs (see clause (b) of this paragraph), subsequent PSA rate adjustments and/or PSA surcharges would be reduced because such costs would otherwise be eligible for recovery in the future under APS’ PSA.

     The updated request does not include the PSA annual adjustor rate increase of approximately 5% that took effect February 1, 2006 or the application for two separate PSA surcharges that APS filed on February 2, 2006. See “Power Supply Adjustor” below.

Application for Emergency Interim Rate Increase

          On January 6, 2006, APS filed with the ACC an application requesting an emergency interim rate increase of $299 million, or approximately 14%, to be effective April 1, 2006. The purpose of the emergency interim rate increase is solely to address APS’ under-collection of higher annual fuel and purchased power costs. The increase would accelerate recovery of the fuel and purchased power component of APS’ general rate case and is not an additional increase and would be subject to refund. On February 28, 2006, several parties filed direct testimony in this matter. The ACC staff and the Residential Utility Consumer Office each recommended that the ACC deny APS’ request for emergency rate relief, and each cited the ACC’s January 25, 2006 modification of the PSA as a basis for its recommendation (see “Power Supply Adjustor” below). Because “concern continues to exist regarding the build-up of deferred fuel balances in 2006 and the uncertain time frame for recovery of prudently incurred fuel and purchased power costs,” the ACC staff also recommended, among other things, that the ACC allow APS to file for PSA surcharge requests in 2006 on a quarterly basis, with the first request to be filed no earlier than June 30, 2006. A business coalition that advocates on behalf of retail electric customers in Arizona and a major APS customer filed joint testimony recommending that the ACC approve an interim rate increase of $126 million in calendar-year 2006. Hearings on the emergency interim rate increase request are scheduled to begin on March 20, 2006. We cannot predict the outcome of this matter.

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Power Supply Adjustor

     PSA Provisions

     The PSA approved by the ACC in April 2005 as part of APS’ 2003 rate case provides for adjustment of retail rates to reflect variations in retail fuel and purchased power costs. On January 25, 2006, the ACC modified the PSA in certain respects. The PSA, as modified, is subject to specified parameters and procedures, including the following:

• APS will record deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the base fuel amount (currently $0.020743 per kWh);

• the deferrals are subject to a 90/10 sharing arrangement in which APS must absorb 10% of the retail fuel and purchased power costs above the base fuel amount and may retain 10% of the benefit from the retail fuel and purchased power costs that are below the base fuel amount;

• amounts to be recovered or refunded through the annual PSA adjustment are limited to a cumulative plus or minus $0.004 per kWh over the life of the PSA;

• the recoverable amount of annual retail fuel and purchased power costs through current base rates and the PSA was originally capped at $776.2 million; however, the ACC has removed the cap pending the ACC’s final ruling on APS’ pending request to have the cap eliminated or substantially raised;

• the PSA will remain in effect for a minimum five-year period, but the ACC may eliminate the PSA at any time, if appropriate, in the event APS files a rate case before the expiration of the five-year period (which APS did by filing the general rate case noted above) or if APS does not comply with the terms of the PSA; and

• APS is prohibited from requesting PSA surcharges until after the PSA annual adjustor rate has been set each year. The amount available for potential PSA surcharges will be limited to the amount of accumulated deferrals through the prior year-end which are not expected to be recovered through the annual adjustor or any PSA surcharges previously approved by the ACC.

     2006 PSA Annual AdjustorThe effective date of the PSA’s annual adjustor is February 1, and the adjustor rate was set at the maximum $0.004 per kilowatt-hour effective February 1, 2006. The change in the adjustor rate represents a retail rate increase of approximately 5% designed to recover $110 million of deferred fuel and purchased power costs over the twelve-month period beginning February 1, 2006.

     Application for PSA SurchargesOn February 2, 2006, APS filed with the ACC an application for two separate surcharges under the PSA. The surcharges would recover approximately $60 million in retail fuel and purchased power costs deferred by APS in 2005 under the PSA. The combined surcharges would represent a temporary rate increase of approximately 2.6% during the overlapping portion of the twelve-month recovery periods for the two surcharges. The other component of the 2005 PSA deferrals is being recovered under the 2006 PSA annual adjustor

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discussed in the preceding paragraph. The first surcharge would recover approximately $15 million over a twelve-month period, representing a temporary rate increase of approximately 0.66%, proposed to begin with the date of the ACC’s decision in APS’ pending emergency interim rate case. The second requested surcharge would recover approximately $45 million over a twelve-month period, representing a temporary rate increase of approximately 1.9%, proposed to begin no later than the ACC’s completion of its inquiry regarding the unplanned 2005 Palo Verde outages. The $45 million of PSA deferrals represents replacement power costs associated with these outages.

     Proposed Modifications to PSA (Requested In General Rate Case)

     In its pending general rate case, APS has requested the following modifications to the PSA:

• The $0.004 per kWh maximum adjustor rate over the life of the PSA would be eliminated, while the $0.004 per kWh maximum annual change in the adjustor rate would remain in effect;

• The $776.2 million annual limit on the retail fuel and purchased power costs under APS’ current base rates and the PSA would be removed or increased (although APS may defer fuel and purchased power costs above $776.2 million per year pending the ACC’s final ruling on APS’ pending request to have the cap eliminated or substantially raised);

• The current provision that APS is required to file a surcharge application with the ACC after accumulated pretax PSA deferrals equal $50 million and before they equal $100 million would be eliminated, thereby giving APS flexibility in determining when a surcharge filing should be made;

• The costs of renewable energy and capacity costs attributable to purchased power obtained through competitive procurement would be excluded from the existing 90/10 sharing arrangement under which APS absorbs 10% of the retail fuel and purchased power costs above the base fuel amount and retains 10% of the benefit from retail fuel and purchased power costs that are below the base fuel amount; and

• 10% of any realized gains or losses resulting from APS’ hedges of Retail Fuel and Power Costs would be retained or absorbed by APS before being subject to the 90/10 sharing provision under the PSA.

APS 2003 Rate Case

     On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003. In addition to the ACC’s approval of the PSA discussed under “Power Supply Adjustor” above, certain key financial components of the order include:

• APS received an annual retail rate increase of approximately 4.2%, which was effective as of April 1, 2005. This increase does not include the impact of the PSA.

• APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and to rate base the

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PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base disallowance of approximately $150 million. Due to depreciation and other miscellaneous factors, the actual disallowance was $139 million at December 31, 2005. This transfer was completed on July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of approximately $84 million in 2005.

• Effective April 1, 2005, APS adopted longer service lives for certain depreciable assets. This change is expected to have the effect of reducing annual depreciation expense for financial reporting purposes by approximately $30 million. APS also adopted longer service lives for the PWEC Dedicated Assets, which is expected to have the effect of reducing annual depreciation expense for financial reporting purposes by approximately $10 million.

Equity Infusions

     On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consist of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006 (see Note 22). Pinnacle West has made these equity infusions into APS.

Federal

     In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.

4. Income Taxes

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

     APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from the reduction in federal income tax rates as part of the Tax Reform Act of 1986. APS amortizes this amount as the differences reverse.

     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. In 2002, we received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax return. The 2001 federal consolidated income tax return is currently under examination by the IRS. As part of this ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. During 2004 and again in 2005, the current income tax liability was increased, with a

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corresponding decrease to plant-related deferred tax liability, to reflect the expected outcome of this audit. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows.

     The income tax liability accounts reflect the tax and interest associated with the most probable resolution of all known and measurable tax exposures.

     In 2004 and 2003, we resolved certain prior-year issues with the taxing authorities and recorded tax benefits associated with tax credits and other reductions to income tax expense.

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

	Year Ended December 31,
	2005			2004			2003
Current:
Federal	$	107,837		$	200,133		$	22,875
State		13,064			48,054			3,752
Total current		120,901			248,187			26,627
Deferred:
Income from continuing operations		11,930			(113,850	)		81,756
Discontinued operations		(35,736	)		—			3,706
Total deferred		(23,806	)		(113,850	)		85,462
Total income tax expense		97,095			134,337			112,089
Less: income tax expense (benefit) on discontinued operations		(29,797	)		(1,805	)		9,887
Income tax expense – continuing operations	$	126,892		$	136,142		$	102,202

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

	Year Ended December 31,
	2005			2004			2003
Federal income tax expense at 35% statutory rate	$	122,519		$	133,956		$	114,655
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		11,981			14,460			11,493
Credits and favorable adjustments related to prior years resolved in current year		—			(6,138	)		(17,944	)
Medicare Subsidy Part-D (see Note 8)		(2,733	)		(1,778	)		—
Allowance for equity funds used during construction (see Note 1)		(3,694	)		(1,547	)		(4,984	)
Other		(1,181	)		(2,811	)		(1,018	)
Income tax expense – continuing operations	$	126,892		$	136,142		$	102,202

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

	December 31,
	2005			2004
Current liability	$	(94,710	)	$	(9,057	)
Long term liability		(1,225,253	)		(1,227,553	)
Accumulated deferred income taxes – net	$	(1,319,963	)	$	(1,236,610	)

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

	December 31,
	2005			2004
DEFERRED TAX ASSETS
Risk management and trading activities	$	323,696		$	91,021
Regulatory liabilities:
Asset retirement obligation		189,726			182,086
Federal excess deferred income taxes		14,446			16,341
Deferred fuel and purchased power – mark-to-market		11,923			—
Other		29,720			8,282
Pension liability		83,753			91,973
Deferred gain on Palo Verde Unit 2 sale leaseback		17,868			19,816
Other		91,015			70,849
Total deferred tax assets		762,147			480,368
DEFERRED TAX LIABILITIES
Plant-related		(1,426,158	)		(1,516,174	)
Risk management and trading activities		(524,940	)		(146,037	)
Regulatory assets:
Deferred fuel and purchased power		(67,461	)		—
Other		(63,551	)		(54,767	)
Total deferred tax liabilities		(2,082,110	)		(1,716,978	)
Accumulated deferred income taxes – net	$	(1,319,963	)	$	(1,236,610	)

5. Lines of Credit and Short-Term Borrowings

     Pinnacle West had committed lines of credit of $300 million at December 31, 2005 and December 31, 2004, which were available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuance of letters of credit. The current lines mature in December 2010. Pinnacle West had no outstanding borrowings at December 31, 2005 and December 31, 2004. Pinnacle West had approximately $11 million of letters of credit issued under the line at December 31, 2005 ($7 million of which terminated as a result of the sale of Silverhawk – see Note 22) and approximately $13 million of letters of credit issued under the line at December 31, 2004. The commitment fees were 0.15% in 2005 and 0.175% in 2004. Pinnacle West had no commercial paper borrowings outstanding at December 31, 2005 and 2004. All Pinnacle West and APS bank lines of credit and commercial paper agreements are unsecured.

     APS had committed lines of credit with various banks of $400 million at December 31, 2005 and $325 million at December 31, 2004, which were available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including the issuance of letters of credit. The current line matures in December 2010. The commitment fees at December 31, 2005 and 2004 for these lines of credit were 0.11% and 0.15% per annum. APS had no bank borrowings

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outstanding under these lines of credit at December 31, 2005 and 2004. APS had approximately $4.8 million of letters of credit issued under the line at December 31, 2005.

     APS had no commercial paper borrowings outstanding at December 31, 2005 and 2004. By Arizona statute, APS’ short-term borrowings cannot exceed 7% of its total capitalization unless approved by the ACC.

     SunCor had revolving lines of credit totaling $150 million at December 31, 2005 and $90 million at December 31, 2004. The commitment fees were 0.125% in 2005 and 2004. SunCor had $123 million outstanding at December 31, 2005 and $35 million outstanding at December 31, 2004. The weighted-average interest rate was 5.93% at December 31, 2005 and 4.50% at December 31, 2004. Interest was based on LIBOR plus 1.5% for 2005 and LIBOR plus 2% or prime plus 0.5% for 2004. The balance is included in long-term debt on the Consolidated Balance Sheets at December 31, 2005 and it was in short-term debt on the Consolidated Balance Sheets at December 31, 2004. SunCor had other short-term loans in the amount of $16 million at December 31, 2005 and $36 million at December 31, 2004. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.25% and 2.50% or prime plus 1.75% at December 31, 2005 and LIBOR plus 2.5% at December 31, 2004.

6. Long-Term Debt

     Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2005 and 2004 (dollars in thousands):

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						December 31,
	Maturity		Interest
	Dates (a)		Rates			2005			2004
APS
Pollution control bonds (b)		2024-2034		(c	)	$	565,855		$	565,860
Pollution control bonds with senior notes		2029		5.05	%		90,000			90,000
Unsecured notes (d)		2005		6.25	%		—			100,000
Unsecured notes (e)		2005		7.625	%		—			300,000
Unsecured notes		2011		6.375	%		400,000			400,000
Unsecured notes		2012		6.50	%		375,000			375,000
Unsecured notes		2033		5.625	%		200,000			200,000
Unsecured notes		2015		4.650	%		300,000			300,000
Unsecured notes (e)		2014		5.80	%		300,000			300,000
Secured note		2014		6.00	%		1,745			1,900
Senior notes		2006		6.75	%		83,695			83,695
Senior notes (f)		2035		5.50	%		250,000			—
Unamortized discount and premium							(9,151	)		(7,968	)
Capitalized lease obligations		2006-2012		(g	)		8,179			9,854
Subtotal							2,565,323			2,718,341
SUNCOR
Notes payable		2006-2008		(h	)		129,040			15,467
Capitalized lease obligations		2005-2007		8.91	%		266			507
Subtotal							129,306			15,974
PINNACLE WEST
Senior notes (i)		2006		6.40	%		298,518			302,589
Unamortized discount and premium							(29	)		(143	)
Floating rate senior notes		2005		(j	)		—			165,000
Capitalized lease obligations		2005-2007		5.45	%		284			389
Subtotal							298,773			467,835
Total long-term debt							2,993,402			3,202,150
Less current maturities							384,947			617,165
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES						$	2,608,455		$	2,584,985

(a) This schedule does not reflect the timing of redemptions that may occur prior to maturity.

(b) On March 1, 2005, Maricopa County Arizona Pollution Control Corporation issued $164 million of variable interest rate pollution control bonds, 2005 Series A-E, due 2029. The bonds were issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Maricopa County Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Consolidated Balance Sheets.

(c) The weighted-average rate was 3.25% at December 31, 2005 and 1.89% at December 31, 2004. Changes in short-term interest rates would affect the costs associated with this debt.

(d) On January 15, 2005, APS repaid its $100 million 6.25% notes due 2005. APS used cash on hand to repay these notes.

(e) On August 1, 2005, APS repaid $300 million of its 7.625% notes due 2005. APS used cash from the issuance of $300 million 5.8% senior unsecured notes due June 30, 2014.

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PINNACLE WEST CAPITAL CORPORATION
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(f) On August 22, 2005, APS issued $250 million of 5.50% senior notes dues 2035. A portion of the proceeds from the sale of the notes was used for general corporate purposes and, on October 3, 2005, the balance of the proceeds, along with cash on hand, was used to fund the $500 million that APS was obligated to transfer to Pinnacle West Energy in connection with APS’ acquisition of the PWEC Dedicated Assets.

(g) The weighted-average rate was 5.81% at December 31, 2005 and 5.78% at December 31, 2004. Capital leases are included in property, plant and equipment on the Consolidated Balance Sheets for both December 31, 2005 and December 31, 2004.

(h) SunCor had $123 million outstanding at December 31, 2005 under its revolving line of credit. The weighted-average interest rate was 5.93% at December 31, 2005. The remaining amount of approximately $6 million at December 31, 2005 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 0.25% or LIBOR plus 2.00%. There is also a note at a fixed rate of 4.25%.

(i) On January 29, 2004, we entered into a fixed-for-floating interest rate swap transaction related to the $300 million 6.40% senior note. The transaction qualifies as a fair value hedge under SFAS No. 133.

(j) The weighted-average rate was 2.06% at December 31, 2004.

     On February 28, 2006, Pinnacle West entered into an Uncommitted Master Shelf Agreement with Prudential Investment Management, Inc. (“Prudential”) and certain of its affiliates. The agreement provides the terms under which Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential affiliates at any time prior to December 31, 2007. The maturity of notes issued under the agreement cannot exceed five years. Pursuant to the agreement, on February 28, 2006, Pinnacle West issued and sold to Prudential affiliates $175 million aggregate principal amount of its 5.91% Senior Notes, Series A, Due February 28, 2011 (the “Series A Notes”). Pinnacle West will use the proceeds of the Series A Notes to repay at maturity a portion of the $300 million aggregate principal amount of its 6.40% Senior Notes due April 1, 2006 or for other general corporate purposes.

     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt to capitalization ratio. 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 each of Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At December 31, 2005, the ratio was approximately 49% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage is approximately 4 times under APS’ bank financing agreements as of December 31, 2005. 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.

     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, in the event of a further rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

     All of Pinnacle West’s bank 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.

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

Year	Pinnacle West		APS
2006	$	387	$	86
2007		1		1
2008		129		1
2009		1		1
2010		224		224
Thereafter		2,261		2,261

7. Common Stock and Treasury Stock

     Our common stock and treasury stock activity during each of the three years 2005, 2004 and 2003 is as follows (dollars in thousands):

	Common Stock				Treasury Stock
	Shares		Amount		Shares			Amount
Balance at December 31, 2002		91,379,947	$	1,737,258		(124,830	)	$	(4,358	)
Reissuance of treasury stock for stock compensation (net)		—		—		32,815			1,085
Other		—		7,096		—			—
Balance at December 31, 2003		91,379,947		1,744,354		(92,015	)		(3,273	)
Common stock issuance		422,914		18,291		—			—
Purchase of treasury stock		—		—		(80,000	)		(2,986	)
Reissuance of treasury stock for stock compensation (net)		—		—		162,493			5,831
Other		—		6,402		—			—
Balance at December 31, 2004		91,802,861		1,769,047		(9,522	)		(428	)
Common stock issuance (a)		7,274,272		298,330		—			—
Purchase of treasury stock (b)		—		—		(28,124	)		(1,601	)
Reissuance of treasury stock for stock compensation (net)		—		—		17,588			784
Other		—		—		—			—
Balance at December 31, 2005		99,077,133	$	2,067,377		(20,058	)	$	(1,245	)

(a)

On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the net proceeds for general corporate purposes, including making capital contributions to APS, which, in turn, used such funds to pay a portion of the approximately $190 million purchase price to acquire the Sundance Plant and for other capital expenditures incurred to meet the growing needs of APS’ service territory.

(b)

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

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PINNACLE WEST CAPITAL CORPORATION
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8. Retirement Plans and Other Benefits

     Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. Effective January 1, 2003, Pinnacle West sponsored a new account balance plan for all new employees in place of the defined benefit plan and, as of April 1, 2003, the plan was offered as an alternative to the defined benefit plan for all existing employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.

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

     Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date.

     On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy of prescription drug cost. The FASB issued FSP 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” to address the accounting for the effects of the Act. Pinnacle West adopted FSP 106-2 retroactive to the beginning of 2004. The effect of this was to reduce the accumulated postretirement benefit obligation (APBO) at January 1, 2004 by $66 million, and net periodic cost for 2004 by $11 million, as compared with the amount calculated without considering the effects of the subsidy.

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

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PINNACLE WEST CAPITAL CORPORATION
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	Pension									Other Benefits
	2005			2004			2003			2005			2004			2003
Service cost-benefits earned during the period	$	45,027		$	41,207		$	37,662		$	20,913		$	17,557		$	15,858
Interest cost on benefit obligation		87,189			81,873			76,951			34,223			29,488			30,163
Expected return on plan assets		(88,403	)		(78,790	)		(65,046	)		(30,471	)		(24,773	)		(18,762	)
Amortization of:
Transition (asset) obligation		(3,227	)		(3,227	)		(3,227	)		3,005			3,005			3,005
Prior service cost (credit)		2,401			2,401			2,401			(125	)		(125	)		(125	)
Net actuarial loss		19,810			17,946			18,135			9,243			7,414			9,714
Net periodic benefit cost	$	62,797		$	61,410		$	66,876		$	36,788		$	32,566		$	39,853
Portion of cost charged to expense	$	26,375		$	25,792		$	30,094		$	15,451		$	13,678		$	17,934
APS share of costs charged to expense	$	24,169		$	22,483		$	25,450		$	14,159		$	11,923		$	15,166

     The following table shows the plans’ changes in the benefit obligations for the years 2005 and 2004 (dollars in thousands):

	Pension						Other Benefits
	2005			2004			2005			2004
Benefit obligation at January 1	$	1,454,244		$	1,307,628		$	536,213		$	540,181
Service cost		45,027			41,207			20,913			17,557
Interest cost		87,189			81,873			34,223			29,488
Benefit payments		(46,109	)		(45,195	)		(16,962	)		(14,332	)
Actuarial losses (gains)		55,717			68,731			11,291			(36,681	)
Benefit obligation at December 31	$	1,596,068		$	1,454,244		$	585,678		$	536,213

     The following table shows the qualified pension plan and other benefit plan changes in the fair value of plan assets for the years 2005 and 2004 (dollars in thousands):

	Pension						Other Benefits
	2005			2004			2005		2004
Fair value of plan assets at January 1	$	982,282		$	887,311		$	352,084	$	294,051
Actual return on plan assets		73,298			102,829			27,302		32,433
Employer contributions		52,700			35,000			36,788		32,600
Benefit payments		(43,432	)		(42,858	)		—		(7,000	)
Fair value of plan assets at December 31	$	1,064,848		$	982,282		$	416,174	$	352,084

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The following table shows a reconciliation of the funded status of the plans to the amounts recognized on the Consolidated Balance Sheets as of December 31, 2005 and 2004 (dollars in thousands):

	Pension						Other Benefits
	2005			2004			2005			2004
Funded status at December 31	$	(531,220	)	$	(471,962	)	$	(169,504	)	$	(184,129	)
Unrecognized net transition (asset) obligation		(645	)		(3,873	)		21,034			24,039
Unrecognized prior service cost (credit)		11,833			14,234			(1,296	)		(1,422	)
Unrecognized net actuarial losses		426,991			375,980			170,011			158,271
Benefit (liability) asset recognized in the Consolidated Balance Sheets	$	(93,041	)	$	(85,621	)	$	20,245		$	(3,241	)

     The following table shows the projected benefit obligation and the accumulated benefit obligation for pension plans in excess of plan assets as of December 31, 2005 and 2004 (dollars in thousands):

	2005		2004
Projected benefit obligation	$	1,596,068	$	1,454,244
Accumulated benefit obligation	$	1,329,324	$	1,216,727
Less fair value of plan assets		1,064,848		982,282
Pinnacle West pension liability	$	264,476	$	234,445
APS share of pension liability	$	233,342	$	203,668

     The following table shows the details related to benefits included on the Consolidated Balance Sheets as of December 31, 2005 and 2004 (dollars in thousands):

	Pension						Other Benefits
	2005			2004			2005		2004
(Accrued) prepaid benefit cost	$	(93,041	)	$	(85,621	)	$	20,245	$	(3,241	)
Additional minimum liability		(171,435	)		(148,824	)		—		—
Total (liability) asset		(264,476	)		(234,445	)		20,245		(3,241	)
Intangible asset		11,833			14,234			—		—
Accumulated other comprehensive loss (pretax)		159,602			134,590			—		—
Net amount recognized	$	(93,041	)	$	(85,621	)	$	20,245	$	(3,241	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The following table shows the other comprehensive income (loss) arising from the change in additional minimum liability for the years ended December 31, 2005 and 2004 (dollars in thousands):

	2005			2004
Increase in minimum liability included in other comprehensive income – net of tax:
Pinnacle West consolidated	$	(15,489	)	$	(15,224	)
APS share	$	(15,045	)	$	(13,929	)

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

							Benefit Costs
	Benefit Obligations						For the Years Ended
	As of December 31,						December 31,
	2005			2004			2005			2004
Discount rate-pension		5.66	%		5.84	%		5.84	%		6.10	%
Discount rate-other benefits		5.68	%		5.92	%		5.92	%		6.10	%
Rate of compensation increase		4.00	%		4.00	%		4.00	%		4.00	%
Expected long-term return on plan assets		N/A			N/A			9.00	%		9.00	%
Initial health care cost trend rate		8.00	%		8.00	%		8.00	%		8.00	%
Ultimate health care cost trend rate		5.00	%		5.00	%		5.00	%		5.00	%
Year ultimate health care trend rate is reached		2010			2009			2009			2008

     In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2006, we are assuming a 9% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.

     Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):

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	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	7	$	(6	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	$	11	$	(9	)
Effect on the accumulated other postretirement benefit obligation	$	100	$	(79	)

Plan Assets

     Pinnacle West’s qualified pension plan asset allocation at December 31, 2005 and 2004 is as follows:

	Percentage of Plan Assets
	at December 31,						Target Asset Allocation
	2005			2004
Asset Category:
Equity securities		59	%		60	%		60	%
Fixed income		26			27			30	%
Other		15			13			10	%
Total		100	%		100	%

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

     Pinnacle West’s other postretirement benefit plans’ asset allocation at December 31, 2005 and 2004, is as follows:

	Percentage of Plan Assets
	at December 31,						Target Asset Allocation
	2005			2004
Asset Category:
Equity securities		69	%		71	%		70	%
Fixed income		26			23			27	%
Other		5			6			3	%
Total		100	%		100	%

     The Investment Management Committee, described above, has also been delegated oversight of the plan assets for the other postretirement benefit plans. The investment policy for other postretirement benefit plans’ assets is similar to that of the pension plan assets described above.

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Contributions

     The contribution to our pension plan in 2006 is estimated to be approximately $50 million. The contribution to our other postretirement benefit plans in 2006 is estimated to be approximately $29 million. APS’ share is approximately 96% of both plans.

Estimated Future Benefit Payments

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

Year	Pension		Other Benefits (a)
2006	$	52,675	$	16,340
2007		56,891		17,751
2008		62,263		19,166
2009		68,651		20,775
2010		75,273		22,847
Years 2011-2015		520,961		149,784

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

Employee Savings Plan Benefits

     Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2005, costs related to APS’ employees represented 96% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account. Under this plan, the Company matches a percentage of the participants’ contributions in the form of Pinnacle West stock. After a five year vesting period, participants have an option to transfer the Company matching contributions out of the Pinnacle West Stock Fund to other investment funds within the plan. At December 31, 2005, approximately 22% of total plan assets were in Pinnacle West stock. Pinnacle West recorded expenses for this plan of approximately $6 million for 2005 and $5 million for each of the years 2004 and 2003. APS recorded expenses for this plan of approximately $6 million in 2005, $5 million in 2004 and $5 million in 2003.

9. Leases

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

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

     Total lease expense recognized in the Consolidated Statements of Income was $71 million in 2005, $69 million in 2004 and $67 million in 2003. APS’ lease expense was $58 million in 2005, $57 million in 2004 and $66 million in 2003.

     The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2006 to 2015.

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

	Pinnacle West
Year	Consolidated		APS
2006	$	74	$	66
2007		73		65
2008		71		64
2009		68		62
2010		65		60
Thereafter		303		288
Total future lease commitments	$	654	$	605

10. Jointly-Owned Facilities

     APS shares ownership of some of its generating and transmission facilities with other companies. Pinnacle West Energy shared ownership of Silverhawk, which was sold on January 10, 2006. See Note 22. Our share of operations and maintenance expense related to these facilities is included in the Consolidated Statements of Income. The following table shows APS’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2005 (dollars in thousands):

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								Construction
	Percent			Plant in		Accumulated		Work in
	Owned			Service		Depreciation		Progress
Generating facilities:
Palo Verde Units 1 and 3		29.1	%	$	1,931,736	$	923,052	$	41,391
Palo Verde Unit 2 (see Note 9)		17.0	%		671,775		260,840		6,363
Four Corners Units 4 and 5		15.0	%		158,129		78,588		317
Navajo Generating Station Units 1, 2 and 3		14.0	%		252,348		108,182		3,963
Cholla common facilities (a)		62.6	%(b)		87,165		38,832		2,109
Transmission facilities:
ANPP 500KV System		35.8	%(b)		81,117		22,829		815
Navajo Southern System		31.4	%(b)		29,809		13,273		6,813
Palo Verde – Yuma 500KV System		23.9	%(b)		9,580		3,945		386
Four Corners Switchyards		27.5	%(b)		3,120		1,267		—
Phoenix – Mead System		17.1	%(b)		36,020		3,770		—
Palo Verde – Estrella 500KV System		55.5	%(b)		74,243		2,023		—
Harquahala		80.0	%(b)		—		—		112

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

11. Commitments and Contingencies

Palo Verde Nuclear Generating Station

     Spent Nuclear Fuel and Waste Disposal

     Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims.

     APS has existing fuel storage pools at Palo Verde and is operating a facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, APS believes spent nuclear fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.

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     Although some low-level waste has been stored on-site in a low-level waste facility, APS is currently shipping low-level waste to off-site facilities. APS currently believes interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.

     APS currently estimates it will incur $147 million (in 2005 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2005, APS had a regulatory asset of $6 million that represents amounts spent for on-site interim spent fuel storage net of amounts recovered in rates per the ACC rate order that was effective April 1, 2005.

     APS believes that scientific and financial aspects of the issues of spent nuclear fuel and low-level waste storage and disposal can be resolved satisfactorily. However, APS acknowledges that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which APS is less able to predict. APS expects to vigorously protect and pursue its rights related to this matter.

     Nuclear Insurance

     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $15 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $13 million.

     The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $17.8 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

Fuel and Purchased Power Commitments

     Pinnacle West and APS are parties to various fuel and purchased power contracts with terms expiring between 2006 and 2025 that include required purchase provisions. Pinnacle West estimates the contract requirements to be approximately $316 million in 2006; $239 million

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in 2007; $180 million in 2008; $139 million in 2009; $117 million in 2010 and $908 million thereafter. APS estimates the contract requirements to be approximately $265 million in 2006; $179 million in 2007; $152 million in 2008; $139 million in 2009; $117 million in 2010 and $896 million thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

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

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

	Actual						Estimated (a)
	2003		2004		2005		2006		2007		2008		2009		2010		Thereafter
Coal take-or-pay commitments	$	43	$	41	$	48	$	67	$	69	$	78	$	93	$	73	$	611

(a) Total take-or-pay commitments are approximately $991 million. The total net present value of these commitments is approximately $598 million.

Coal Mine Reclamation Obligations

     APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’ coal mine reclamation obligation was $75 million at December 31, 2005 and $61 million at December 31, 2004 and is included in Deferred Credits and Other on the Consolidated Balance Sheets.

California Energy Market Issues and Refunds in the Pacific Northwest

     FERC

     In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006, the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. We currently believe the refund claims at FERC will have no material adverse impact on our financial position, results of operations, cash flow or liquidity.

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     On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing has not been acted upon, and the outcome of the further proceedings cannot be predicted at this time.

     The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Ninth Circuit Court of Appeals. Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or cash flows.

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

     California Civil Energy Market Litigation

     APS has been named in a lawsuit regarding wholesale contracts in California, which, after moving to state court, has been removed to the federal court for a second time. The First Amended Complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market, in violation of California unfair competition laws. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against APS and numerous other PX participants. Various motions continue to be filed, and we currently believe these claims will have no material adverse impact on our financial position, results of operations, cash flow or liquidity.

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Construction Program

     Consolidated capital expenditures in 2006 are estimated to be (dollars in millions):

APS	$	649
SunCor		232
Other		6
Total	$	887

Natural Gas Supply

     Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural Gas Company, the rates charged for natural gas transportation were subject to a rate moratorium through December 31, 2005.

     On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the 1996 settlement but maintained the cost responsibility provisions agreed to by parties to that settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain the cost responsibility provisions of the settlement, a party has sought appellate review and is seeking to reallocate the costs responsibility associated with the changed contractual obligations in a way that would be less favorable to APS and Pinnacle West Energy than under the FERC’s July 9, 2003 order. Should this party prevail on this point, APS and Pinnacle West Energy’s annual capacity cost could be increased by approximately $3 million per year, for the period September 2003 through December 2005. This appeal has been stayed pending further consideration by the FERC.

     Consistent with its obligations under the 1996 settlement, El Paso filed a new rate case on June 30, 2005, which proposed new rates and new services to become effective on January 1, 2006. The FERC suspended the effectiveness of these new rates and services until January 1, 2006 and made the rates subject to refund pending the outcome of a hearing. As part of an ongoing technical conference and settlement discussions, El Paso has agreed to postpone the implementation and the associated cost impact of the new services until April 1, 2006. APS will be able to evaluate the cost impact of these new services once the FERC issues a final order on the technical conference. APS cannot currently predict the outcome of this matter.

Navajo Nation Litigation

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

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of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.

     In January, 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.

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, neither APS nor Pinnacle West can currently estimate the expenditures which may be required.

Litigation

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

12. Asset Retirement Obligations

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

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

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

     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed- income debt securities and domestic equity securities. APS applies the provisions of

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SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, APS has recorded the offsetting amount of unrealized gains (losses) on investment securities in other regulatory liabilities/assets.The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at December 31, 2005 and December 31, 2004 (dollars in millions):

			Total		Total
			Unrealized		Unrealized
	Fair Value		Gains		Losses
2005
Equity securities	$	150	$	50	$	—
Debt securities		144		3		1
Total	$	294	$	53	$	1
2004
Equity securities	$	135	$	45	$	—
Debt securities		133		6		—
Total	$	268	$	51	$	—

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

	Year Ended December 31,
	2005			2004			2003
Realized gains	$	6		$	1		$	2
Realized losses		(6	)		(2	)		(1	)
Proceeds from the sale of securities		186			124			169

     The fair value of debt securities, summarized by contractual maturities, at December 31, 2005 is as follows:

	Fair Value
	(in millions)
Less than one year	$	18
1 year — 5 years		35
5 years — 10 years		36
Greater than 10 years		55
Total	$	144

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     The following schedule shows the change in our asset retirement obligations for 2005 and 2004 (dollars in millions):

	2005			2004
Asset retirement obligation at the beginning of year	$	252		$	234
Changes attributable to:
Liabilities settled		(2	)		(1	)
Accretion expense		17			17
Estimated cash flow revisions		2			2
Asset retirement obligation at the end of year	$	269		$	252

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

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13. Selected Quarterly Financial Data (Unaudited)

     The following note presents quarterly financial information for 2005 and 2004. We are disclosing originally reported amounts and revised amounts in each period for the reclassification of certain commercial properties at SunCor and Silverhawk as discontinued operations (see Note 22).

     Consolidated quarterly financial information for 2005 and 2004 is as follows (dollars in thousands, except per share amounts):

	2005 Quarter Ended											2005
	March 31,			June 30,			September 30,			December 31,		Total
As originally reported:
Operating revenues	$	615,087		$	755,836		$	955,583
Operations and maintenance		156,496			153,097			158,940
Operating income		85,256			178,627			162,113
Income taxes		14,732			55,024			40,305
Income from continuing operations		23,656			85,156			84,694
SunCor reclassifications (see Note 22):
Operating revenues		(2,120	)		(494	)		—
Operating income		(529	)		205			(268	)
Income taxes		(91	)		(36	)		—
Income from continuing operations		(142	)		(55	)		—
Silverhawk reclassifications (see Note 22):
Operating revenues		(27,609	)		—			—
Operations and maintenance		(1,412	)		—			—
Operating income		7,098			—			—
Income taxes		3,929			—			—
Income from continuing operations		6,085			—			—
After SunCor and Silverhawk reclassifications:
Operating revenues	$	585,358		$	755,342		$	955,583		$	691,672	$	2,987,955
Operations and maintenance		155,084			153,097			158,940			168,706		635,827
Operating income		91,825			178,832			161,845			82,787		515,289
Income taxes		18,570			54,988			40,305			13,029		126,892
Income from continuing operations		29,599			85,101			84,694			23,769		223,163
Net income		24,448			26,735			103,737			21,347		176,267

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	2004 Quarter Ended												2004
	March 31,			June 30,			September 30,			December 31,			Total
As originally reported:
Operating revenues	$	566,345		$	711,883		$	886,779		$	734,718		$	2,899,725
Operations and maintenance		137,386			138,975			160,765			159,431			596,557
Operating income		84,198			120,480			210,836			90,745			506,259
Income taxes		15,468			43,206			58,900			11,283			128,857
Income from continuing operations		30,791			71,223			103,886			29,318			235,218
Net income		31,426			72,640			105,400			33,729			243,195
SunCor reclassifications (see Note 22):
Operating revenues		(2,293	)		(2,592	)		(2,318	)		(2,274	)		(9,477	)
Operating income		(552	)		(625	)		(415	)		375			(1,217	)
Income taxes		(26	)		(48	)		51			168			145
Income from continuing operations		(41	)		(75	)		80			261			225
Silverhawk reclassifications (See Note 22):
Operating revenues		301			(5,084	)		(37,296	)		(19,163	)		(61,242	)
Operations and maintenance		—			(380	)		(2,158	)		(1,699	)		(4,237	)
Operating income		300			3,002			(1,065	)		10,686			12,923
Income taxes		(108	)		1,801			232			5,215			7,140
Income from continuing operations		(170	)		2,813			363			8,141			11,147
After SunCor and Silverhawk reclassifications:
Operating revenues	$	564,353		$	704,207		$	847,165		$	713,281		$	2,829,006
Operations and maintenance		137,386			138,595			158,607			157,732			592,320
Operating income		83,946			122,857			209,356			101,806			517,965
Income taxes		15,334			44,959			59,183			16,666			136,142
Income from continuing operations		30,580			73,961			104,329			37,720			246,590
Net income		31,426			72,640			105,400			33,729			243,195

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Earnings per share:

	2005 Quarter Ended
	March 31,		June 30,		September 30,		December 31,
As originally reported — Basic earnings per share (a):
Income from continuing operations	$	0.26	$	0.89	$	0.86	$	0.24
Net income		0.27		0.28		1.05		0.22
After SunCor and Silverhawk reclassifications — Basic earnings per share (a):
Income from continuing operations		0.32		0.88		0.86		0.24
Net income		0.27		0.28		1.05		0.22
As originally reported — Diluted earnings per share (a):
Income from continuing operations		0.26		0.88		0.86		0.24
Net income		0.27		0.28		1.05		0.22
After SunCor and Silverhawk reclassifications — Diluted earnings per share (a):
Income from continuing operations	$	0.32	$	0.88	$	0.86	$	0.24
Net income		0.27		0.28		1.05		0.22

	2004 Quarter Ended
	March 31,		June 30,		September 30,		December 31,
As originally reported — Basic earnings per share (a):
Income from continuing operations	$	0.34	$	0.78	$	1.14	$	0.32
Net income		0.34		0.80		1.15		0.37
After SunCor and Silverhawk reclassifications — Basic earnings per share (a):
Income from continuing operations		0.33		0.81		1.14		0.41
Net income		0.34		0.80		1.15		0.37
As originally reported — Diluted earnings per share (a):
Income from continuing operations		0.34		0.78		1.14		0.32
Net income		0.34		0.79		1.15		0.37
After SunCor and Silverhawk reclassifications — Diluted earnings per share (a):
Income from continuing operations	$	0.33	$	0.81	$	1.14	$	0.41
Net income		0.34		0.79		1.15		0.37

(a) The difference between originally reported and revised basic and diluted earnings per share related to the sale of certain commercial properties at SunCor and the sale of Silverhawk (see Note 22), which changed reported amounts for the quarters in 2005 and 2004.

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14. Fair Value of Financial Instruments

     Pinnacle West and APS believe that the carrying amounts of their cash equivalents are reasonable estimates of their fair values at December 31, 2005 and 2004 due to their short maturities.

     Pinnacle West and APS hold investments in debt securities for purposes other than trading. We believe that the carrying amounts of these investments represent reasonable estimates of their fair values at December 31, 2005 and 2004 due to the short-term reset of interest rates.

     We also hold investments in fixed income and domestic equity securities for purposes other than trading. The December 31, 2005 and 2004 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.

     On December 31, 2005, the carrying value of our long-term debt for Pinnacle West, excluding capitalized lease obligations and interest rate swap (see “Fair Value Hedges” – Note 18), was $2.99 billion, with an estimated fair value of $3.00 billion. See Note 18 for fair value of the interest rate swap. The carrying value of our long-term debt for Pinnacle West (excluding capitalized lease obligations) was $3.19 billion on December 31, 2004, with an estimated fair value of $3.30 billion. On December 31, 2005, the carrying value of APS’ long-term debt (excluding capitalized lease obligations) was $2.56 billion, with an estimated fair value of $2.57 billion. The carrying value of APS’ long-term debt (excluding capital lease obligations) was $2.71 billion on December 31, 2004, with an estimated fair value of $2.81 billion. The fair value estimates are based on quoted market prices of the same or similar issues.

15. Earnings Per Share

     The following table presents earnings per weighted-average common share outstanding for the years ended December 31, 2005, 2004 and 2003:

	2005			2004			2003
Basic earnings per share:
Income from continuing operations	$	2.31		$	2.70		$	2.47
Income (loss) from discontinued operations		(0.48	)		(0.04	)		0.17
Earnings per share – basic	$	1.83		$	2.66		$	2.64
Diluted earnings per share:
Income from continuing operations	$	2.31		$	2.69		$	2.47
Income (loss) from discontinued operations		(.49	)		(0.03	)		0.16
Earnings per share – diluted	$	1.82		$	2.66		$	2.63

     Dilutive stock options increased average common shares outstanding by approximately 106,000 shares in 2005, 135,000 shares in 2004 and 140,000 shares in 2003. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 96,589,949 shares in 2005, 91,532,473 shares in 2004 and 91,405,134 shares in 2003.

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     Options to purchase 495,367 shares of common stock were outstanding at December 31, 2005 but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 1,058,616 at December 31, 2004 and 2,291,646 at December 31, 2003.

16. Stock-Based Compensation

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

     The 2002 Long-Term Incentive Plan (2002 plan) allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. We have reserved 6 million shares of common stock for issuance under the 2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards and stock ownership incentive awards. The plan also provides for the granting of new non-qualified stock options at a price per share not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met, which can accelerate the vesting period. The term of the option cannot be longer than 10 years and the option cannot be repriced during its term.

     The 1994 Long-Term Incentive Plan (“1994 Plan”) includes outstanding options but no new options will be granted under the plan. Options vested one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 Plan also provided for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents.

     In the third quarter of 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123. In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in APB No. 25.

     In addition, see Note 2 for discussion of a new standard on share based payments (SFAS No. 123R).

     Total stock-based compensation cost, including restricted stock, performance shares, stock options, and stock ownership incentives was $6 million in 2005, $8 million in 2004 and $6 million in 2003 for Pinnacle West. APS’ share was $5 million in 2005, $6 million in 2004 and $3 million in 2003.

     The following table is a summary of the status of outstanding stock options under our equity incentive plans as of December 31, 2005, 2004 and 2003 and changes during the years ending on those dates:

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				2005					2004					2003
				Weighted					Weighted					Weighted
				Average					Average					Average
	2005			Exercise		2004			Exercise		2003			Exercise
	Shares			Price		Shares			Price		Shares			Price
Outstanding at beginning of year		2,276,123		$	39.14		2,698,246		$	38.56		2,185,129		$	39.96
Granted		—			—		37,580			37.85		621,875			32.29
Exercised		(478,851	)		36.54		(372,205	)		34.02		(62,366	)		26.09
Forfeited		(101,500	)		43.04		(87,498	)		42.31		(46,392	)		37.61
Outstanding at year-end		1,695,772			39.65		2,276,123			39.14		2,698,246			38.56
Options exercisable at year-end		1,499,302			40.55		1,859,340			40.59		1,787,622			40.35
Weighted-average grant date fair value of options granted during the year					—				$	3.53				$	7.37

     The following table summarizes information about our stock options at December 31, 2005:

					Weighted
			Weighted		Average				Weighted
			Average		Remaining				Average
Exercise	Options		Exercise		Contract		Options		Exercise
Prices Per Share	Outstanding		Price		Life (Years)		Exercisable		Price
$28.07 — 32.75		341,902	$	32.24		6.6		160,372	$	32.18
32.75 — 37.42		67,081		34.66		3.7		67,081		34.66
37.42 — 42.10		540,855		38.89		5.2		525,915		38.92
42.10 — 46.78		745,934		44.04		4.6		745,934		44.04
		1,695,772						1,499,302

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     The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2005, 2004 and 2003:

			2005 Grant					2004 Grant					2003 Grant
	2005		Date Fair			2004		Date Fair			2003		Date Fair
	Shares		Value			Shares		Value			Shares		Value
Restricted stock		—	$	—			4,000	$	37.68	(a)		4,000	$	32.20	(a)
Performance share awards		215,300		41.36	(b)		215,285		37.85	(b)		119,085		32.29	(b)
Stock ownership incentive awards		11,322		44.13	(b)		9,015		40.29	(b)		—		—

(a)	Restricted stock priced at the average of the high and low market price on the grant date.
(b)	Performance shares and stock ownership incentive awards priced at the closing market price on the grant date.

17. Business Segments

     We have three principal business segments (determined by products, services and the regulatory environment):

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

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

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services.

     Financial data for 2005, 2004 and 2003 by business segments is provided as follows (dollars in millions):

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	Business Segments for the Year Ended December 31, 2005
	Regulated						Marketing
	Electricity			Real Estate			and Trading			Other		Total
Operating revenues (a)	$	2,237		$	338		$	352		$	61	$	2,988
Purchased power and fuel costs		595			—			293			—		888
Other operating expenses		740			278			28			52		1,098
Regulatory disallowance (see Note 3)		139			—			—			—		139
Operating margin		763			60			31			9		863
Depreciation and amortization		343			3			2			—		348
Interest expense		169			2			2			—		173
Other expense (income)		(6	)		(3	)		—			1		(8	)
Income from continuing operations before income taxes		257			58			27			8		350
Income taxes		90			23			11			3		127
Income from continuing operations		167			35			16			5		223
Income (loss) from discontinued operations — net of income tax benefit of $(30) (see Note 22) (b)(c)		—			17			(67	)		3		(47	)
Net income (loss)	$	167		$	52		$	(51	)	$	8	$	176
Total assets	$	9,732		$	483		$	1,070		$	38	$	11,323
Capital expenditures	$	811		$	106		$	11		$	—	$	928

	Business Segments for the Year Ended December 31, 2004
	Regulated					Marketing
	Electricity		Real Estate			and Trading			Other			Total
Operating revenues	$	2,035	$	350		$	401		$	43		$	2,829
Purchased power and fuel costs		567		—			321			—			888
Other operating expenses		683		284			30			34			1,031
Operating margin		785		66			50			9			910
Depreciation and amortization		384		4			4			—			392
Interest expense		170		1			1			—			172
Other expense (income) (d)		4		(6	)		(2	)		(33	)		(37	)
Income from continuing operations before income taxes		227		67			47			42			383
Income taxes		75		27			18			16			136
Income from continuing operations		152		40			29			26			247
Income (loss) from discontinued operations — net of income tax benefit of $(2) (see Note 22) (b)(c)		—		4			(12	)		4			(4	)
Net income	$	152	$	44		$	17		$	30		$	243
Total assets	$	8,674	$	454		$	746		$	23		$	9,897
Capital expenditures	$	483	$	81		$	34		$	—		$	598

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	Business Segments for the Year Ended December 31, 2003
	Regulated						Marketing
	Electricity			Real Estate			and Trading		Other		Total
Operating revenues	$	1,978		$	362		$	391	$	28	$	2,759
Purchased power and fuel costs		517			—			345		—		862
Other operating expenses		625			306			34		24		989
Operating margin		836			56			12		4		908
Depreciation and amortization		428			6			1		—		435
Interest expense		172			2			—		—		174
Other expense (income)		(4	)		(25	)		—		—		(29	)
Income from continuing operations before income taxes		240			73			11		4		328
Income taxes		70			28			3		2		103
Income from continuing operations		170			45			8		2		225
Income from discontinued operations — net of income taxes of $9 (see Note 22) (b)(c)		—			10			1		5		16
Net income	$	170		$	55		$	9	$	7	$	241
Capital expenditures	$	686		$	72		$	9	$	—	$	767

(a)	Effective April 1, 2005, revenues of approximately $40 million from Off-System Sales, which were previously reported in the marketing and trading segment, began being reported in the regulated electricity segment in accordance with the retail rate case settlement.
(b)	The marketing and trading segment relates to the sale and operations of Silverhawk. See Note 22.
(c)	The other segment relates to the sale and operations of NAC. See Note 22.
(d)	The other segment includes a $35 million pre-tax ($21 million after-tax) gain related to the sale of a limited partnership interest in the Phoenix Suns in 2004.

18. Derivative and Energy Trading Accounting

     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge our exposure to changes in interest rates and to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. As of December 31, 2005, we hedged certain exposures to the price variability of commodities for a maximum of 3.25 years. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

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     We recognize all derivatives, except those which qualify for a scope exception, as either assets or liabilities on the balance sheet and measure those instruments at fair value in accordance with SFAS No. 133, as amended by SFAS No. 149. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales exception and are accounted for under the accrual method of accounting. Changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative are recognized in common stock equity (as a component of other comprehensive income (loss)). For fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item associated with the hedged risk are recognized in earnings. We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. We use fair value hedges to limit our exposure to changes in fair value of an asset or liability.

     For its regulated operations, APS defers for future rate recovery 90% of gains and losses on derivatives that would otherwise be recognized in income. To the extent the amounts that would otherwise be recognized in income are eligible to be recovered through the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings.

     We assess hedge effectiveness both at inception and on a continuing basis. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated. It is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.

     Both non-trading and trading derivatives that do not qualify for a scope exception are classified as assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets. Certain of our non-trading derivatives qualify for cash flow hedge accounting treatment. Non-trading derivatives, or any portion thereof that are not effective hedges, are adjusted to fair value through income. Realized gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings.

     All gains and losses (realized and unrealized) on trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis. Trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.

     In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs,

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which reduces both revenues and fuel and purchased power costs in our Consolidated Statement of Income, but this does not impact our financial condition, net income or cash flows.

Cash Flow Hedges

     The changes in the fair value of our hedged positions included in the Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2005, 2004 and 2003 are comprised of the following (dollars in thousands):

	2005		2004			2003
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	14,289	$	(1,568	)	$	8,237
Gains from the change in options’ time value excluded from measurement of effectiveness		620		185			181
Gains from the discontinuance of cash flow hedges		556		1,137			—

     During 2006, we estimate that a net gain of $216 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).

     Our assets and liabilities from risk management and trading activities are presented in two categories, consistent with our business segments.

     The following table summarizes our assets and liabilities from risk management and trading activities at December 31, 2005 and 2004 (dollars in thousands):

December 31, 2005

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	516,399	$	228,873	$	(335,801	)	$	(74,787	)	$	334,684
Margin account and options		1,814		—		(124,165	)		—			(122,351	)
Marketing and trading:
Mark-to-market		307,883		291,122		(236,922	)		(181,417	)		180,666
Options and emission allowances – at cost		1,683		77,836		(23,805	)		(209	)		55,505
Total	$	827,779	$	597,831	$	(720,693	)	$	(256,413	)	$	448,504

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2004

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	45,220	$	19,417	$	(19,191	)	$	(12,000	)	$	33,446
Margin account and options		18,821		118		(8,879	)		—			10,060
Marketing and trading:
Mark-to-market		102,855		204,512		(68,008	)		(132,683	)		106,676
Options and emission allowances – at cost		—		294		(17,328	)		(11,579	)		(28,613	)
Total	$	166,896	$	224,341	$	(113,406	)	$	(156,262	)	$	121,569

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was a liability of $123 million at December 31, 2005 and $9 million at December 31, 2004 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $6 million at December 31, 2005 and $1 million at December 31, 2004, and is included in other current assets on the Consolidated Balance Sheets. Collateral provided to us by counterparties was $216 million at December 31, 2005 and $24 million at December 31, 2004, and is included in other current liabilities on the Consolidated Balance Sheets.

Fair Value Hedges

     On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on our $300 million 6.4% Senior Notes. The purpose of these hedges is to protect against significant fluctuations in the fair value of our debt. Our interest rate swaps are considered to be fully effective with any resulting gains or losses on the derivative offset by a similar loss or gain amount on the underlying fair value of debt. The fair value of the interest rate swaps was a loss of $1.5 million at December 31, 2005 and is included in other current liabilities with the corresponding offset in current maturities of long-term debt on the Consolidated Balance Sheets. The fair value of the interest rate swaps was $2.6 million at December 31, 2004 and is included in investments and other assets with the corresponding offset in long-term debt less current maturities on the Consolidated Balance Sheets.

Credit Risk

     We are exposed to losses in the event of non-performance or non-payment by counterparties. We have risk management and trading contracts with many counterparties. Our risk management

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process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 “Derivative Accounting” for a discussion of our credit valuation adjustment policy.

19. Other Income and Other Expense

     The following table provides detail of other income and other expense for the years 2005, 2004 and 2003 (dollars in thousands):

	2005			2004			2003
Other income:
Investment gains — net (a)	$	752		$	38,256		$	3,649
Interest income		14,793			6,770			4,412
SunCor (b)		2,623			4,458			24,740
Asset sales		3,187			3,026			618
Miscellaneous		2,005			779			2,144
Total other income	$	23,360		$	53,289		$	35,563
Other expense:
Non-operating costs (c)	$	(13,589	)	$	(15,524	)	$	(14,959	)
Asset dispositions		(9,759	)		(1,212	)		(1,522	)
Miscellaneous		(3,368	)		(4,604	)		(4,093	)
Total other expense	$	(26,716	)	$	(21,340	)	$	(20,574	)

(a)	Includes a $35 million gain ($21 million after tax) related to the sale of a limited partnership interest in the Phoenix Suns in 2004.
(b)	Primarily related to the sale at SunCor of a land interest and profit participation agreement in 2003 for $18 million. Includes joint venture and other non-operating income.
(c)	As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and other costs excluded from utility rate recovery).

20. Variable-Interest Entities

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

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     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, 2005, APS would have been required to assume approximately $234 million of debt and pay the equity participants approximately $185 million.

     SunCor has certain land development arrangements that are required to be consolidated under FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $34 million at December 31, 2005 and 2004.

21. Guarantees

     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantee for Pinnacle West Energy relates to a purchased power agreement. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by our unregulated 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 guarantees on behalf of its subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2005 are as follows (dollars in millions):

	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
Parental:
Pinnacle West Energy	$	5		1	$	—		—
APS Energy Services		20		1		65		1
Total	$	25			$	65

     At December 31, 2005, we had entered into approximately $37 million of letters of credit which supported transmission agreements related to Silverhawk. These letters of credit terminated as a result of the sale of Silverhawk. See Note 22 for a discussion of the sale of Silverhawk. At December 31, 2005, Pinnacle West had approximately $4 million of letters of credit related to workers’ compensation expiring in 2006. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2005, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $98 million of letters of credit to support certain equity

124

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2006. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

     We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

22. Discontinued Operations

     Silverhawk(marketing and trading segment)–In June 2005, we entered into an agreement to sell our 75% interest in Silverhawk to NPC. The sale was completed on January 10, 2006. As a result of this sale, we recorded a loss from discontinued operations of approximately $56 million ($91 million pretax) in the second quarter of 2005. The amounts in the chart below also include the revenues and expenses related to the operations of Silverhawk. The assets held for sale at December 31, 2005 were $203 million, of which property, plant and equipment accounted for approximately $197 million.

     Concurrent with the execution of the agreement to sell our interest in Silverhawk, GenWest and NPC also entered into a Purchase Power Agreement (“PPA”) providing for the sale of GenWest’s share of the capacity and output of Silverhawk to NPC. The PPA commenced on October 1, 2005 and was terminated on January 10, 2006, the date of the sale under the Purchase Agreement.

     SunCor(real estate segment)–In 2005, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144. As a result of the sales, we recorded a gain from discontinued operations of approximately $15 million ($25 million pretax) in the third quarter of 2005.

     NAC(other segment)–In 2004, we sold our investment in NAC, and in 2005 we recognized a gain of $4 million ($6 million pretax) in connection with the sale that had previously been subject to contingencies.

     The following table provides revenue, income (loss) before income taxes and after-tax income classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2005, 2004 and 2003 (dollars in millions):

125

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2005			2004			2003
Revenue:
Silverhawk	$	95		$	61		$	1
SunCor – commercial operations		9			21			71
NAC		—			34			58
Total revenue	$	104		$	116		$	130
Income (loss) before taxes:
Silverhawk (a)	$	(111	)	$	(18	)	$	—
SunCor – commercial operations		28			6			17
NAC		6			7			8
Total income (loss) before taxes	$	(77	)	$	(5	)	$	25
Income (loss) after taxes:
Silverhawk	$	(67	)	$	(12	)	$	1
SunCor – commercial operations		17			4			10
NAC		3			4			5
Total income (loss) after taxes	$	(47	)	$	(4	)	$	16

(a) Income before income taxes includes an interest expense allocation, net of capitalized amounts, of $13 million in 2005 and $6 million in 2004. The allocation was based on Pinnacle West’s weighted-average interest rate applied to the net property, plant and equipment.

126

MANAGEMENT’S REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

(ARIZONA PUBLIC SERVICE COMPANY)

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13(a)-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework inInternal Control – Integrated Framework,our management concluded that our internal control over financial reporting was effective as of December 31, 2005. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s financial statements.

March 8, 2006

127

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Arizona Public Service Company
Phoenix, Arizona

We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”) as of December 31, 2005 and 2004, and the related statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

128

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP
Phoenix, Arizona

March 8, 2006

129

ARIZONA PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME

(dollars in thousands)

	Year Ended December 31,
	2005			2004			2003
Electric Operating Revenues:
Regulated electricity	$	2,244,951		$	2,051,602		$	1,999,390
Marketing and trading		25,842			145,519			105,541
Total		2,270,793			2,197,121			2,104,931
Operating Expenses:
Regulated electricity fuel and purchased power		656,654			612,300			606,251
Marketing and trading fuel and purchased power		32,328			150,954			97,180
Operations and maintenance		591,941			540,277			513,604
Depreciation and amortization		325,174			336,648			389,240
Income taxes (Notes 4 and S-2)		157,273			113,696			91,646
Other taxes		125,810			114,265			108,852
Total		1,889,180			1,868,140			1,806,773
Operating Income		381,613			328,981			298,158
Other Income (Deductions):
Regulatory disallowance (Note 3)		(138,562	)		—			—
Income taxes (Notes 4 and S-2)		59,263			(6,334	)		4,792
Allowance for equity funds used during construction		11,191			4,885			14,240
Other income (Note S-5)		22,141			30,593			20,277
Other expense (Note S-5)		(23,204	)		(13,816	)		(12,962	)
Total		(69,171	)		15,328			26,347
Interest Deductions:
Interest on long-term debt		138,476			140,556			142,706
Interest on short-term borrowings		7,026			6,427			4,904
Debt discount, premium and expense		4,085			4,854			3,337
Allowance for borrowed funds used during construction		(7,624	)		(7,155	)		(7,379	)
Total		141,963			144,682			143,568
Net Income	$	170,479		$	199,627		$	180,937

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

130

ARIZONA PUBLIC SERVICE COMPANY

BALANCE SHEETS

(dollars in thousands)

	December 31,
	2005			2004
ASSETS
Utility Plant (Notes 1, 6, 9 and 10)
Electric plant in service and held for future use	$	10,682,999		$	9,120,407
Less accumulated depreciation and amortization		3,616,886			3,266,181
Total		7,066,113			5,854,226
Construction work in progress		314,584			249,243
Intangible assets, net of accumulated amortization of $181,046 and $154,843		90,327			103,701
Nuclear fuel, net of accumulated amortization of $53,984 and $59,020		54,184			51,188
Utility plant – net		7,525,208			6,258,358
Investments and Other Assets
Note receivable from Pinnacle West Energy (Notes 1, 3 and S-6)		—			498,489
Decommissioning trust accounts (Note 12)		293,943			267,700
Assets from risk management and trading activities (Note S-4)		234,372			20,123
Other assets		64,128			61,364
Total investments and other assets		592,443			847,676
Current Assets:
Cash and cash equivalents		49,933			49,575
Investment in debt securities		—			181,175
Customer and other receivables		421,621			353,772
Allowance for doubtful accounts		(3,568	)		(3,444	)
Materials and supplies (at average cost)		109,736			83,893
Fossil fuel (at average cost)		23,658			20,506
Assets from risk management and trading activities (Note S-4)		532,923			70,430
Other		14,639			10,187
Total current assets		1,148,942			766,094
Deferred Debits:
Deferred fuel and purchased power regulatory asset (Notes 1, 3, 4 and S-2)		172,756			—
Other regulatory assets (Notes 1, 3, 4 and S-2)		151,123			135,051
Unamortized debt issue costs		25,279			21,832
Other		91,690			69,541
Total deferred debits		440,848			226,424
Total Assets	$	9,707,441		$	8,098,552

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

131

ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)

	December 31,
	2005			2004
LIABILITIES AND EQUITY
Capitalization:
Common stock	$	178,162		$	178,162
Additional paid-in capital (Note 3)		1,853,098			1,246,804
Retained earnings		860,675			860,196
Accumulated other comprehensive income (loss):
Minimum pension liability adjustment		(86,132	)		(71,087	)
Derivative instruments		179,422			18,327
Common stock equity		2,985,225			2,232,402
Long-term debt less current maturities (Note 6)		2,479,703			2,267,094
Total capitalization		5,464,928			4,499,496
Current Liabilities:
Current maturities of long-term debt (Note 6)		85,620			451,247
Accounts payable		215,384			215,076
Accrued taxes		360,737			292,521
Accrued interest		25,003			33,332
Customer deposits		55,474			51,804
Deferred income taxes (Notes 4 and S-2)		64,210			9,057
Liabilities from risk management and trading activities (Note S-4)		480,138			34,292
Other		227,398			91,441
Total current liabilities		1,513,964			1,178,770
Deferred Credits and Other:
Deferred income taxes (Notes 4 and S-2)		1,215,403			1,108,571
Regulatory liabilities (Notes 1, 3, 4, and S-2)		592,494			506,646
Liability for asset retirements (Note 12)		269,011			251,612
Pension liability (Note 8)		233,342			203,668
Customer advances for construction		60,287			59,185
Unamortized gain — sale of utility plant (Note 9)		45,757			50,333
Liabilities from risk management and trading activities (Note S-4)		83,774			13,124
Other		228,481			227,147
Total deferred credits and other		2,728,549			2,420,286
Commitments and Contingencies (Notes 3, 11, 12 and S-6)
Total Liabilities and Equity	$	9,707,441		$	8,098,552

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

132

ARIZONA PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2005			2004 (a)			2003 (a)
Cash Flows from Operating Activities:
Net income	$	170,479		$	199,627		$	180,937
Adjustments to reconcile net income to net cash provided by operating activities:
Regulatory disallowance		138,562			—			—
Depreciation and amortization including nuclear fuel		353,082			367,094			417,997
Deferred fuel and purchased power		(172,756	)		—			—
Allowance for equity funds used during construction		(11,191	)		(4,885	)		(14,240	)
Deferred income taxes		9,659			(140,855	)		(1,087	)
Change in derivative mark-to-market valuations		3,492			(15,807	)		2,339
Changes in current assets and liabilities:
Customer and other receivables		(56,152	)		(24,146	)		85,106
Materials, supplies and fossil fuel		(12,268	)		4,643			(872	)
Other current assets		(2,592	)		(2,529	)		976
Accounts payable		(12,372	)		88,937			17,961
Accrued taxes		67,454			202,047			7,917
Collateral		169,080			5,671			11,431
Other current liabilities		(37,781	)		22,715			9,737
Changes in risk management and trading – liabilities		115,495			8,879			—
Change in other long-term assets		(9,303	)		(44,386	)		(2,072	)
Change in other long-term liabilities		9,002			51,133			60,994
Net cash flow provided by operating activities		721,890			718,138			777,124
Cash Flows from Investing Activities:
Capital expenditures		(609,857	)		(513,677	)		(426,260	)
Transfer of PWEC Dedicated Assets to APS		(500,000	)		—			—
Purchase of Sundance Plant		(185,046	)		—			—
Allowance for borrowed funds used during construction		(7,624	)		(7,155	)		(7,379	)
Purchases of investment securities		(1,476,623	)		(871,610	)		(855,660	)
Proceeds from sale of investment securities		1,657,798			760,285			785,810
Proceeds from nuclear decommissioning trust sales		186,215			123,795			168,874
Investment in nuclear decommissioning trust		(204,633	)		(135,239	)		(180,319	)
Loan to Pinnacle West Energy		—			—			(497,865	)
Repayment of loan by Pinnacle West Energy		500,000			—			—
Other		(5,372	)		10,639			3,149
Net cash flow used for investing activities		(645,142	)		(632,962	)		(1,009,650	)
Cash Flows from Financing Activities:
Issuance of long-term debt		411,787			478,140			491,654
Equity infusion		250,000			—			—
Dividends paid on common stock		(170,000	)		(170,000	)		(170,000	)
Repayment and reacquisition of long-term debt		(568,177	)		(385,893	)		(89,525	)
Net cash flow provided by (used for) financing activities		(76,390	)		(77,753	)		232,129
Net increase (decrease) in cash and cash equivalents		358			7,423			(397	)
Cash and cash equivalents at beginning of year		49,575			42,152			42,549
Cash and cash equivalents at end of year	$	49,933		$	49,575		$	42,152
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes, net of refunds	$	34,252		$	68,074		$	74,523
Interest, net of amounts capitalized	$	146,207		$	149,148		$	140,010

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

(a) See “Cash and Cash Equivalents” in Note 1 for information regarding reclassifications of prior year amounts.

133

ARIZONA PUBLIC SERVICE COMPANY

STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(dollars in thousands)

	Years Ended December 31,
	2005			2004			2003
COMMON STOCK	$	178,162		$	178,162		$	178,162
ADDITIONAL PAID-IN CAPITAL		1,853,098			1,246,804			1,246,804
RETAINED EARNINGS
Balance at beginning of year		860,196			830,569			819,632
Net income		170,479			199,627			180,937
Common stock dividends		(170,000	)		(170,000	)		(170,000	)
Balance at end of year		860,675			860,196			830,569
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year		(52,760	)		(51,905	)		(85,286	)
Minimum pension liability adjustment, net of tax expense (benefit) of ($9,023), ($8,936) and $3,105		(15,045	)		(13,929	)		4,329
Unrealized gain on derivative instruments, net of tax expense of $140,135, $16,824 and $15,824		218,656			25,892			24,135
Reclassification of realized (gain) loss to income, net of tax expense (benefit) of ($37,082), ($8,344) and $3,207		(57,561	)		(12,818	)		4,917
Balance at end of year		93,290			(52,760	)		(51,905	)
TOTAL COMMON STOCK EQUITY	$	2,985,225		$	2,232,402		$	2,203,630
COMPREHENSIVE INCOME
Net income	$	170,479		$	199,627		$	180,937
Other comprehensive income (loss)		146,050			(855	)		33,381
Total comprehensive income	$	316,529		$	198,772		$	214,318

See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.

134

     Certain notes to Arizona Public Service Company’s financial statements are combined with the notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements, the majority of which also relate to Arizona Public Service Company’s financial statements. In addition, listed below are the supplemental notes which are required disclosures for Arizona Public Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s Consolidated Notes.

		APS’
	Consolidated	Supplemental
	Footnote	Footnote
	Reference	Reference
Summary of Significant Accounting Policies	Note 1	Note S-1
New Accounting Standards	Note 2	—
Regulatory Matters	Note 3	—
Income Taxes	Note 4	Note S-2
Lines of Credit and Short-Term Borrowings	Note 5	—
Long-Term Debt	Note 6	—
Common Stock and Treasury Stock	Note 7	—
Retirement Plans and Other Benefits	Note 8	—
Leases	Note 9	—
Jointly-Owned Facilities	Note 10	—
Commitments and Contingencies	Note 11	—
Asset Retirement Obligations	Note 12	—
Selected Quarterly Financial Data (Unaudited)	Note 13	Note S-3
Fair Value of Financial Instruments	Note 14	—
Earnings Per Share	Note 15	—
Stock-Based Compensation	Note 16	—
Business Segments	Note 17	—
Derivative and Energy Trading Activities	Note 18	Note S-4
Other Income and Other Expense	Note 19	Note S-5
Variable Interest Entities	Note 20	—
Guarantees	Note 21	—
Discontinued Operations	Note 22	—
Related Party Transactions	—	Note S-6

135

S-1. Summary of Significant Accounting Polices

Stock-Based Compensation

     Pinnacle West offers stock-based compensation plans for officers and key employees of APS. In 2002, APS began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” In accordance with the transition requirements of SFAS No. 123, APS applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, APS recognized stock compensation expense based on the intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.”

     The following chart compares APS’ net income and stock compensation expense to what those items would have been if APS had recorded stock compensation expense based on the fair value method for all stock grants through 2005 (dollars in thousands):

	2005			2004			2003
Net income, as reported	$	170,479		$	199,627		$	180,937
Add: Stock compensation expense included in reported net income (net of tax)		3,102			3,353			2,035
Deduct: Total stock compensation expense determined under fair value method (net of tax)		(3,102	)		(3,713	)		(3,024	)
Pro forma net income	$	170,479		$	199,267		$	179,948

S-2. Income Taxes

     APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based on APS’ taxable income or loss alone.

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

     APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from the reduction in federal income tax rates as part of the Tax Reform Act of 1986. APS amortizes this amount as the differences reverse.

     As a result of a change in IRS guidance, Pinnacle West claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. In 2002, Pinnacle West received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax

136

return. The 2001 federal consolidated income tax return is currently under examination by the IRS. As part of this ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. During 2004 and again in 2005, the current income tax liability was increased, with a corresponding decrease to plant-related deferred tax liability, to reflect the expected outcome of this audit. APS does not expect the ultimate outcome of this examination to have a material adverse impact on its financial position or results of operations. We expect that it will have a negative impact on cash flows.

     The income tax liability accounts reflect the tax and interest associated with the most probable resolution of all known and measurable tax exposures.

     In 2004 and 2003, we resolved certain prior-year issues with the taxing authorities and recorded tax benefits associated with tax credits and other reductions to income tax expense.

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

	Year Ended December 31,
	2005		2004			2003
Current:
Federal	$	79,917	$	207,306		$	75,087
State		8,434		53,579			12,854
Total current		88,351		260,885			87,941
Deferred		9,659		(140,855	)		(1,087	)
Total income tax expense	$	98,010	$	120,030		$	86,854

     On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.

     The following chart compares APS’ pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):

	Year Ended December 31,
	2005			2004			2003
Federal income tax expense at 35% statutory rate	$	93,971		$	111,880		$	93,727
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		8,986			12,496			9,723
Credits and favorable adjustments related to prior years resolved in current year		—			(315	)		(12,944	)
Medicare Subsidy Part-D (see Note 8)		(2,465	)		(1,507	)		—
Allowance for equity funds used during construction (see Note 1)		(3,694	)		(1,543	)		(4,984	)
Other		1,212			(981	)		1,332
Income tax expense	$	98,010		$	120,030		$	86,854

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

	December 31,
	2005			2004
Current liability	$	(64,210	)	$	(9,057	)
Long term liability		(1,215,403	)		(1,108,571	)
Accumulated deferred income taxes – net	$	(1,279,613	)	$	(1,117,628	)

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

	December 31,
	2005			2004
DEFERRED TAX ASSETS
Regulatory liabilities:
Asset retirement obligation	$	189,726		$	182,086
Federal excess deferred income tax		14,446			16,341
Deferred fuel and purchased power – mark-to-market		11,923			—
Other		29,720			8,282
Risk management and trading activities		171,640			15,172
Pension liability		72,376			80,184
Deferred gain on Palo Verde Unit 2 sale-leaseback		17,868			19,816
Other		71,567			73,925
Total deferred tax assets		579,266			395,806
DEFERRED TAX LIABILITIES
Plant-related		(1,426,158	)		(1,424,859	)
Risk management and trading activities		(301,709	)		(33,808	)
Regulatory assets:
Deferred fuel and purchased power		(67,461	)		—
Other		(63,551	)		(54,767	)
Total deferred tax liabilities		(1,858,879	)		(1,513,434	)
Accumulated deferred income taxes – net	$	(1,279,613	)	$	(1,117,628	)

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S-3. Selected Quarterly Financial Data (Unaudited)

     Quarterly financial information for 2005 and 2004 is as follows (dollars in thousands):

	2005 Quarter Ended,								2005
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	441,292	$	588,757	$	748,348	$	492,396	$	2,270,793
Operations and maintenance		142,294		138,314		149,198		162,135		591,941
Operating income		58,743		95,321		174,415		53,134		381,613
Net income		27,045		63,998		61,093		18,343		170,479

	2004 Quarter Ended,								2004
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	441,102	$	569,658	$	700,512	$	485,849	$	2,197,121
Operations and maintenance		125,912		126,871		143,338		144,156		540,277
Operating income		67,050		83,604		129,682		48,645		328,981
Net income		34,429		54,934		95,192		15,072		199,627

S-4. Derivative and Energy Trading Accounting

     APS is exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels and emissions allowances and credits. As of December 31, 2005, APS hedged certain exposures to these risks for a maximum of 3.25 years.

Cash Flow Hedges

     The changes in the fair value of APS’ hedged positions included in the APS Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2005, 2004 and 2003 are comprised of the following (dollars in thousands):

	2005		2004			2003
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	14,452	$	(1,570	)	$	7,033
Gains from the change in options time value excluded from measurement of effectiveness		620		185			181
Gains from the discontinuance of cash flow hedges		473		575			—

     During 2006, APS estimates that a net gain of $158 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).

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     APS’ assets and liabilities from risk management and trading activities are presented in two categories:

• Regulated Electricity – non-trading derivative instruments that hedge APS’ purchases and sales of electricity and fuel for its Native Load requirements; and

• Marketing and Trading – both non-trading and trading derivative instruments.

     The following table summarizes APS’ assets and liabilities from risk management and trading activities at December 31, 2005 and 2004 (dollars in thousands):

December 31, 2005

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	516,399	$	228,873	$	(335,801	)	$	(74,787	)	$	334,684
Margin account and options		1,814		—		(124,165	)		—			(122,351	)
Marketing & Trading:
Mark-to-market		13,027		5,499		(20,172	)		(8,778	)		(10,424	)
Options at cost		1,683		—		—			(209	)		1,474
Total	$	532,923	$	234,372	$	(480,138	)	$	(83,774	)	$	203,383

December 31, 2004

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	45,220	$	19,417	$	(19,191	)	$	(12,000	)	$	33,446
Margin account and options		18,821		118		(8,879	)		—			10,060
Marketing & Trading:
Mark-to-market		6,389		581		(6,222	)		(1,124	)		(376	)
Options at cost		—		7		—			—			7
Total	$	70,430	$	20,123	$	(34,292	)	$	(13,124	)	$	43,137

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was a liability of $123 million at December 31, 2005 and $9 million at December 31, 2004 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

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     Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. No collateral was provided to counterparties at December 31, 2005 or at December 31, 2004. Collateral provided to us by counterparties was $175 million at December 31, 2005 and $6 million at December 31, 2004, and is included in other current liabilities on the Balance Sheets.

S-5. Other Income and Other Expense

     The following table provides detail of APS’ other income and other expense for the years ended December 31, 2005, 2004 and 2003 (dollars in thousands):

	Year Ended December 31,
	2005			2004			2003
Other income:
Interest income	$	14,513		$	22,354		$	15,660
Miscellaneous		2,736			2,021			1,892
Investment gains – net		1,705			3,192			2,107
Asset dispositions		3,187			3,026			618
Total other income	$	22,141		$	30,593		$	20,277
Other expense:
Non-operating costs (a)	$	(11,706	)	$	(8,923	)	$	(9,361	)
Asset dispositions		(9,759	)		(1,212	)		(1,522	)
Miscellaneous		(1,739	)		(3,681	)		(2,079	)
Total other expense	$	(23,204	)	$	(13,816	)	$	(12,962	)

(a) As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and other costs excluded from utility rate recovery).

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S-6. Related Party Transactions

     From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s subsidiaries. The following table summarizes the amounts included in the APS Statements of Income and Balance Sheets related to transactions with affiliated companies (dollars in millions):

	Year Ended December 31,
	2005		2004		2003
Electric operating revenues:
Pinnacle West – marketing and trading	$	6	$	13	$	12
Pinnacle West Energy		2		3		9
Total	$	8	$	16	$	21
Fuel and purchased power costs:
Pinnacle West Energy	$	61	$	75	$	70
Capital expenditures:
Pinnacle West – marketing and trading	$	—	$	11	$	—
Pinnacle West		—		22		—
Total	$	—	$	33	$	—
Other:
Pinnacle West Energy:
Lease expense	$	—	$	—	$	10
Interest income	$	7	$	19	$	12
Pinnacle West:
Equity infusion from Pinnacle West (see Note 3)	$	250	$	—	$	—

	As of December 31,
	2005			2004
Net intercompany receivables (payables):
Pinnacle West Energy	$	—		$	467
Pinnacle West – marketing and trading		82			19
APS Energy Services		2			9
Pinnacle West		(2	)		(5	)
Total	$	82		$	490

     Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. APS purchases electricity from and sells electricity to APS Energy Services; however, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 2-3.”

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     Intercompany receivables primarily include amounts related to the intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

     The December 31, 2004 intercompany receivable included a $500 million loan that APS made to Pinnacle West Energy. This loan was repaid in May 2005.

     APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and to rate base the PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base disallowance of approximately $150 million. Due to depreciation and other miscellaneous factors, the actual disallowance was $139 million at December 31, 2005. This transfer was completed on July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of approximately $84 million in 2005. In connection with the transfer, APS recorded a $500 million intercompany payable to Pinnacle West Energy. On October 3, 2005, APS settled the intercompany payable.

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PINNACLE WEST CAPITAL CORPORATION

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS

(dollars in thousands)

Column A	Column B			Column C				Column D			Column E
				Additions
	Balance at			Charged to		Charged					Balance
	beginning			cost and		to other					at end of
Description	of period			expenses		accounts		Deductions			period
Real estate valuation reserves:
2005	$	—		$	—	$	—	$	—		$	—
2004		—			—		—		—			—
2003		1,661			—		—		1,661	(a)		—
Reserve for uncollectibles:
2005	$	4,896		$	2,638	$	—	$	2,555		$	4,979
2004		9,223			2,868		—		7,195			4,896
2003		9,607			3,715		—		4,099			9,223
Reserve for contract losses:
2005	$	—		$	—	$	—	$	—		$	—
2004		—			—		—		—			—
2003		13,000	(b)		—		—		13,000			—

(a)	Represents pro-rata allocations for sale of land.
(b)	Contract losses related to NAC (see Note 22 – Discontinued Operations – NAC).

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ARIZONA PUBLIC SERVICE COMPANY

SCHEDULE II — RESERVE FOR UNCOLLECTIBLES

(dollars in thousands)

Column A	Column B		Column C				Column D		Column E
			Additions
	Balance at		Charged to		Charged				Balance
	beginning		cost and		to other				at end of
Description	of period		expenses		accounts		Deductions		period
Reserve for uncollectibles:
2005	$	3,444	$	2,638	$	—	$	2,514	$	3,568
2004		3,743		2,446		—		2,745		3,444
2003		1,341		5,716		—		3,314		3,743

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

     None.

ITEM 9A. CONTROLS AND PROCEDURES

     (a) Disclosure Controls and Procedures

     The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78aet seq.) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

     Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of December 31, 2005. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

     APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of December 31, 2005. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.

(b) Management’s Annual Reports on Internal Control Over Financial Reporting

     Reference is made to “Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)” on page 67 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 126 of this report.

(c) Attestation Reports of the Registered Public Accounting Firm

     Reference is made to “Report of Independent Registered Public Accounting Firm” on page 68 of this report and “Report of Independent Registered Public Accounting Firm” on page 127 of this report on the internal control over financial reporting of Pinnacle West and APS, respectively.

(d) Changes In Internal Control Over Financial Reporting

     The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of

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financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

     No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended December 31, 2005 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

     None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF PINNACLE WEST

     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance,” “Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting Compliance” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 17, 2006 (the “2006 Proxy Statement”) and to the Supplemental Item — “Executive Officers of Pinnacle West” in Part I of this report.

     Pinnacle West has adopted a Code of Ethics for Financial Professionals that applies to professional employees in the areas of finance, accounting, internal audit, energy risk management, marketing and trading financial control, tax, investor relations, and treasury and also includes Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and officers holding substantially equivalent positions at Pinnacle West’s subsidiaries. The Code of Ethics for Financial Professionals is posted on Pinnacle West’s website at www.pinnaclewest.com. Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Professionals by posting such information on Pinnacle West’s website.

ITEM 11. EXECUTIVE COMPENSATION

     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance — How are directors compensated?”; “Performance Graph”; and “Executive Compensation” in the 2006 Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners and Management

     Reference is hereby made to “How Many Shares of Pinnacle West Stock are Owned by Management and Large Shareholders?” in the 2006 Proxy Statement.

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Securities Authorized For Issuance Under Equity Compensation Plans

     The following table sets forth information as of December 31, 2005 with respect to our compensation plans and individual compensation arrangements under which our equity securities were authorized for issuance.

Equity Compensation Plan Information

					Number of securities
	Number of				remaining available for
	securities to be		Weighted-average		future issuance under
	issued upon exercise		exercise price of		equity compensation
	of outstanding		outstanding		plans (excluding
	options, warrants		options, warrants		securities reflected in
	and rights		and rights		column (a))
Plan category	(a)		(b)		(c)
Equity compensation plans approved by security holders		1,695,772	$	39.65		4,245,671
Equity compensation plans not approved by security holders		—		—		145,100
Total		1,695,772	$	39.65		4,390,771

Equity Compensation Plans Approved By Security Holders

     The Company has four equity compensation plans that were approved by its shareholders: the Pinnacle West Capital Corporation Stock Option and Incentive Plan, under which no new options may be granted; the Pinnacle West Capital Corporation Directors Stock Option Plan, under which no new options may be granted; the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan, under which no stock awards may be granted; and the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan. See Note 16 for additional information regarding these plans.

Equity Compensation Plans Not Approved By Security Holders

     The Company has one equity compensation plan, the Pinnacle West Capital Corporation 2000 Director Equity Plan (the “2000 Plan”), for which the approval of shareholders was not required.

     Number of Shares Subject to the 2000 Plan. The total number of shares of the Company’s common stock granted under the 2000 Plan may not exceed 200,000. In the case of a significant corporate event, such as a reorganization, merger or consolidation, the 2000 Plan provides for adjustment of the above limit, the number of shares to be awarded automatically to eligible non-employee directors and the number of shares of the Company’s common stock non-employee directors are required to own to receive an annual grant of common stock under the 2000 Plan.

     Eligibility for Participation. Only non-employee directors may participate in the 2000 Plan. A non-employee director is an individual who is a director of the Company but who is not also an employee of the Company or any of its subsidiaries.

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     Terms of Awards. The 2000 Plan provides for: (1) annual grants of common stock to eligible non-employee directors, (2) discretionary grants of common stock to eligible non-employee directors and (3) grants of non-qualified stock options to eligible non-employee directors.

     Annual Grants of Stock

     Each individual who is a non-employee director as of July 1 of a calendar year, and who meets requirements of ownership of the Company’s common stock set forth below, will receive 1,100 shares of the Company’s common stock for such calendar year. In the first calendar year in which a non-employee director is eligible to participate in the 2000 Plan, he or she must own at least 900 shares of the Company’s common stock as of December 31 of the same calendar year to receive a grant of 1,100 shares of the Company’s common stock. If the non-employee director owns 900 shares of common stock as of June 30, he or she will receive a grant of 1,100 shares of common stock as of July 1 of the same calendar year. If the non-employee director does not own 900 shares of the Company’s common stock as of June 30, but acquires the necessary shares on or before December 31 of the same year, he or she will receive a grant of 1,100 shares of common stock within a reasonable time after the Company verifies that the requisite number of shares has been acquired. In each subsequent year, the number of shares of the Company’s common stock the non-employee director must own to receive a grant of 900 shares of common stock will increase by 1,100 shares, until reaching a maximum of 4,500 shares. In each of the subsequent years, the non-employee director must own the requisite number of shares of the Company’s common stock as of June 30 of the relevant calendar year.

     Discretionary Grants of Stock

     The Human Resources Committee of the Board of Directors administers the 2000 Plan and may grant shares of the Company’s common stock to non-employee directors in its discretion. No discretionary grants of common stock have been made under the 2000 Plan.

     Grants of Non-qualified Stock Options

     The Committee can grant non-qualified stock options under the 2000 Plan. The terms and the conditions of the option grant, including the exercise price per share, which may not be less than fair market value on the date of grant, will be set by the Committee in a written award agreement. The Committee will determine the time or times at which any such options may be exercised in whole or in part. The Committee will also determine the performance or other conditions, if any, that must be satisfied before all or part of an option may be exercised. Any such options granted to a participant will expire on the tenth anniversary date of the date of grant, unless the option is earlier terminated, forfeited or surrendered pursuant to a provision of the 2000 Plan or the applicable award agreement. Notwithstanding the foregoing, if a participant ceases to be a Company director for any reason, including death or disability, any such options held by that participant will expire on the second anniversary of the date on which the participant ceased to be a Company director, unless otherwise provided in the applicable award agreement. Unless the Committee provides otherwise, no such options may be sold, transferred, pledged, assigned or otherwise alienated, other than by will, the laws of descent and distribution, or under any other circumstances allowed by the Committee. No options have been granted under the 2000 Plan.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Reference is hereby made to “How Many Shares of Pinnacle West Stock are Owned by Management and Large Shareholders?”; “Does the Company Have Any Related Party Transactions to Disclose?”; “Executive Compensation — Human Resources Committee Interlocks and Insider Participation” and “What are the Company’s Defined Benefit Plans — Employment and Change-in-Control Agreement” in the 2006 Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTANT
FEES AND SERVICES

Pinnacle West

     Reference is hereby made to “Audit Matters — What fees were paid to our independent registered public accountants in 2005 and 2004?” and “- What are the Audit Committee’s pre-approval policies?” in the 2006 Proxy Statement.

APS

     The following fees were paid to APS’ independent registered public accountants, Deloitte & Touche LLP, for the last two fiscal years:

Type of Service	2004		2005
Audit Fees (1)	$	1,910,089	$	2,167,319
Audit-Related Fees (2)		318,750		33,899
Tax Fees (3)		1,559,928		1,025

(1)	The aggregate fees billed for services rendered for the audit of annual financial statements and for review of financial statements included in Forms 10-Q.
(2)	The aggregate fees billed for assurance services that are reasonably related to the performance of the audit or review of the financial statements that are not included in Audit Fees reported above, which primarily consist of fees for Sarbanes-Oxley Section 404 readiness.
(3)	The aggregate fees billed primarily for investment tax credit services, tax compliance and tax planning.

     Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’ independent public accountants. The Audit Committee has delegated to the Chairman of the Audit Committee the authority to pre-approve audit and non-audit services to be performed by the independent public accountants if the services are not expected to cost more than $50,000. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS were pre-approved by the Audit Committee.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements and Financial Statement Schedules

     See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.

Exhibits Filed

     The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
3.1	Pinnacle West	Articles of Incorporation, restated as of July 29, 1988	19.1 to Pinnacle West’s September 1988 Form 10-Q Report, File No. 1-8962	11-14-88
3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of December 14, 2005	3.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report	12-15-05
3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’ Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	9-29-93
3.4	APS	Arizona Public Service Company Bylaws, amended as of June 23, 2004	3.1 to APS’ June 30, 2004 Form 10-Q Report, File No. 1-4473	8-9-04
4.12	Pinnacle West APS	Agreement, dated March 21, 1994, relating to the filing of instruments defining the rights of holders of APS long-term debt not in excess of 10% of APS’ total assets	4.1 to APS’ 1993 Form 10-K Report, File No. 1-4473	3-30-94

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Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
4.13	Pinnacle West APS	Indenture dated as of January 1, 1995 among APS and The Bank of New York, as Trustee	4.6 to APS’ Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473	1-11-95
4.14	Pinnacle West APS	First Supplemental Indenture dated as of January 1, 1995	4.4 to APS’ Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473	1-11-95
4.15	Pinnacle West APS	Indenture dated as of November 15, 1996 among APS and The Bank of New York, as Trustee	4.5 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333- 15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473	11-22-96
4.16	Pinnacle West APS	First Supplemental Indenture	4.6 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473	11-22-96
4.17	Pinnacle West APS	Second Supplemental Indenture	4.10 to APS’ Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report, File No. 1-4473	4-9-97

152

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
4.18	Pinnacle West APS	Third Supplemental Indenture	10.2 to Pinnacle West’s March 2003 Form 10-Q Report, File No. 1-8962	5-15-03
4.19	Pinnacle West	Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Senior Debt Securities	4.1 to Pinnacle West’s Registration Statement No. 333-53150	12-21-00
4.20	Pinnacle West	First Supplemental Indenture dated as of March 15, 2001	4.1 to Pinnacle West’s Registration Statement No. 333-52476 by means of March 26, 2001 Form 8-K Report, File No. 1-8962	3-26-01
4.21	Pinnacle West	Second Supplemental Indenture dated as of November 1, 2003	4.20 to Pinnacle West’s Registration Statement No. 333-101457 by means of November 6, 2003 Form 8-K Report, File No. 1-8962	11-12-03
4.22	Pinnacle West	Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to subordinated Debt Securities	4.2 to Pinnacle West’s Registration Statement No. 333-53150	12-21-00
4.23	Pinnacle West	Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value	4.2 to Pinnacle West’s 1988 Form 10-K Report, File No. 1-8962	3-31-89
4.24	Pinnacle West	Agreement, dated March 29, 1988, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets	4.1 to Pinnacle West’s 1987 Form 10-K Report, File No. 1-8962	3-30-88

153

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
4.25	Pinnacle West APS	Indenture dated as of January 15, 1998 among APS and The Chase Manhattan Bank, as Trustee	4.10 to APS’ Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473	1-16-98
4.26	Pinnacle West APS	First Supplemental Indenture dated as of January 15, 1998	4.3 to APS’ Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473	1-16-98
4.27	Pinnacle West APS	Second Supplemental Indenture dated as of February 15, 1999	4.3 to APS’ Registration Statement Nos. 333-27551 and 333-58445 by means of February 18, 1999 Form 8-K Report, File No. 1-4473	2-22-99
4.28	Pinnacle West APS	Third Supplemental Indenture dated as of November 1, 1999	4.5 to APS’ Registration Statement Nos. 333-58445 by means of November 2, 1999 Form 8-K Report, File No. 1-4473	11-5-99
4.29	Pinnacle West APS	Fourth Supplemental Indenture dated as of August 1, 2000	4.1 to APS’ Registration Statement No. 333-58445 and 333-94277 by means of August 2, 2000 Form 8-K Report, File No. 1-4473	8-4-00
4.30	Pinnacle West APS	Fifth Supplemental Indenture dated as of October 1, 2001	4.1 to APS’ September 2001 Form 10-Q, File No. 1-4473	11-6-01
4.31	Pinnacle West APS	Sixth Supplemental Indenture dated as of March 1, 2002	4.1 to APS’ Registration Statement Nos. 333-63994 and 333-83398 by means of February 26, 2002 Form 8-K Report, File No. 1-4473	2-28-02

154

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
4.32	Pinnacle West APS	Seventh Supplemental Indenture dated as of May 1, 2003	4.1 to APS’ Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report, File No. 1-8962	5-9-03
4.33	Pinnacle West APS	Eighth Supplemental Indenture dated as of June 15, 2004	4.1 to APS’ Registration Statement No. 333-106772 by means of June 24, 2004 Form 8-K Report, File No. 1-4473	6-28-04
4.34	Pinnacle West APS	Ninth Supplemental Indenture dated as of August 15, 2005	4.1 to APS’ Registration Statements Nos. 333-106772 and 333-121512 by means of August 17, 2005 Form 8-K Report, File No. 1-4473	8-22-05
4.35	Pinnacle West	Amended and Restated Rights Agreement, dated as of March 26, 1999, between Pinnacle West Capital Corporation and BankBoston, N.A., as Rights Agent, including (i) as Exhibit A thereto the form of Amended Certificate of Designation of Series A Participating Preferred Stock of Pinnacle West Capital Corporation, (ii) as Exhibit B thereto the form of Rights Certificate and (iii) as Exhibit C thereto the Summary of Right to Purchase Preferred Shares	4.1 to Pinnacle West’s March 22, 1999 Form 8-K Report, File No. 1-8962	4-19-99
4.36	Pinnacle West	Amendment to Rights Agreement, effective as of January 1, 2002	4.1 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	5-15-02

155

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
4.37	Pinnacle West	Second Amended and Restated Investor’s Advantage Plan	4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962	8-9-04
10.1	Pinnacle West APS	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 19, 2003	10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04
10.2	Pinnacle West APS	Amendment No. 7 to the Decommissioning Trust Agreement (PVNGS Unit 2), dated as of December 19, 2003	10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04
10.3	Pinnacle West APS	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 19, 2003	10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04
10.4	Pinnacle West APS	Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.6 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04
10.5	Pinnacle West APS	Pinnacle West Capital Corporation Supplement Excess Benefit Retirement Plan, amended and restated as of January 1, 2003	10.7 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04

156

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.6	Pinnacle West APS	Two separate Decommissioning Trust Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee	10.2 to APS’ September 1991 Form 10-Q Report, File No. 1-4473	11-14-91
10.7	Pinnacle West APS	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 1, 1994	10.1 to APS’ 1994 Form 10- K Report, File No. 1-4473	3-30-95
10.8	Pinnacle West APS	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 1, 1994	10.2 to APS’ 1994 Form 10-K Report, File No. 1-4473	3-30-95
10.9	Pinnacle West APS	Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991	10.4 to APS’ 1996 Form 10-K Report , File No. 1-4473	3-28-97
10.10	Pinnacle West APS	Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991	10.6 to APS’ 1996 Form 10-K Report, File No. 1-4473	3-28-97

157

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.11	Pinnacle West APS	Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992, among APS, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2	10.1 to Pinnacle West’s 1991 Form 10-K Report, File No. 1-8962	3-26-92
10.12	Pinnacle West APS	First Amendment to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992	10.2 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
10.13	Pinnacle West APS	Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994	10.3 to APS’ 1994 Form 10-K Report, File No. 1-4473	3-30-95
10.14	Pinnacle West APS	Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of January 31, 1992	10.1 to APS’ June 1996 Form 10-Q Report, File No. 1-4473	8-9-96

158

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.15	Pinnacle West APS	Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992	APS 10.5 to APS’ 1996 Form 10-K Report, File No. 1-4473	3-28-97
10.16	Pinnacle West APS	Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 30, 2000	10.1 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	5-15-02
10.17	Pinnacle West APS	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of March 18, 2002	10.2 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	5-15-02
10.18	Pinnacle West APS	Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of March 18, 2002	10.3 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	5-15-02
10.19	Pinnacle West APS	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of March 18, 2002	10.4 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	5-15-02
10.20	Pinnacle West APS	Asset Purchase and Power Exchange Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991	10.1 to APS’ June 1991 Form 10-Q Report, File No. 1-4473	8-8-91

159

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.21	Pinnacle West APS	Long-Term Power Transaction Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8, 1991	10.2 to APS’ June 1991 Form 10-Q Report, File No. 1-4473	8-8-91
10.22	Pinnacle West APS	Amendment No. 1 dated April 5, 1995 to the Long-Term Power Transaction Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and APS	10.3 to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96
10.23	Pinnacle West APS	Restated Transmission Agreement between PacifiCorp and APS dated April 5, 1995	10.4 to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96
10.24	Pinnacle West APS	Contract among PacifiCorp, APS and United States Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995	10.5 to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96
10.25	Pinnacle West APS	Reciprocal Transmission Service Agreement between APS and PacifiCorp dated as of March 2, 1994	10.6 to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96

160

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.26	Pinnacle West APS	Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high -level radioactive waste, ANPP	10.31 to Pinnacle West’s Form S-14 Registration Statement, File No. 2-96386	3-13-85
10.27	Pinnacle West APS	Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant	5.01 to APS’ Form S-7 Registration Statement, File No. 2-59644	9-1-77
10.28	Pinnacle West APS	Supplemental and Additional Indenture of Lease, including amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant	5.02 to APS’ Form S-7 Registration Statement, File No. 2-59644	9-1-77
10.29	Pinnacle West APS	Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease Four Corners, dated April 25, 1985	10.36 to Pinnacle West’s Registration Statement on Form 8-B Report, File No. 1-8962	7-25-85
10.30	Pinnacle West APS	Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site	5.04 to APS’ Form S-7 Registration Statement, File No. 2-59644	9-1-77
10.31	Pinnacle West APS	Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985	10.37 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962	7-25-85

161

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.32	Pinnacle West APS	Application and Grant of Arizona Public Service Company rights- of-way and easements, Four Corners Plant Site	5.05 to APS’ Form S-7 Registration Statement, File No. 2-59644	9-1-77
10.33	Pinnacle West APS	Four Corners Project Co-Tenancy Agreement Amendment No. 6	10.7 to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962	3-14-01
10.34	Pinnacle West APS	Application and Amendment No. 1 to Grant of Arizona Public Service Company rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985	10.38 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962	7-25-85
10.35	Pinnacle West APS	Indenture of Lease, Navajo Units 1, 2, and 3	5(g) to APS’ Form S-7 Registration Statement, File No. 2-36505	3-23-70
10.36	Pinnacle West APS	Application of Grant of rights-of-way and easements, Navajo Plant	5(h) to APS Form S-7 Registration Statement, File No. 2-36505	3-23-70
10.37	Pinnacle West APS	Water Service Contract Assignment with the United States Department of Interior, Bureau of Reclamation, Navajo Plant	5(l) to APS’ Form S-7 Registration Statement, File No. 2-394442	3-16-71

162

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.38	Pinnacle West APS	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto	10. 1 to APS’ 1988 Form 10-K Report, File No. 1-4473	3-8-89
10.39	Pinnacle West APS	Amendment No. 13, dated as of April 22, 1991, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	10.1 to APS’ March 1991 Form 10-Q Report, File No. 1-4473	5-15-91

163

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.40	Pinnacle West APS	Amendment No. 14 to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	99.1 to Pinnacle West’s June 2000 Form 10-Q Report, File No. 1-8962	8-14-00
10.41c	Pinnacle West APS	Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	4.3 to APS’ Form S-3 Registration Statement, File No. 33-9480	10-24-86
10.42c	Pinnacle West APS	Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	10.5 to APS’ September 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	12-4-86

164

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.43c	Pinnacle West APS	Amendment No. 2 dated as of June 1, 1987 to Facility Lease dated as of August 1, 1986 between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.3 to APS’ 1988 Form 10-K Report, File No. 1-4473	3-8-89
10.44c	Pinnacle West APS	Amendment No. 3, dated as of March 17, 1993, to Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.3 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
10.45	Pinnacle West APS	Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	10.1 to APS’ November 18, 1986 Form 8-K Report, File No. 1-4473	1-20-87

165

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.46	Pinnacle West APS	Amendment No. 1, dated as of August 1, 1987, to Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	4.13 to APS’ Form S-3 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473	8-24-87
10.47	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	10.4 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
10.48b	Pinnacle West APS	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 18, 2003

166

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.49b	Pinnacle West APS	Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996	10.14 to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.50b	Pinnacle West APS	First Amendment dated December 7, 1999 to the Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans	10.15 to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.51b	Pinnacle West APS	Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986	10.1 to APS’ June 1986 Form 10-Q Report, File No. 1-4473	8-13-86
10.52b	Pinnacle West APS	Second Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993	10.2 to APS’ 1993 Form 10-K Report, File No. 1-4473	3-30-94
10.53b	Pinnacle West APS	Third Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of May 1, 1993	10.1 to APS’ September 1994 Form 10-Q Report, File No. 1-4473	11-10-94

167

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.54b	Pinnacle West APS	Fourth Amendment to the Arizona Public Service Company Directors Deferred Compensation Plan effective as of January 1, 1999	10.8 to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.55b	Pinnacle West APS	Arizona Public Service Company Deferred Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987 respectively	10.4 to APS’ 1988 Form 10-K Report, File No. 1-4473	3-8-89
10.56b	Pinnacle West APS	Third Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993	10.3 to APS’ 1993 Form 10-K Report, File No. 1-4473	3-30-94
10.57b	Pinnacle West APS	Fourth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective as of May 1, 1993	10.2 to APS’ September 1994 Form 10-Q Report, File No. 1-4473	11-10-94
10.58b	Pinnacle West APS	Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 1997	10.3 to APS’ 1996 Form 10-K Report, File No. 1-4473	3-28-97
10.59b	Pinnacle West APS	Sixth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 2001	10.8 to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962	3-14-01
10.60b	Pinnacle West APS	Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996	10.10 to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96

168

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.61b	Pinnacle West APS	First Amendment effective as of January 1, 1999, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.7 to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.62b	Pinnacle West APS	Second Amendment effective January 1, 2000 to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.10 to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.63b	Pinnacle West APS	Third Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	10.3 to Pinnacle West’s March 2003 Form 10-Q Report, File No. 1-8962	5-15-03
10.64b	Pinnacle West APS	Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective January 1, 2003.
10.65b	Pinnacle West APS	Schedules of William J. Post and Jack E. Davis to Arizona Public Service Company Deferred Compensation Plan, as amended.	10.2 to Pinnacle West Form 10-K Report, File No. 1-8962	3-31-03

169

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.66b	Pinnacle West APS	Letter Agreement dated July 28, 1995 between Arizona Public Service Company and Armando B. Flores	10.16 to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.67b	Pinnacle West APS	Letter Agreement dated December 21, 1993, between APS and William L. Stewart	10.7 to APS’ 1994 Form 10-K Report, File No. 1-4473	3-30-96
10.68b	Pinnacle West APS	Letter Agreement dated August 16, 1996 between APS and William L. Stewart	10.8 to APS’ 1996 Form 10-K Report, File No. 1-4473	3-28-97

170

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.69b	Pinnacle West APS	Letter Agreement between APS and William L. Stewart	10.2 to APS’ September 1997 Form 10-Q Report, File No. 1-4473	11-12-97
10.70b	Pinnacle West APS	Letter Agreement dated December 13, 1999 between APS and William L. Stewart	10.9 to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.71b	Pinnacle West APS	Amendment to Letter Agreement, effective as of January 1, 2002, between APS and William L. Stewart	10.1 to Pinnacle West’s June 2002 Form 10-Q Report, File No. 1-8962	8-13-02
10.72b	Pinnacle West APS	Letter Agreement dated October 3, 1997 between Arizona Public Service Company and James M. Levine	10.17 to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.73b	Pinnacle West APS	Employment Agreement dated February 27, 2003 between APS and James M. Levine	10.1 to Pinnacle West’s March 2003 Form 10-Q Report, File No. 1-8962	5-15-03
10.74b	Pinnacle West APS	Summary of James M. Levine Retirement Benefits	10.2 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	5-15-02
10.75b	Pinnacle West APS	Employment Agreement, effective as of October 1, 2002, between APS and James M. Levine	10.1 to Pinnacle West’s November 2002 Form 10-Q Report, File No. 1-8962	11-14-02
10.75.1b	Pinnacle West APS	Amendment to Agreement between APS and James M. Levine effective October 11, 2002	10.2 to Pinnacle West’s September 2004 Form 10-Q Report, File No. 1-8962	11-8-04

171

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.75.2b	Pinnacle West APS	Amendment to Agreement between APS and James M. Levine effective as of 1-1-05	10.79.2 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.76b	Pinnacle West APS	Letter Agreement dated June 28, 2001 between Pinnacle West Capital Corporation and Steve Wheeler	10.4 to Pinnacle West’s 2002 Form 10-K Report, File No. 1-8962	3-31-03
10.77bd	Pinnacle West APS	Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries
10.78b	Pinnacle West APS	Pinnacle West Capital Corporation 1994 Long- Term Incentive Plan, effective as of March 23, 1994	A to the Proxy Statement for the Plan Report for Pinnacle West’s 1994 Annual Meeting of Shareholders, File No. 1-8962	4-16-94
10.79b	Pinnacle West APS	First Amendment dated December 7, 1999 to the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan	10.12 to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

172

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.80b	Pinnacle West APS	Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.5 to Pinnacle West’s 2002 Form 10-K Report	3-31-03
10.81b	Pinnacle West	Pinnacle West Capital Corporation 2000 Director Equity Plan	99.1 to Pinnacle West’s Registration Statement on Form S-8 (No. 333-40796), File No. 1-8962	7-3-00
10.82	Pinnacle West APS	Agreement No. 13904 (Option and Purchase of Effluent) with Cities of Phoenix, Glendale, Mesa, Scottsdale, Tempe, Town of Youngtown, and Salt River Project Agricultural Improvement and Power District, dated April 23, 1973	10.3 to APS’ 1991 Form 10-K Report, File No. 1-4473	3-19-92
10.83	Pinnacle West APS	Territorial Agreement between the Company and Salt River Project	10.1 to APS’ March 1998 Form 10-Q Report, File No. 1-4473	5-15-98
10.84	Pinnacle West APS	Power Coordination Agreement between the Company and Salt River Project	10.2 to APS’ March 1998 Form 10-Q Report, File No. 1-4473	5-15-98

173

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.85	Pinnacle West APS	Memorandum of Agreement between the Company and Salt River Project	10.3 to APS’ March 1998 Form 10-Q Report, File No. 1-4473	5-15-98
10.86	Pinnacle West APS	Addendum to Memorandum of Agreement between APS and Salt River Project dated as of May 19, 1998	10.2 to APS’ May 19, 1998 Form 8-K Report, File No. 1-4473	6-26-98
10.87 bd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	12-15-05
10.88 bd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.1 to Pinnacle West/APS December 31, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	2-1-06
10.89bd	Pinnacle West APS	Performance Accelerated Stock Option Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.98 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05

174

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.90bd	Pinnacle West APS	Stock Ownership Incentive Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.99 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.91bd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.92 bd	Pinnacle West APS	Summary of 2006 CEO Variable Incentive Plan and Officer Variable Incentive Plan
10.93	Pinnacle West APS	Amended and Restated Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, as Administrative Agent and Issuing Bank, dated as of July 22, 2002	10.100 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.94	Pinnacle West APS	Three-Year Credit Agreement dated as of May 21, 2004 between APS as Borrower, and the banks, financial institutions and other institutional lenders and initial issuing banks listed on the signature pages thereof	10.101 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.95	Pinnacle West APS	Amended and Restated Five-Year Credit Agreement dated as of December 9, 2005 between APS, as Borrower, Citibank, N.A., as Agent, and the lenders and other parties thereto
10.96	Pinnacle West	$200,000,000 Senior Notes Uncommitted Master Shelf Agreement dated as of February 28, 2006

175

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.97	Pinnacle West	Amended and Restated Credit Agreement dated as of December 9, 2005 among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Agent, and the other agent parties thereto
10.98	Pinnacle West APS	Agreement between Pinnacle West Energy Corporation and Arizona Public Service Company for Transportation and Treatment of Effluent by and between Pinnacle West Energy Corporation and APS dated as of the 10th day of April, 2001	10.102 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.99	Pinnacle West APS	Agreement for the Transfer and Use of Wastewater and Effluent by and between APS, SRP and PWE dated June 1, 2001	10.103 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.100	Pinnacle West APS	Agreement for the Sale and Purchase of Wastewater Effluent dated November 13, 2000, by and between the City of Tolleson, Arizona, APS and SRP	10.104 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.101	Pinnacle West APS	Operating Agreement for the Co-Ownership of Wastewater Effluent dated November 16, 2000 by and between APS and SRP	10.105 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05

176

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.102	Pinnacle West APS	Asset Purchase Agreement by and between PPL Sundance Energy, LLC, as Seller, and APS, as Purchaser, dated as of June 1, 2004	10.1 to Pinnacle West’s June 2004 Form 10-Q Report, File No. 1-8962	8-9-04
10.102.1	Pinnacle West APS	Amendment to Asset Purchase Agreement	99.1 to Pinnacle West’s November 18, 2004 Form 8-K Report, File No. 1-8962	12-20-04
10.103	Pinnacle West APS	Credit Agreement dated as of October 19, 2004 among Pinnacle West, other lenders, and JPMorgan Chase Bank, as Administrative Agent	10.1 to Pinnacle West’s September 2004 Form 10-Q Report, File No. 1-8962	11-8-04
10.104b	Pinnacle West APS	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, amended and restated as of January 1, 2003	10.7 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	3-15-04
10.105b	Pinnacle West APS	Pinnacle West Capital Corporation and Arizona Public Service Company Directors’ Retirement Plan, as amended and restated on June 21, 2000	99.2 to Pinnacle West’s Registration Statement on Form S-8 No. 333-40796, File No. 1-8962	7-3-00

177

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
10.106	Pinnacle West APS	Agreement for the Sale and Purchase of Wastewater Effluent with City of Tolleson and Salt River Agricultural Improvement and Power District, dated June 12, 1981, including Amendment No. 1 dated as of November 12, 1981 and Amendment No. 2 dated as of June 4, 1986	10.4 to APS’ 1991 Form 10-K Report, File 1-4473	3-19-92
10.107	Pinnacle West APS	Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996, Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998.
10.108	Pinnacle West APS	Navajo Project Participation Agreement dated as of September 30, 1969, and Amendment and Supplement No. 1 dated as of January 16, 1970, and Coordinating Committee Agreement No. 1 dated as of September 31, 1971.
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
21.1	Pinnacle West	Subsidiaries of Pinnacle West
23.1	Pinnacle West	Consent of Deloitte & Touche LLP
23.2	APS	Consent of Deloitte & Touche LLP
31.1	Pinnacle West	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

178

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
31.2	Pinnacle West	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3	APS	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

179

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.1	Pinnacle West APS	Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	4.2 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.2	Pinnacle West APS	Supplemental Indenture to Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	4.3 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.3c	Pinnacle West APS	Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	28.1 to APS’ September 1992 Form 10-Q Report, File No. 1-4473	11-9-92

180

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.4c	Pinnacle West APS	Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	10.8 to APS’ September 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8, File No. 1-4473	12-4-86
99.5c	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	28.4 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93

181

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.6c	Pinnacle West APS	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.5 to APS’ Form S-3 Registration Statement, File No. 33-9480	10-24-86
99.7c	Pinnacle West APS	Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	10.6 to APS’ September 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	12-4-86

182

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.8c	Pinnacle West APS	Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee	4.4 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.9c	Pinnacle West APS	Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.3 to APS’ Form S-3 Registration Statement, File No. 33-9480	10-24-86
99.10c	Pinnacle West APS	Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	10.10 to APS’ September 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8, File No. 1-4473	12-4-86

183

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.11c	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.6 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.12	Pinnacle West APS	Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Report Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, APS, and the Owner Participant named therein	28.2 to APS’ September 1992 Form 10-Q Report, File No. 1-4473	11-9-92

184

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.13	Pinnacle West APS	Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, APS, and the Owner Participant named therein	28.20 to APS’ Form S-3 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473	8-10-87
99.14	Pinnacle West APS	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Owner Participant named therein	28.5 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93

185

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.15	Pinnacle West APS	Trust Indenture, Mortgage Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	10.2 to APS’ November 18, 1986 Form 10-K Report, File No. 1-4473	1-20-87
99.16	Pinnacle West APS	Supplemental Indenture No. 1, dated as of August 1, 1987, to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	4.13 to APS’ Form S-3 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473	8-24-87

186

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.17	Pinnacle West APS	Supplemental Indenture No. 2 to Trust Indenture Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee	4.5 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.18	Pinnacle West APS	Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	10.5 to APS’ November 18, 1986 Form 8-K Report, File No. 1-4473	1-20-87
99.19	Pinnacle West APS	Amendment No. 1, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	28.7 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.20c	Pinnacle West APS	Indemnity Agreement dated as of March 17, 1993 by APS	28.3 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93

187

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.21	Pinnacle West APS	Extension Letter, dated as of August 13, 1987, from the signatories of the Participation Agreement to Chemical Bank	28.20 to APS’ Form S-3 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473	8-10-87

188

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.22	Pinnacle West APS	Arizona Corporation Commission Order, Decision No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules	10.2 to APS’ September 1999 Form 10-Q Report, File No. 1-4473	11-15-99
99.23	Pinnacle West APS	ACC Decision No. 65796 dated April 4, 2003 (Financing Order)	99.3 to Pinnacle West’s March 2003 Form 10-Q Report, File No. 1-8962	5-15-03
99.24	Pinnacle West APS	Proposed Settlement of Docket E-01345A-03-0437, APS Request for Rate Adjustment, dated August 18, 2004	99.1 to Pinnacle West’s August 18, 2004 Form 8-K Report, File No. 1-8962	8-18-04

189

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.25	Pinnacle West APS	Opinion and Order, ACC Decision No. 67744 dated April 7, 2005 (see Exhibit 99.24 herein for Attachment A to the Opinion and Order, the 2004 Settlement Agreement)	99.5 to Pinnacle West/APS March 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-10-05
99.26	Pinnacle West	Purchase Agreement by and among Pinnacle West Energy Corporation and GenWest, L.L.C. and Nevada Power Company, dated June 21, 2005	99.5 to Pinnacle West/APS June 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-9-05
99.27	Pinnacle West APS	Amended and Restated Reimbursement Agreement among Arizona Public Service Company, The Banks party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and Barclays Bank PLC, as Syndication Agent, dated as of May 19, 2005	99.6 to PinnacleWest/APS June 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473	8-9-05
99.28	Pinnacle West APS	Application for Emergency Interim Rate Increase and Interim Amendment to Decision No. 67744	99.1 to Pinnacle West/APS January 6, 2006 Form 8-K Report, File Nos. 1-8962 and 1-4473	1-9-06

190

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Effective
99.29	Pinnacle West	Non-GAAP Financial Measure Reconciliation - Operating Income (GAAP measure) to Gross Margin (non-GAAP financial measure)
99.30	APS	Non-GAAP Financial Measure Reconciliation - Operating Income (GAAP measure) to Gross Margin (non-GAAP financial measure)

a	Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.
b	Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
c	An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.
d	Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.

191

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	PINNACLE WEST CAPITAL CORPORATION
		(Registrant)
Date: March 10, 2006
		/s/ William J. Post
		(William J. Post, Chairman of the Board of Directors and Chief Executive Officer)

Power of Attorney

     We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ William J. Post	Principal Executive Officer and Director	March 10, 2006
(William J. Post, Chairman of the Board of Directors and Chief Executive Officer)
/s/ Jack E. Davis	Director	March 10, 2006
(Jack E. Davis, President and Chief Operating Officer)
/s/ Donald E. Brandt	Principal Accounting Officer and	March 10, 2006
(Donald E. Brandt, Executive Vice President and Chief Financial Officer)	Principal Financial Officer

192

Signature	Title	Date
/s/ Edward N. Basha, Jr.	Director	March 10, 2006
(Edward N. Basha, Jr.)
/s/ Michael L. Gallagher	Director	March 10, 2006
(Michael L. Gallagher)
/s/ Pamela Grant	Director	March 10, 2006
(Pamela Grant)
/s/ Roy A. Herberger, Jr.	Director	March 10, 2006
(Roy A. Herberger, Jr.)
/s/ Martha O. Hesse	Director	March 10, 2006
(Martha O. Hesse)
/s/ William S. Jamieson, Jr.	Director	March 10, 2006
(William S. Jamieson, Jr.)
/s/ Humberto S. Lopez	Director	March 10, 2006
(Humberto S. Lopez)
/s/ Kathryn L. Munro	Director	March 10, 2006
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom	Director	March 10, 2006
(Bruce J. Nordstrom)
/s/ William L. Stewart	Director	March 10, 2006
(William L. Stewart)

193

SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	ARIZONA PUBLIC SERVICE COMPANY
	(Registrant)
Date: March 10, 2006	/s/ Jack E. Davis
	(Jack E. Davis, President and Chief Executive Officer)

Power of Attorney

     We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ William J. Post	Director	March 10, 2006
(William J. Post, Chairman of the Board of Directors )
/s/ Jack E. Davis	Principal Executive Officer and Director	March 10, 2006
(Jack E. Davis, President and Chief Executive Officer)
/s/ Donald E. Brandt	Principal Financial Officer	March 10, 2006
(Donald E. Brandt, Executive Vice President, and Chief Financial Officer)
/s/ Chris N. Froggatt	Principal Accounting Officer	March 10, 2006
(Chris N. Froggatt, Vice President and Controller)

194

Signature	Title	Date
/s/ Edward N. Basha, Jr.	Director	March 10, 2006
(Edward N. Basha, Jr.)
/s/ Michael L. Gallagher	Director	March 10, 2006
(Michael L. Gallagher)
/s/ Pamela Grant	Director	March 10, 2006
(Pamela Grant)
/s/ Roy A. Herberger, Jr.	Director	March 10, 2006
(Roy A. Herberger, Jr.)
/s/ Martha O. Hesse	Director	March 10, 2006
(Martha O. Hesse)
/s/ William S. Jamieson, Jr.	Director	March 10, 2006
(William S. Jamieson, Jr.)
/s/ Humberto S. Lopez	Director	March 10, 2006
(Humberto S. Lopez)
/s/ Kathryn L. Munro	Director	March 10, 2006
(Kathryn L. Munro)
/s/ Bruce J. Nordstrom	Director	March 10, 2006
(Bruce J. Nordstrom)
/s/ William L. Stewart	Director	March 10, 2006
(William L. Stewart)

195

Exhibit Index

Exhibit
No.	Registrant(s)	Description
10.48b	Pinnacle West APS	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 18, 2003
10.64b	Pinnacle West APS	Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective January 1, 2003.
10.77bd	Pinnacle West APS	Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries
10.91bd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan
10.92bd	Pinnacle West APS	Summary of 2006 CEO Variable Incentive Plan and Officer Variable Incentive Plan
10.95	Pinnacle West APS	Amended and Restated Five-Year Credit Agreement dated as of December 9, 2005 between APS, as Borrower, Citibank, N.A., as Agent, and the lenders and other parties thereto
10.96	Pinnacle West	$200,000,000 Senior Notes Uncommitted Master Shelf Agreement dated as of February 28, 2006
10.97	Pinnacle West	Amended and Restated Credit Agreement dated as of December 9, 2005 among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Agent, and the other agent parties thereto
10.107	Pinnacle West APS	Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996, Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998.
10.108	Pinnacle West APS	Navajo Project Participation Agreement dated as of September 30, 1969, and Amendment and Supplement No. 1 dated as of January 16, 1970, and Coordinating Committee Agreement No. 1 dated as of September 31, 1971.
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements
21.1	Pinnacle West	Subsidiaries of Pinnacle West
23.1	Pinnacle West	Consent of Deloitte & Touche LLP
23.2	APS	Consent of Deloitte & Touche LLP
31.1	Pinnacle West	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3	APS	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.29	Pinnacle West	Non-GAAP Financial Measure Reconciliation - Operating Income (GAAP measure) to Gross Margin (non-GAAP financial measure)
99.30	APS	Non-GAAP Financial Measure Reconciliation - Operating Income (GAAP measure) to Gross Margin (non-GAAP financial measure)

a	Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.
b	Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
c	An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.
d	Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.