Pinnacle West Capital (PNW) 10-K 2006 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, 2006

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	Yeso	Noþ

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

PINNACLE WEST CAPITAL CORPORATION	Yesþ	Noo
ARIZONA PUBLIC SERVICE COMPANY	Yesþ	Noo

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

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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	$3,946,188,585 as of June 30, 2006
ARIZONA PUBLIC SERVICE COMPANY	$0 as of June 30, 2006

      The number of shares outstanding of each registrant’s common stock as of February 21, 2007

PINNACLE WEST CAPITAL CORPORATION	100,011,597 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 23, 2007 are incorporated by reference into Part III hereof.

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

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

TABLE OF CONTENTS

	Page
GLOSSARY
PART I
Item 1. Business		3
Item 1A. Risk Factors		15
Item 1B. Unresolved Staff Comments		23
Item 2. Properties		24
Item 3. Legal Proceedings		29
Item 4. Submission of Matters to a Vote of Security Holders		29
Supplemental Item
Executive Officers of Pinnacle West		30
PART II
Item 5. Market for Registrants’ Common Equity, Pinnacle West Related Stockholder Matters and Issuer Purchases of Equity Securities		32
Item 6. Selected Financial Data		34
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		36
Item 7A. Quantitative and Qualitative Disclosures about Market Risk		67
Item 8. Financial Statements and Supplementary Data		68
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		150
Item 9A. Controls and Procedures		150
Item 9B. Other Information		151
PART III
Item 10. Directors, Executive Officers and Corporate Governance of Pinnacle West		151
Item 11. Executive Compensation		151
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		151
Item 13. Certain Relationships and Related Transactions, and Director Independence		152
Item 14. Principal Accountant Fees and Services		152
PART IV
Item 15. Exhibits and Financial Statement Schedules		153
SIGNATURES		194
EX-10.78
EX-12.1
EX-12.2
EX-12.3
EX-21.1
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-31.3
EX-31.4
EX-32.1
EX-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

FIP – Federal Implementation Plan

Four Corners – Four Corners Power Plant

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

IRS – United States Internal Revenue Service

kW – kilowatt, one thousand watts

kWh – kilowatt-hour, one thousand watts per hour

Moody’s – Moody’s Investors Service

MW – megawatt, one million watts

MWh – megawatt-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

Note – a Note to Pinnacle West’s Consolidated Financial Statements in Item 8 of this report

NPC – Nevada Power Company

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

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

Palo Verde – Palo Verde Nuclear Generating Station, also known as ANPP

Pinnacle West – Pinnacle West Capital Corporation, the Company

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

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

PPL Sundance – PPL Sundance Energy, LLC

PRP – potentially responsible parties under Superfund

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

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

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

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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 owned any generating plants and was dissolved as of August 31, 2006. Pinnacle West’s other first-tier subsidiaries, El Dorado Investment Company, Pinnacle West Marketing & Trading, SunCor and APS Energy Services, are discussed in greater detail

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below. See “Business of SunCor Development Company” and “Business of Other Subsidiaries,” in this Item 1.

Business Segments

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

• the regulated electricity segment (77% of operating revenues in 2006), which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities, and includes electricity generation, transmission and distribution; and

• the real estate segment (12% of operating revenues in 2006), which consists of SunCor’s real estate development and investment activities.

     See Note 17 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 adequate and timely retail rate treatment by the ACC. APS’ retail rate proceedings pending before the ACC are discussed in greater detail in Note 3 in Item 8.

Employees

     At December 31, 2006, Pinnacle West employed approximately 7,400 people, including the employees of its subsidiaries. Of these employees, approximately 6,600 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 800 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.

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

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• Corporate Governance Guidelines;

• Board Committee Summary;

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

• Code of Ethics for Financial Professionals;

• Ethics Policy and Standards of Business Practices; and

• Director Independence Standards.

     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, including such deferrals in 2005 and 2006 associated with unplanned Palo Verde outages and reduced power operations that are the subject of ACC prudence reviews;

• 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 purchased power costs and the completion of generation and transmission

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	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 value of our nuclear decommissioning trust, pension, and other postretirement benefit plan assets, the amount of required contributions to Pinnacle West’s pension plan and contributions to APS’ nuclear decommissioning trust funds, as well as the reported costs of providing pension and other postretirement benefits;
•	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.

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

     In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. As a result, as of January 1, 2001, all of APS’ retail customers were eligible to choose alternate energy suppliers. However, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. In 2000, an Arizona Superior Court found that the rules were 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

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Arizona and only with certain entities not regulated by the ACC. APS cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

Wholesale

     General

     The FERC regulates rates for wholesale power sales and transmission services. During 2006, approximately 4.4% 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.

BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY

General

     APS was incorporated in 1920 under the laws of the state of Arizona and currently has approximately 1,052,000 customers. APS does not distribute any products. During 2006, no single purchaser or user of energy accounted for more than 6.1% of electric revenues. See “Overview – General” and “Regulation and Competition” above for additional background information about APS’ business.

     At December 31, 2006, APS employed approximately 6,600 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).

Purchased Power and Generating Fuel

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

     2006 Energy Mix

     APS’ sources of energy during 2006 were: purchased power – 35.0%; coal – 31.2%; gas – 17.3%; and nuclear – 16.5%. In accordance with GAAP, a substantial portion of APS’ purchased power contracts was netted against wholesale sales contracts on the Statements of Income. See Note 18 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 long-term leases 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

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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 on APS’ part 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.

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

     Natural Gas Supply

     See Note 11 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 are continually identifying their future resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates and conversion services through 2007 and for approximately 70% of uranium concentrates and conversion services in 2008. The participants have

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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 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 2006, APS received 550,567 MWh of energy under the contract and paid about $66.1 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.

     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 of capacity and a related amount of energy available to it under the agreement for its respective seasons. In 2006, APS received 571,181 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 2006, PacifiCorp received offers of 1,105,125 MWh and purchased 309,750 MWh.

     APS continually assesses its need for additional capacity resources to assure system reliability. Consistent with the terms of the 2004 Settlement Agreement, and, as a result of seeking proposals from the competitive wholesale market, APS entered into a number of agreements under which APS is entitled to purchase power, including several agreements (aggregating 650 MW) running through 2015 covering APS’ peak periods. APS has also entered into an agreement under which APS is entitled to the output of a 510 MW power plant from June 1, 2007 through May 31, 2017. APS has also agreed to purchase approximately 100 MW of renewable power (wind, geothermal and landfill gas) under contracts that expire between 2025 and 2029. APS remains committed to seeking proposals from the competitive wholesale market for filling its future resource needs, including for renewable capacity.

Construction Program

     During the years 2004 through 2006, APS incurred approximately $2 billion in capital expenditures. APS’ capital expenditures for the years 2007 through 2009 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 $662 million in 2006. APS’ capital expenditures, including expenditures for environmental control facilities, for the years 2007 through 2009, net of contributions in aid of construction, have been estimated as follows (dollars in millions):

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	Estimate
	2007		2008		2009
Major facilities:
Distribution	$	361	$	414	$	459
Transmission		173		195		288
Generation		333		304		313
Other		26		37		40
Total	$	893	$	950	$	1,100

     The above amounts exclude capitalized interest costs and include capitalized property taxes. Nuclear fuel of approximately $50 million in 2007 and $75 million per year for 2008 and 2009 is also included. APS conducts a continuing review of its construction program.

     See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Needs and Resources” 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 (SIPs) by 2008 to demonstrate “reasonable progress” towards achieving natural visibility conditions in certain “Class I Areas,” including several on the Colorado Plateau. The SIP is required to consider and potentially apply “best available retrofit technology” (BART) for certain older 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 SIPs 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 under an application of BART.

     On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional haze rules by providing guidelines, known as the BART guidelines, for states to use in determining which facilities must install controls and the type of controls the facilities must use. On October 13, 2006, the EPA issued a final rule reconciling the Annex Rule with the CEED decision.

     The Arizona Department of Environmental Quality (ADEQ) is currently undertaking a rulemaking process to amend its SIP to reconcile with the Annex Rule litigation and SIPs to implement the Clean Air Visibility Rule requirements. As part of the rulemaking process, the ADEQ will require certain sources in the state to conduct BART analyses, potentially including Cholla and

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other APS plants. The ADEQ’s Regional Haze SIPs are due to EPA Region 9 in December 2007. In addition, we anticipate that EPA Region 9 may require Four Corners to conduct a BART analysis. The Company cannot currently predict the outcome of these proceedings.

     MercuryOn March 15, 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to control mercury emissions from coal-fired power plants. This rule establishes performance standards limiting mercury emissions from coal-fired power plants and establishes a two phased market-based emissions trading program. Under the trading program, the EPA has assigned each state a mercury emissions “budget” and each state must submit to the EPA a plan detailing how it will meet its “budget.” In the first phase of the program, beginning in 2010, mercury emissions from all coal-fired power plants in the country will be reduced from a total of 48 tons per year to 38 tons. In 2018, those 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.

     In November 2006, the ADEQ submitted a SIP to the EPA to implement the CAMR. ADEQ’s SIP generally incorporates the EPA’s model cap-and-trade program, but it includes additional requirements, including the requirement to meet a 90% mercury removal control level or 0.0087 lbs/GWh, whichever is greater, the requirement to obtain mercury allowances at a 2:1 ratio for any emissions that fall below the specified control level, and the requirement, beginning in 2013, to consider clean coal technologies as part of permitting any new generation. APS is evaluating the potential impacts of the proposed rule and cannot currently estimate the expenditures that may be required.

     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 the Four Corners Power Plant. On July 26, 2006, the Sierra Club sued the EPA in an attempt to force the EPA to issue a final FIP to limit emissions at the Four Corners Power Plant. On September 12, 2006, the EPA proposed a revised FIP to establish air quality standards at Four Corners and the Navajo Generating Station. On September 18, 2006, APS filed a motion to intervene in the Sierra Club’s lawsuit against the EPA, in order to assure that its interests are protected. On November 22, 2006, the court granted APS’ motion to intervene in the lawsuit. In December 2006, the court issued a consent decree signed by the Sierra Club and the EPA; the consent decree requires EPA to take “final action” on the proposed FIP by April 30, 2007. APS cannot currently predict the effect of the proposed FIP on its financial position, results of operations, cash flows or liquidity, or whether the proposed FIP will be adopted in its current form.

     In addition, on August 21, 2006, the EPA proposed a FIP to implement “minor New Source Review” on Indian reservations. The FIP, if finalized, would apply to Four Corners and the Navajo Generating Station, and would require preconstruction review and permitting of plant projects that meet specified criteria. APS does not currently expect this 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

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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.

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

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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. The MCAQD subsequently rescinded most of the NOVs and imposed a penalty of approximately $20,000 for the remaining NOVs, which was paid in October 2006.

Water Supply

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

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

     A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County, Arizona, Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’ rights and the rights of the Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Five of APS’ other power plants are also located within the geographic area subject to the summons. APS’ claims dispute the court’s jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Court 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, which was originally filed on September 5, 1985. 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

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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 2007 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 Act includes a wide range of provisions addressing many aspects of the energy industry. Specifically, with respect to the electric utility industry, the Act includes provisions which, among other things, repeals the Public Utility Holding Company Act of 1935 through enactment of the Public Utility Holding Company Act of 2005, effective as of February 8, 2006, creates incentives for the construction of transmission infrastructure, eliminates the statutory restrictions on ownership of qualifying facilities by electric utilities, establishes civil penalty authority over electric utilities and expands the authority of the FERC to include overseeing the reliability of the bulk power system. While we continue to monitor the impact of this new federal legislation, we cannot predict the impact of the Act on our operations at this time.

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, 2006.

     At December 31, 2006, SunCor had total assets of about $607 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.

     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 $400 million in 2006, $338 million in 2005 and $350 million in 2004. SunCor’s net income was approximately $61 million in 2006, $56 million in 2005 and $45 million in 2004. 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 in Item 8.

     See Note 6 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 OTHER SUBSIDIARIES

     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, 2006. 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 $3 million in 2006, a net loss of $6 million in 2005 and net income of $3 million in 2004. At December 31, 2006, APS Energy Services had total assets of $81 million.

     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 business of generating, distributing and marketing electricity. El Dorado’s offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-3517).

     El Dorado had a net loss of $4 million in 2006, net income of $4 million in 2005 and net income of $40 million in 2004. Income taxes related to El Dorado are recorded by Pinnacle West. At December 31, 2006, El Dorado had total assets of $34 million.

     Pinnacle West Marketing & Trading was formed on August 29, 2006. See “Capital Needs and Resources – Pinnacle West (Parent Company)” for information regarding Pinnacle West Marketing & Trading, the Company’s marketing and trading subsidiary.

ITEM 1A. RISK FACTORS

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

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     APS is subject to comprehensive government regulation by several federal, state and local regulatory agencies that significantly affect its business and 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. While approved electric rates are intended to permit APS to recover its costs of service and earn a reasonable rate of return, the profitability of APS is affected by the rates it may charge. Consequently, our financial condition and results of operations are dependent upon the satisfactory resolution of APS’ retail rate proceedings pending before the ACC.

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

     On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) following an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 generator did not activate during routine inspections on July 25 and September 22, 2006. This finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, will result in an enhanced NRC inspection regimen.

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

     APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, 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 APS to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. If there is a delay in obtaining any required environmental regulatory approval, or if APS fails to obtain, maintain or comply with any such approval, operations at affected facilities could be suspended or subject to additional expenses. In addition, failure to comply with applicable environmental laws and regulations could result in civil liability or criminal penalties. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.

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

     We cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs incurred by APS are not fully recoverable from APS’

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customers, could have a material adverse effect on our financial position, results of operations or cash flows.

     Concern over climate change could result in significant legislative and regulatory efforts to limit greenhouse gas emissions.

     Concern over climate change deemed by many to be induced by rising levels of greenhouse gases in the atmosphere has led to significant legislative and regulatory efforts to limit greenhouse gas emissions. In 1998, the United States became a signatory to the Kyoto Protocol of the United Nations Framework Convention on Climate Change.The Kyoto Protocol, which became effective in February 2005, calls for developed nations to reduce their emissions of greenhouse gases to specified levels by 2012. CO2, which is a major byproduct of the combustion of fossil fuel, is a greenhouse gas that would be regulated under the Kyoto Protocol. The United States Senate indicated that it would not enact the Kyoto Protocol, and in 2002 President Bush confirmed that the United States would not enter into the Kyoto Protocol. Instead, the President indicated that the United States would support voluntary measures for reducing greenhouse gases and technologies that would use or dispose of CO2 effectively and economically. As the Kyoto Protocol becomes effective in other countries, there is increasing pressure for sources in the United States to be subject to mandatory restrictions on CO2 emissions. In the last year, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions, but such bills have not received sufficient Congressional approval to date to become law. If the United States ultimately ratifies the Kyoto Protocol and/or if the United States Congress or individual states or groups of states in which we operate ultimately pass legislation regulating the emissions of greenhouse gases, any resulting limitations on generation facility CO2 emissions could have a material adverse impact on all fossil fuel fired generation facilities (particularly coal fired facilities), including ours.

     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; the costs of securing the facilities against possible terrorist attacks; and unscheduled outages due to equipment and other problems. APS maintains nuclear decommissioning trust funds and external insurance coverage to minimize its financial exposure to some of these risks; however, it is possible that damages could exceed the amount of insurance coverage.

     The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose 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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     The operation of Palo Verde requires licenses that need to be periodically renewed and/or extended. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.

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

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

     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 APS due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

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

     Changes in technology may adversely affect our business.

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

     Our results of operations can be adversely affected by 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

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result, our overall operating results fluctuate substantially on a seasonal basis. In addition, APS has historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish our results of operations and harm our financial condition.

     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. The common equity ratio, as defined in the ACC order, is common equity divided by common equity plus long-term debt, including current maturities of long-term debt.

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

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

     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;

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

• changes in technology; or

• the overall health of the utility or real estate 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.

     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 limit our access to capital and 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

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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 affect interest paid on variable-rate debt and interest earned on variable-rate securities in our pension plan, other postretirement benefit plan and nuclear decommissioning trust funds. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan and other postretirement benefit liabilities are also impacted by the discount rate, which is the interest rate used to discount future pension and other postretirement benefit obligations. Declining interest rates impact the discount rate, and may result in increases in pension and other postretirement benefit costs, cash contributions, regulatory assets, and charges to other comprehensive income. The pension plan, other postretirement benefit and nuclear decommissioning trust funds also have risks associated with changing market values of fixed income and equity investments. A significant portion of the pension costs and other postretirement benefit costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices.

     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 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, a portion of which is subject to a prudence review by the ACC as a result of unplanned Palo Verde outages in 2005 and 2006.

• 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.

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• 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 is recognized in common stock 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.

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

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

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

     SunCor’s business and financial performance could be adversely affected by a variety of factors affecting the real estate market, including downward changes in general economic, real estate construction or other business conditions; the potential overvaluation of land and new homes, which could result in an economic down cycle for the homebuilding industry; future increases in interest rates, reductions in mortgage availability or increases in the effective costs of owning a home, which could prevent potential customers from buying homes in SunCor’s developments; competition for homebuyers or commercial customers or partners, which could reduce SunCor’s profitability; supply shortages and other risks related to the demand for skilled labor and building materials, which could increase costs and delay deliveries; government regulations, which could increase the cost and limit the availability of SunCor’s development, homebuilding and commercial projects; and inflation, which could result in increased costs that SunCor may not be able to recoup if demand declines.

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 2006 fiscal year and that remain unresolved.

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ITEM 2. PROPERTIES

Regulated Electricity Segment 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		225,000
Units 1, 2 and 3 at Cholla		641,000
14% owned Units 1, 2 and 3 at the Navajo Generating Station		315,000
Subtotal		1,741,000
Gas or Oil:
Two steam units at Ocotillo and two steam units at Saguaro		430,000
Twenty-two combustion turbine units		992,000
Seven combined cycle units		1,862,000
Subtotal		3,284,000
Nuclear:
29.1% owned or leased Units 1, 2 and 3 at Palo Verde		1,126,752
Solar		5,816
Total		6,157,568

Reserve Margin

     APS’ 2006 peak one-hour demand on its electric system was recorded on July 21, 2006 at 7,652,000 kW, compared with the 2005 peak of 6,999,600 kW recorded on July 18, 2005. Taking into account additional capacity then available to APS under long-term purchased power contracts as well as APS’ generating capacity, APS’ capability of meeting system demand on July 21, 2006, amounted to 6,783,000 kW, for an installed reserve margin of negative 12.7%. 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 2006 peak amounted to 5,706,000 kW, for a margin of a negative 35.6%. Firm purchases totaling 3,522,000 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 7.0%.

     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, and the leases contain options to extend. 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.

     See “NRC Inspection” in Note 11 in Item 8 for information regarding an NRC finding relating to an NRC inspection that will result in an enhanced NRC inspection regimen.

     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 in Item 8 for additional information about APS’ nuclear decommissioning costs.

     Palo Verde Liability and Insurance Matters

     See “Palo Verde Nuclear Generating Station” in Note 11 in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.

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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, 2006:

	Percent Owned
Generating facilities:
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 (a)		63.2	%(b)
Transmission facilities:
ANPP 500KV System		35.8	%(b)
Navajo Southern System		31.4	%(b)
Palo Verde – Yuma 500KV System		23.9	%(b)
Four Corners Switchyards		27.5	%(b)
Phoenix – Mead System		17.1	%(b)
Palo Verde – Estrella 500KV System		55.5	%(b)
Harquahala		80.0	%(b)

(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.

     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 in Item 8 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.

Transmission and Distribution Facilities

     APS’ transmission facilities consist of approximately 5,712 pole miles of overhead lines and approximately 43 miles of underground lines, 5,486 miles of which are located within the State of Arizona. APS’ distribution facilities consist of approximately 12,355 pole miles of overhead lines and approximately 15,222 miles of underground lines, all of which are located within the State of Arizona.

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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 “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.

Real Estate Segment Properties

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

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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 3 in Item 8 with respect to retail rate proceedings pending before the ACC.

     See Note 11 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 February 28, 2007		Position(s) at February 28, 2007
William J. Post		56	Chairman of the Board and Chief Executive Officer (1)
Jack E. Davis		60	President and Chief Operating Officer, and Chief Executive Officer, APS (1)
Donald E. Brandt		52	Executive Vice President and Chief Financial Officer, and President and Chief Financial Officer of APS
Randall K. Edington		53	Senior Vice President and Chief Nuclear Officer, APS
Armando B. Flores		63	Executive Vice President, Corporate Business Services, APS
Chris N. Froggatt		49	Vice President and Controller, APS
Barbara M. Gomez		52	Vice President and Treasurer
Nancy C. Loftin		53	Vice President, General Counsel and Secretary
Donald G. Robinson		53	Vice President, Planning, APS
Steven M. Wheeler		58	Executive Vice President, Customer Service and Regulation, APS

(1) Member of the Board of Directors.

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

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

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February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr. Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until October 2002. Mr. Post is also a director of APS 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 was also President of APS (October 1998 – December 2006) and is Chief Executive Officer of APS (since October 2002). He is also a director of APS.

     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 President of APS in December 2006 and Chief Financial Officer of APS in January 2003. He was also Executive Vice President of APS (September 2003 – December 2006) and Senior Vice President of APS (January 2003 – September 2003).

     Mr. Edington was elected Senior Vice President and Chief Nuclear Officer of APS in January 2007. Prior to that time he was with Entergy Corporation, serving as Site Vice President and Chief Nuclear Officer of Cooper Generating Station (2003 – January 2007) and Vice President of Operator Training, Indian Point Energy Center (2001 – 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 of Pinnacle West (August 1999 – February 2004) and Manager, Treasury Operations of APS (1997 – 1999). She was also elected Treasurer of APS in October 1999 and Vice President of APS in February 2004.

     Ms. Loftin was elected Vice President and General Counsel of Pinnacle West 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 February 21, 2007, Pinnacle West’s common stock was held of record by approximately 31,471 shareholders.

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

							Dividends
2006	High		Low		Close		Per Share
1st Quarter	$	44.14	$	38.76	$	39.10	$	0.500
2nd Quarter		41.06		38.31		39.91		0.500
3rd Quarter		45.99		39.90		45.05		0.500
4th Quarter		51.00		45.12		50.69		0.525

							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

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

     The chart below sets forth the dividends paid on APS’ common stock for each of the four quarters for 2006 and 2005.

Common Stock Dividends
(Dollars in Thousands)

Quarter	2006		2005
1st Quarter	$	42,500	$	42,500
2nd Quarter		42,500		—
3rd Quarter		42,500		—
4th Quarter		42,500		127,500

     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, 2006, APS did not have any outstanding preferred stock.

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     Issuer Purchases of Equity Securities

     The following table contains information about our purchases of our common stock during the fourth quarter of 2006.

					(c) Total Number
	(a) Total				of Shares		(d) Maximum Number
	Number of		(b)		Purchased		of Shares
	Shares		Average		as Part of Publicly		that May Yet Be
	Purchased		Price Paid		Announced Plans		Purchased Under the
Period	(1)		per Share		or Programs		Plans or Programs
October 1 – October 31, 2006		—		—		—		—
November 1 – November 30, 2006		907	$	47.79		—		—
December 1 – December 31, 2006		—		—		—		—
Total		907	$	47.79

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

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

	2006		2005			2004			2003		2002
			(dollars in thousands, except per share amounts)
OPERATING RESULTS
Operating revenues:
Regulated electricity segment	$	2,635,036	$	2,237,145		$	2,035,247		$	1,978,075	$	1,890,391
Real estate segment		399,798		338,031			350,315			361,604		201,081
Marketing and trading		330,742		351,558			400,628			391,196		286,879
Other revenues		36,172		61,221			42,816			27,929		26,899
Total operating revenues	$	3,401,748	$	2,987,955		$	2,829,006		$	2,758,804	$	2,405,250
Income from continuing operations (a)		317,143		223,163			246,590			225,384		236,563
Discontinued operations – net of income taxes (b)		10,112		(46,896	)		(3,395	)		15,195		(21,410	)
Cumulative effect of change in accounting – net of income taxes (c)		—		—			—			—		(65,745	)
Net income	$	327,255	$	176,267		$	243,195		$	240,579	$	149,408
COMMON STOCK DATA
Book value per share – year-end	$	34.48	$	34.58		$	32.14		$	30.97	$	29.40
Earnings (loss) per weighted average common share outstanding:
Continuing operations – basic	$	3.19	$	2.31		$	2.70		$	2.47	$	2.79
Discontinued operations (b)		0.10		(0.48	)		(0.04	)		0.17		(0.26	)
Cumulative effect of change in accounting (c)		—		—			—			—		(0.77	)
Net income – basic	$	3.29	$	1.83		$	2.66		$	2.64	$	1.76
Continuing operations – diluted	$	3.17	$	2.31		$	2.69		$	2.47	$	2.78
Net income – diluted	$	3.27	$	1.82		$	2.66		$	2.63	$	1.76
Dividends declared per share	$	2.025	$	1.925		$	1.825		$	1.725	$	1.625
Indicated annual dividend rate per share – year-end	$	2.10	$	2.00		$	1.90		$	1.80	$	1.70
Weighted-average common shares outstanding – basic		99,417,008		96,483,781			91,396,904			91,264,696		84,902,946
Weighted-average common shares outstanding – diluted		100,010,108		96,589,949			91,532,473			91,405,134		84,963,921
BALANCE SHEET DATA
Total assets	$	11,455,943	$	11,322,645		$	9,896,747		$	9,519,042	$	9,139,157
Liabilities and equity:
Long-term debt less current maturities	$	3,232,633	$	2,608,455		$	2,584,985		$	2,616,585	$	2,743,741
Other liabilities		4,777,194		5,289,226			4,361,566			4,072,678		3,709,263
Total liabilities		8,009,827		7,897,681			6,946,551			6,689,263		6,453,004
Common stock equity		3,446,116		3,424,964			2,950,196			2,829,779		2,686,153
Total liabilities and equity	$	11,455,943	$	11,322,645		$	9,896,747		$	9,519,042	$	9,139,157

(a)	Includes regulatory disallowance of $84 million after tax in 2005. See Note 3 in Item 8.
(b)	Amounts related to Silverhawk, SunCor and NAC discontinued operations. See Note 22 in Item 8.
(c)	Represents change in accounting standards related to energy trading activities in 2002.

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SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY

	2006		2005			2004		2003		2002
			(dollars in thousands)
OPERATING RESULTS
Electric operating revenues:
Regulated electricity	$	2,640,989	$	2,244,951		$	2,051,602	$	1,999,390	$	1,902,112
Marketing and trading		17,524		25,842			145,519		105,541		34,054
Total electric operating revenues		2,658,513		2,270,793			2,197,121		2,104,931		1,936,166
Fuel and purchased power costs:
Regulated electricity		965,712		656,654			612,300		606,251		438,141
Marketing and trading		4,055		32,328			150,954		97,180		32,662
Operating expenses		1,290,804		1,200,198			1,104,886		1,103,342		1,136,363
Operating income		397,942		381,613			328,981		298,158		329,000
Other income (deductions)		27,584		(69,171	)		15,328		26,347		(8,041	)
Interest deductions – net		155,796		141,963			144,682		143,568		121,616
Net income	$	269,730	$	170,479		$	199,627	$	180,937	$	199,343
BALANCE SHEET DATA
Total assets	$	10,513,692	$	9,707,441		$	8,098,552	$	7,722,533	$	7,122,238
Capital structure:
Common stock equity	$	3,207,473	$	2,985,225		$	2,232,402	$	2,203,630	$	2,159,312
Long-term debt less current maturities		2,877,502		2,479,703			2,267,094		2,135,606		2,217,340
Total capitalization		6,084,975		5,464,928			4,499,496		4,339,236		4,376,652
Current maturities of long-term debt		968		85,620			451,247		487,067		3,503
Total	$	6,085,943	$	5,550,548		$	4,950,743	$	4,826,303	$	4,380,155

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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, these proceedings consist of:

• a general retail rate case pursuant to which APS is requesting a 20.4%, or $434.6 million, increase in its annual retail electricity revenues;

• an application for a temporary rate increase of approximately 1.9%, through a PSA surcharge, to recover $45 million in retail fuel and purchased power costs relating to Palo Verde’s 2005 unplanned outages that were deferred by APS in 2005 under the PSA and are subject to the ACC’s completion of an inquiry regarding the outages (this matter is now being addressed in the general retail rate case); and

• the ACC’s prudency review of amounts collected through the May 2, 2006 interim PSA adjustor (see “Interim Rate Increase” in Note 3) related to unplanned 2006 Palo Verde outages. The related PSA deferrals were approximately $79 million in 2006.

     SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings. See discussion below in “Pinnacle West Consolidated – Factors Affecting our Financial Outlook – Subsidiaries.” Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial and 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 was a subsidiary that owned and operated unregulated generating plants. Pursuant to the ACC’s April 7, 2005 order in APS’ retail rate settlement, on July 29, 2005, Pinnacle West Energy transferred the PWEC Dedicated Assets to APS. Pinnacle West Energy sold its 75% interest in Silverhawk to NPC on January 10, 2006. See Note 22 for a discussion of discontinued operations. As a result, Pinnacle West Energy no longer owned any generating plants and was dissolved as of August 31, 2006.

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     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

     Pinnacle West’s two principal business segments are:

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

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

     Our reportable business segments reflect a change from the previously reported information. As of December 31, 2006, our marketing and trading activities are no longer considered a segment requiring separate reporting or disclosure. The marketing and trading activities consist of our competitive energy business, including wholesale marketing and trading and retail commodity-related energy services. These activities have decreased as a result of fewer market opportunities and the Company’s intention to deemphasize that part of our business. These activities are now reported as part of the “Other” category in the table below. The corresponding information for earlier periods has been reclassified.

     The following table summarizes income from continuing operations by segment for December 31, 2006, 2005 and 2004 and reconciles to net income in total (dollars in millions):

	2006			2005			2004
Regulated electricity (a)	$	259		$	167		$	152
Real estate		50			35			40
Other (b)		8			21			55
Income from continuing operations		317			223			247
Discontinued operations – net of tax:
Real estate (c)		10			17			4
Sale of Silverhawk (d)		1			(67	)		(12	)
Sale of NAC		(1	)		3			4
Net income	$	327		$	176		$	243

(a)	Includes an $84 million after-tax regulatory disallowance of plant costs in 2005 in accordance with APS’ 2003 general retail rate case settlement.
(b)	Primarily marketing and trading activity.
(c)	Primarily relates to sales of commercial properties.
(d)	See Note 22.

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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 contributions, gross margin refers to operating revenues less fuel and purchased power costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.29 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States (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.

Deferred Fuel and Purchased Power Costs

     Our subsidiary, APS, settled its 2003 general retail rate case effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with 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. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications. See “Power Supply Adjustor” in Note 3.

     Since the inception of the PSA, APS has incurred substantially higher fuel and purchased power costs than those authorized for recovery through APS’ current base rates primarily due to the use of higher cost resources and has deferred those cost differences in accordance with the PSA. The balance of APS’ PSA deferrals at December 31, 2006 was approximately $160 million. The recovery of PSA deferrals through ACC approved adjustors and surcharges recorded as revenue is offset dollar-for-dollar by the amortization of those deferred expenses recorded as fuel and purchased power.

     APS operated Palo Verde Unit 1 at reduced power levels from December 25, 2005 until March 18, 2006 due to vibration levels in one of the Unit’s shutdown cooling lines. During an outage at Unit 1 from March 18, 2006 to July 7, 2006, APS performed the necessary work and modifications to remedy the situation. APS estimates that incremental replacement power costs resulting from these and other unplanned Palo Verde outages and reduced power levels were approximately $88 million during 2006. The related impact on the PSA deferrals was an increase of approximately $79 million. These Palo Verde replacement power costs were partially offset by $42 million of lower than expected replacement power costs related to APS’ other generating units during 2006, which decreased PSA deferrals by $38 million.

     The PSA deferral balance at December 31, 2006 includes (a) $45 million related to replacement power costs associated with unplanned 2005 Palo Verde outages and (b) $79 million related to replacement power costs associated with unplanned 2006 outages or reduced power operations at Palo Verde. The PSA deferrals associated with these unplanned Palo Verde outages

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and reduced power operations are the subject of ACC prudence reviews. The ACC staff has recommended disallowance of $17 million of the 2005 costs. The recommendation will be considered as part of APS’ general rate case currently before the ACC. See “PSA Deferrals Related to Unplanned Palo Verde Outages” in Note 3. The ACC staff recommendation does not change management’s belief that the expenses in question were prudently incurred and, therefore, are recoverable. See Note 3.

2006 Compared with 2005

     Our consolidated net income for 2006 was $327 million compared with $176 million for the comparable prior-year period. The prior year included a net loss from discontinued operations of $47 million, which was related to the sale and operations of Silverhawk, partially offset by income from sales of real estate commercial properties at SunCor. Income from continuing operations increased $94 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

• Regulated Electricity Segment – Income from continuing operations increased approximately $92 million primarily due to an $84 million after-tax regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher retail sales volumes due to customer growth; income tax credits related to prior years resolved in 2006; and increased other income due to higher interest income on higher investment balances. These positive factors were partially offset by higher operations and maintenance expense related to generation and customer service; and higher depreciation and amortization primarily due to increased plant asset balances, partially offset by lower depreciation rates. In addition, higher fuel and purchased power costs of $74 million after-tax were partially offset by the deferral of $45 million after-tax of costs in accordance with the PSA. See discussion – “Deferred Fuel and Purchased Power Costs” above.

• Real Estate Segment – Income from continuing operations increased approximately $15 million primarily due to increased margins on residential sales and the sale of certain joint venture assets, partially offset by higher general and administrative expenses. Income from discontinued operations decreased $7 million due to lower commercial property sales.

• Other – Income from continuing operations decreased approximately $13 million primarily due to lower mark-to-market gains, partially offset by higher unit margins on wholesale sales and competitive retail sales in California.

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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:
Higher fuel and purchased power costs (see “Deferred Fuel and Purchased Power Costs” above)	$	(121	)	$	(74	)
Increased deferred fuel and purchased power costs (deferrals began April 1, 2005)		73			45
Higher retail sales volumes due to customer growth, excluding weather effects		87			53
Miscellaneous items, net		(7	)		(4	)
Net increase in regulated electricity segment gross margin		32			20
Lower marketing and trading gross margin primarily related to lower mark-to-market gains, partially offset by higher unit margins on wholesale sales and competitive retail sales in California		(18	)		(11	)
Higher real estate segment contribution primarily related to increased margins on residential sales and the sale of certain joint venture assets		25			15
Regulatory disallowance of plant costs in 2005, in accordance with APS’ 2003 general retail rate case settlement		139			84
Operations and maintenance increases primarily due to:
Generation costs, including increased maintenance and overhauls		(41	)		(25	)
Customer service costs, including regulatory demand-side management programs and planned maintenance		(16	)		(10	)
Miscellaneous items, net		2			1
Higher depreciation and amortization primarily due to increased plant asset balances partially offset by lower depreciation rates		(11	)		(7	)
Higher other income, net of expense, primarily due to miscellaneous asset sales and increased interest income on higher investment balances		12			7
Income tax credits related to prior years resolved in 2006		—			14
Miscellaneous items, net		—			6
Net increase in income from continuing operations	$	124			94
Discontinued operations:
Silverhawk loss in 2005					68
Lower commercial property real estate sales					(7	)
Sale of NAC International Inc.					(4	)
Net increase in net income				$	151

Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $398 million higher for 2006 compared with the prior-year period primarily as a result of:

• a $265 million increase in revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see “Deferred Fuel and Purchased Power Costs” above);

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• a $124 million increase in retail revenues related to customer growth, excluding weather effects;

• a $6 million increase in Off-System Sales primarily resulting from $12 million of sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with APS’ 2003 general retail rate case settlement, partially offset by $6 million of lower Off-System Sales in 2006; and

• a $3 million increase due to miscellaneous factors.

Real Estate Segment Revenues

     Real estate segment revenues were $62 million higher for 2006 compared with the prior-year period primarily as a result of:

• a $55 million increase in residential sales due to higher prices and volumes; and

• a $7 million increase in commercial real estate sales.

Other Revenues

     Other revenues were $25 million lower for 2006 compared with the prior-year period primarily as a result of decreased sales-related products and services by APS Energy Services.

     Marketing and trading revenues were $21 million lower for 2006 compared with the prior-year period primarily as a result of:

• a $20 million decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices;

• a $12 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 the regulated electricity segment in accordance with APS’ 2003 general retail rate case settlement;

• a $23 million increase from higher prices on competitive retail sales in California; and

• a $12 million decrease due to miscellaneous factors.

2005 Compared with 2004

     Our consolidated net income for 2005 was $176 million compared with $243 million for the prior year. The 2005 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, 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:

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• 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 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.

• Other – Income from continuing operations decreased approximately $34 million primarily due to an after-tax gain related to the sale of a limited partnership interest in the Phoenix Suns recorded in 2004 and due to lower unit margins on competitive retail sales in California.

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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 “Deferred Fuel and Purchased Power Costs” 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
Lower real estate segment contribution primarily related to decreased parcel sales, partially offset by increased margins on home sales		(8	)		(5	)
Lower marketing and trading gross margin primarily due to lower unit margins on competitive retail sales in California		(21	)		(13	)
Regulatory disallowance, in accordance with the APS retail rate case settlement		(139	)		(84	)
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					(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 as marketing and trading revenues 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.

     Real Estate Segment Revenues

     Real estate segment 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 $31 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 as marketing and trading revenues that were classified beginning in April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate case settlement;

• an $18 million increase due to increased sales of energy-related products and services by APS Energy Services; and

• a $9 million decrease due to miscellaneous factors.

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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 2006 and estimated capital expenditures for the next three years:

CAPITAL EXPENDITURES
(dollars in millions)

	Actual		Estimated
	2006		2007		2008		2009
APS
Distribution	$	357	$	361	$	414	$	459
Transmission		113		173		195		288
Generation		176		333		304		313
Other (a)		16		26		37		40
Subtotal		662		893		950		1,100
SunCor (b)		201		131		101		100
Other		7		13		19		11
Total	$	870	$	1,037	$	1,070	$	1,211

(a)	Primarily information systems and facilities projects.
(b)	Consists primarily of capital expenditures for residential, land development and retail and office building construction reflected in “Real estate investments” and “Capital expenditures” on the Consolidated Statements of Cash Flows.

     Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include 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 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. Environmental expenditures are estimated at approximately $80 million to $100 million per year for 2007, 2008 and 2009. Generation also includes nuclear fuel expenditures of approximately $50 million for 2007, and approximately $75 million per year for 2008 and 2009.

     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 $70 million (APS’ share). Approximately $30 million of the Unit 3 steam generator costs have been incurred through December 31, 2006, with the remaining $40

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million included in the capital expenditures table above. Capital expenditures will be funded with internally generated cash and/or external financings.

Contractual Obligations

     The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2006 (dollars in millions):

			2008-		2010-
	2007		2009		2011		Thereafter		Total
Long-term debt payments, including interest: (a)
APS	$	158	$	316	$	929	$	3,600	$	5,003
Pinnacle West		10		20		188		—		218
SunCor		14		185		6		—		205
Total long-term debt payments, including interest		182		521		1,123		3,600		5,426
Short-term debt payments, including interest (b)		36		—		—		—		36
Capital lease payments		1		2		2		1		6
Operating lease payments		79		148		133		253		613
Minimum pension funding requirement (c)		24		—		—		—		24
Purchased power and fuel commitments (d)		366		500		412		1,310		2,588
Purchase obligations (e)		44		11		1		80		136
Nuclear decommissioning funding requirements		21		43		48		234		346
Total contractual commitments	$	753	$	1,225	$	1,719	$	5,478	$	9,175

(a)	The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using the rates at December 31, 2006 (see Note 6).
(b)	The short-term debt is primarily related to commercial paper at Pinnacle West (see Note 5).
(c)	Future pension contributions are not determinable for time periods after 2007.
(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.

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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, 2006, APS would have been required to assume approximately $214 million of debt and pay the equity participants approximately $177 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 February 28, 2007 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase the cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 18).

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

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

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     Debt Provisions

     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2006, the ratio was approximately 48% for Pinnacle West and 46% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.7 times under APS’ bank financing agreements as of December 31, 2006. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

     Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, in the event of a rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

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

     See Note 6 for further discussions.

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 18, 2006, our Board of Directors increased the common stock dividend to an indicated annual rate of $2.10 per share from $2.00 per share, effective with the December 1, 2006 dividend payment. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

     Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2004 through 2006, total dividends from APS were $510 million and total distributions from SunCor were $145 million. For 2006, cash contributions from APS were $170 million and distributions from SunCor were $10 million. An existing ACC order requires APS to maintain a common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the payment would reduce its common equity below that threshold. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At December 31, 2006, APS’ common equity ratio, as defined, was approximately 53%.

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     At December 31, 2006, Pinnacle West’s outstanding long-term debt, including current maturities, was $175 million. Pinnacle West has a $300 million revolving credit facility that terminates in December 2010. 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, 2006, we had $28 million of commercial paper outstanding.

     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. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of common stocks, bonds, fixed-income securities and domestic equity securities and short-term investments. Future year contribution amounts are dependent on fund performance and plan asset valuation assumptions. We contributed approximately $47 million in 2006. The contribution to our pension plan in 2007 is estimated to be approximately $24 million. The expected contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $25 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.

     In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk. See “Equity Infusions” in Note 3 for more information.

     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 of its 5.91% Senior Notes, Series A, due February 28, 2011 (the “Series A Notes”).

     On April 3, 2006, Pinnacle West repaid $300 million of its 6.40% Senior Notes due April 2006. Pinnacle West used the proceeds of the Series A Notes, cash on hand and commercial paper proceeds to repay these notes.

     On January 4, 2007, the FERC issued an order permitting Pinnacle West to transfer its market based rate tariff and wholesale power sales agreements to a newly-created Pinnacle West subsidiary, Pinnacle West Marketing & Trading. Pinnacle West completed the transfer on February 1, 2007, which resulted in Pinnacle West no longer being a public utility under the Federal Power Act. As a result, Pinnacle West is no longer subject to FERC jurisdiction in connection with its issuance of securities or its incurrence of long-term debt.

     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

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discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.

     Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On December 15, 2006, APS filed a financing application with the ACC requesting an increase in APS’ current long-term debt authorization (approximately $3.2 billion) to approximately $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected future financing needed to fund APS’ capital expenditure and maintenance program and other cash requirements.

     On August 3, 2006, APS issued $400 million of debt as follows: $250 million of its 6.25% Notes due 2016 and $150 million of its 6.875% Notes due 2036. A portion of the proceeds was used to pay at maturity approximately $84 million of APS’ 6.75% Senior Notes due November 15, 2006. The remainder may be used to fund its construction program and other general corporate purposes.

     On September 28, 2006, APS put in place an additional $500 million revolving credit facility that terminates in September 2011. APS may increase the amount of the facility up to a maximum facility of $600 million upon the satisfaction of certain conditions. APS will use the facility for general corporate purposes. The facility can also be used for the issuance of letters of credit. Interest rates are based on APS’ senior unsecured debt credit ratings.

     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 the ACC’s approval of annual PSA adjustments and periodic surcharge applications. During 2006, APS recovered approximately $265 million of PSA deferrals, which provided cash flow but had no effect on earnings because of amortization of the same amount recorded as fuel and purchased power expense.

     APS’ outstanding debt was approximately $2.9 billion at December 31, 2006. APS has two committed lines of credit totaling $900 million that are 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. The $400 million line terminates in December 2010 and the $500 million line terminates in September 2011. At December 31, 2006, APS had no outstanding commercial paper or bank borrowings. APS ended 2006 in an invested cash position.

     See “Cash Flow Hedges” in Note 18 for information related to decreased collateral provided to us by counterparties and the change in our margin account.

     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 2006 and projected capital expenditures for the next

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three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.

     SunCor’s total outstanding debt was approximately $189 million as of December 31, 2006, including $118 million of debt classified as long-term debt under a $170 million line of credit. SunCor’s long-term debt, including current maturities, was $181 million and total short-term debt was $8 million at December 31, 2006. See Note 6.

     See Note 22 for a discussion of the sale of Pinnacle West Energy’s 75% ownership interest in Silverhawk.

     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 and Pinnacle West Marketing & Trading expect 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 $846 million, including $160 million related to the PSA, of regulatory assets on the Consolidated Balance Sheets at December 31, 2006. Included in the $160 million is approximately $45 million related to the 2005 unplanned Palo Verde outages and $79 million related to the 2006 unplanned outages, which currently are the subject of inquiry by the ACC.

     At December 31, 2006, APS recorded a regulatory asset of $473 million in accordance with SFAS No. 158 for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC this regulatory asset would be charged to OCI.

     In addition, we had $635 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2006, which primarily are related to removal costs. See Notes 1, 3 and 8 for more information about regulatory assets, APS’ general rate case and the PSA.

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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, 2006 reported pension liability on the Consolidated Balance Sheets and our 2006 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):

	Increase (Decrease)
	Impact on			Impact on
	Pension			Pension
Actuarial Assumption (a)	Liability			Expense
Discount rate:
Increase 1%	$	(217	)	$	(9	)
Decrease 1%		249			9
Expected long-term rate of return on plan assets:
Increase 1%		—			(5	)
Decrease 1%		—			5

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

     The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2006 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2006 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 Other			Impact on Other
	Postretirement Benefit			Postretirement Benefit
Actuarial Assumption (a)	Obligation			Expense
Discount rate:
Increase 1%	$	(92	)	$	(5	)
Decrease 1%		108			5
Health care cost trend rate (b):
Increase 1%		105			8
Decrease 1%		(87	)		(7	)
Expected long-term rate of return on plan assets – pretax:
Increase 1%		—			(2	)
Decrease 1%		—			2

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

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

Derivative Accounting

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

     In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109.” This guidance requires us to recognize the tax benefits of an uncertain tax position if it is more likely than not that the benefit will be sustained upon examination by the taxing authority. A tax position that meets the more-likely-than-not recognition threshold must be recognized in the financial statements at the largest amount of benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The Interpretation is effective for fiscal years beginning after December 15, 2006. We are currently evaluating this new guidance and believe it will not have a material impact on retained earnings.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for fiscal years beginning after November 15, 2007. We are currently evaluating this new guidance.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating the impact of this new standard.

     See the following Notes for information about new accounting standards:

• See Note 8 and Note S-6 for a discussion of SFAS No. 158 on pension and other postretirement plans.

• See Note 16 for a discussion of the accounting standard (SFAS No. 123(R)) on stock-based compensation.

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. For the years 2004 through 2006, retail electric revenues comprised approximately 82% of our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer mix, customer growth, average usage per customer, electricity rates and tariffs, variations in weather from period to period, and amortization of PSA deferrals. Competitive retail sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition. Off-system sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because the gross margin is credited to APS’ retail customers through the PSA (see Note 3). These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including demand and prices. Competitive wholesale transactions are made by the marketing and trading group through structured trading opportunities involving matched sales and purchases of commodities.

     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, which are discussed in greater detail in Note 3. The most significant pending retail rate proceedings are APS’ general rate case request and an application for a 1.9% PSA surcharge, or temporary rate increase, related to incremental replacement power costs incurred by APS in 2005 in connection with

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unplanned outages at Palo Verde, which is subject to the ACC’s review of the unplanned outages. These matters have been consolidated procedurally and a decision on them by the ACC is expected in the second quarter of 2007. In addition, the ACC staff is conducting a review of the prudence of approximately $79 million in PSA deferrals related to 2006 unplanned outages at Palo Verde.

     Fuel and Purchased Power CostsFuel and purchased power costs included on our income statements are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and, since April 1, 2005, PSA deferrals and amortization thereof. See “Power Supply Adjustor” in Note 3 for information regarding the PSA, including PSA deferrals related to Palo Verde unplanned outages and reduced power operations that are the subject of ACC prudence reviews. See “Natural Gas Supply” in Note 11 for more information on fuel costs. APS’ recovery of PSA deferrals from its ratepayers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.

     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 was 4.4% during 2006. Such growth averaged 4.1% a year for the three years from 2004 through 2006; and we currently expect customer growth to average about 4.0% per year from 2007 to 2009. For the three years 2004 through 2006, APS’ actual retail electricity sales in kilowatt-hours grew at an average rate of 4.2%; adjusted to exclude effects of weather variations, such retail sales growth averaged 4.6% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 3.2% on average, from 2007 through 2009, before the effects of weather variations. We currently expect our retail sales growth in 2007 to be below average because of potential effects on customer usage from the retail rate increases proposed by APS (see Note 3).

     Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors 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 Market ConditionsThe marketing and trading group 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 group, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits.

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.

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     Depreciation and Amortization ExpensesDepreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction, changes in depreciation and amortization rates, and changes in regulatory asset amortization.

     Property TaxesTaxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessed valuation ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.9% of assessed value for 2006 and 9.2% for 2005 and 2004. We expect property taxes to increase as new power plants (including the Sundance Plant acquired in 2005) and additions to our 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 are expected to be our capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.

     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. We cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

     SubsidiariesSunCor’s net income was $61 million in 2006, $56 million in 2005, and $45 million in 2004. See Note 22 for further discussion. We currently expect SunCor’s net income in 2007 will be between $30 million and $35 million. This estimate reflects a slow-down in the western United States residential real estate markets.

     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.

     Interest Rate and Equity Risk

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

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     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, 2006 and 2005. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2006 and 2005 (dollars in thousands):

						Variable-Rate					Fixed-Rate
	Short-Term Debt					Long-Term Debt					Long-Term Debt
	Interest					Interest					Interest
2006	Rates			Amount		Rates			Amount		Rates			Amount
2007		6.26	%	$	35,750		10.25	%	$	112		5.78	%	$	1,549
2008		—			—		7.26	%		161,356		5.39	%		7,810
2009		—			—		9.37	%		2,500		6.23	%		5,371
2010		—			—		—			—		6.24	%		6,455
2011		—			—		—			—		6.24	%		576,320
Years thereafter		—			—		3.77	%		565,855		5.81	%		1,916,758
Total				$	35,750				$	729,823				$	2,514,263
Fair Value				$	35,750				$	729,823				$	2,480,605

						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

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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, 2006 and 2005. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2006 and 2005 (dollars in thousands):

	Variable-Rate					Fixed-Rate
	Long-Term Debt					Long-Term Debt
	Interest					Interest
2006	Rates			Amount		Rates			Amount
2007		—		$	—		6.18	%	$	1,033
2008		—			—		6.18	%		1,230
2009		—			—		6.17	%		1,020
2010		—			—		6.17	%		1,111
2011		—			—		6.38	%		401,320
Years thereafter		3.77	%		565,855		5.81	%		1,916,758
Total				$	565,855				$	2,322,472
Fair Value				$	565,855				$	2,288,814

	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

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:

• 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 activities.

     The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions in 2006 and 2005 (dollars in millions):

	2006						2005
	Regulated			Marketing			Regulated			Marketing
	Electricity			and Trading			Electricity			and Trading
Mark-to-market of net positions at beginning of period	$	335		$	181		$	33		$	107
Recognized in earnings:
Change in mark-to-market gains (losses) for future period deliveries		(12	)		(15	)		14			20
Mark-to-market gains realized including ineffectiveness during the period		(3	)		—			(8	)		(14	)
Deferred as a regulatory liability (asset)		(93	)		—			31			—
Recognized in OCI:
Change in mark-to-market gains (losses) for future period deliveries (a)		(285	)		(67	)		359			102
Mark-to-market gains realized during the period		(4	)		(22	)		(94	)		(34	)
Change in valuation techniques		—			—			—			—
Mark-to-market of net positions at end of period	$	(62	)	$	77		$	335		$	181

(a) The change in regulated mark-to-market recorded in OCI is due primarily to changes 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, 2006 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	2007			2008			2009			2010			2011			thereafter			value
Prices actively quoted	$	(34	)	$	(6	)	$	(10	)	$	—		$	—		$	—		$	(50	)
Prices provided by other external sources		13			(3	)		(1	)		—			—			—			9
Prices based on models and other valuation methods		(3	)		(2	)		(2	)		(3	)		(2	)		(9	)		(21	)
Total by maturity	$	(24	)	$	(11	)	$	(13	)	$	(3	)	$	(2	)	$	(9	)	$	(62	)

Marketing and Trading

															Total
															fair
Source of Fair Value	2007			2008		2009			2010			2011			value
Prices actively quoted	$	9		$	—	$	—		$	—		$	—		$	9
Prices provided by other external sources		40			17		—			—			2			59
Prices based on models and other valuation methods		(5	)		17		(1	)		(1	)		(1	)		9
Total by maturity	$	44		$	34	$	(1	)	$	(1	)	$	1		$	77

     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, 2006 and 2005 (dollars in millions).

	December 31, 2006					December 31, 2005
	Gain (Loss)					Gain (Loss)
	Price Up		Price Down			Price Up		Price Down
Commodity	10%		10%			10%		10%
Mark-to-market changes reported in OCI (a):
Electricity	$	38	$	(38	)	$	66	$	(66	)
Natural gas		80		(80	)		103		(103	)
Total	$	118	$	(118	)	$	169	$	(169	)

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(a) These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

Credit Risk

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

ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS

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.

Deferred Fuel and Purchased Power Costs

     The settlement of our 2003 general retail rate case became effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with 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. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications. See “Power Supply Adjustor” in Note 3.

     Since the inception of the PSA, APS has incurred substantially higher fuel and purchased power costs than those authorized for recovery through APS’ current base rates primarily due to the use of higher cost resources and has deferred those cost differences in accordance with the PSA. The balance of APS’ PSA deferrals at December 31, 2006 was approximately $160 million. The recovery of PSA deferrals through ACC approved adjustors and surcharges recorded as revenue is offset dollar-for-dollar by the amortization of those deferred expenses recorded as fuel and purchased power.

     APS operated Palo Verde Unit 1 at reduced power levels from December 25, 2005 until March 18, 2006 due to vibration levels in one of the Unit’s shutdown cooling lines. During an outage at Unit 1 from March 18, 2006 to July 7, 2006, APS performed the necessary work and modifications to remedy the situation. APS estimates that incremental replacement power costs resulting from these and other unplanned Palo Verde outages and reduced power levels were approximately $88 million during 2006. The related impact on the PSA deferrals was an increase of

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approximately $79 million. These Palo Verde replacement power costs were partially offset by $42 million of lower than expected replacement power costs related to APS’ other generating units during 2006, which decreased PSA deferrals by $38 million.

     The PSA deferral balance at December 31, 2006 includes (a) $45 million related to replacement power costs associated with unplanned 2005 Palo Verde outages and (b) $79 million related to replacement power costs associated with unplanned 2006 outages or reduced power operations at Palo Verde. The PSA deferrals associated with these unplanned Palo Verde outages and reduced power operations are the subject of ACC prudence reviews. The ACC staff has recommended disallowance of $17 million of the 2005 costs. The recommendation will be considered as part of APS’ general rate case currently before the ACC. See “PSA Deferrals Related to Unplanned Palo Verde Outages” in Note 3. The ACC staff recommendation does not change management’s belief that the expenses in question were prudently incurred and, therefore, are recoverable. See Note 3.

2006 Compared with 2005

     APS’ net income for the 2006 was $270 million compared with $170 million for the comparable prior-year period. The $100 million increase was primarily due to an $84 million after-tax regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher retail sales volumes due to customer growth; higher marketing and trading gross margin primarily due to higher mark-to-market gains; income tax credits related to prior years resolved in 2006; and increased other income due to higher interest income on higher investment balances. These positive factors were partially offset by higher operations and maintenance expense related to generation and customer service; higher depreciation and amortization primarily due to increased plant asset balances, partially offset by lower depreciation rates; and higher interest expense. In addition, higher fuel and purchased power costs of $74 million after-tax were partially offset by the deferral of $45 million after-tax of costs in accordance with the PSA. See discussion – “Deferred Fuel and Purchased Power Costs” above.

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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
Gross margin:
Higher fuel and purchased power costs (see “Deferred Fuel and Purchased Power Costs” above)	$	(121	)	$	(74	)
Higher retail sales volumes due to customer growth, excluding weather effects		87			53
Increased deferred fuel and purchased power costs (deferrals began April 1, 2005)		73			45
Absence of prior year cost-based contract for PWEC Dedicated Assets		56			34
Higher marketing and trading gross margin primarily related to higher mark-to-market gains		20			12
Miscellaneous items, net		(8	)		(5	)
Net increase in gross margin		107			65
Regulatory disallowance of plant costs in 2005, in accordance with APS’ 2003 general retail rate case settlement		139			84
Operations and maintenance increases primarily due to:
Generation costs, including increased maintenance and overhauls		(41	)		(25	)
Costs of PWEC Dedicated Assets not included in prior year period		(18	)		(11	)
Customer service costs, including regulatory demand-side management programs and planned maintenance		(16	)		(10	)
Miscellaneous items, net		1			1
Depreciation and amortization increases primarily due to:
Higher depreciable assets due to transfer of PWEC Dedicated Assets		(14	)		(8	)
Higher other depreciable assets partially offset by lower depreciation rates		(14	)		(8	)
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates		(14	)		(8	)
Higher other income, net of expense, primarily due to miscellaneous asset sales and increased interest income on higher investment balances		9			5
Income tax credits related to prior years resolved in 2006		—			11
Miscellaneous items, net		1			4
Net increase in income	$	140		$	100

Regulated Electricity Revenues

     Regulated electricity revenues were $396 million higher for 2006 compared with the prior-year period primarily as a result of:

• a $265 million increase in revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see “Deferred Fuel and Purchased Power Costs” above);

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• a $124 million increase in retail revenues related to customer growth, excluding weather effects;

• a $6 million increase in Off-System Sales primarily resulting from $12 million of sales previously reported in marketing and trading that were classified beginning in April 2005 as sales in regulated electricity in accordance with APS’ 2003 general retail rate case settlement, partially offset by $6 million of lower Off-System Sales in 2006; and

• a $1 million increase due to miscellaneous factors.

Marketing and Trading Revenues

     Marketing and trading revenues were $8 million lower for 2006 compared with the prior-year period primarily as a result of:

• a $12 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 APS’ 2003 general retail rate case settlement;

• a $12 million increase in mark-to-market gains on contracts for future delivery due to changes in forward prices; and

• an $8 million decrease in energy trading revenues on realized sales of electricity primarily due to lower delivered electricity prices and lower volumes.

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):

64

	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.

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:

65

• 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.

LIQUIDITY AND CAPITAL RESOURCES – ARIZONA PUBLIC SERVICE COMPANY

     Contractual Obligations

     The following table summarizes contractual requirements for APS as of December 31, 2006 (dollars in millions):

			2008-		2010-		There-
	2007		2009		2011		after		Total
Long-term debt payments, including interest (a)	$	158	$	316	$	929	$	3,600	$	5,003
Capital lease payments		1		2		2		1		6
Operating lease payments		72		136		123		234		565
Purchase power and fuel commitments (b)		306		472		406		1,304		2,488
Minimum pension funding requirement (c)		23		—		—		—		23
Purchase obligations (d)		44		11		1		80		136
Nuclear decommissioning funding requirements		21		43		48		234		346
Total contractual commitments	$	625	$	980	$	1,509	$	5,453	$	8,567

(a)	The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by the rates at December 31, 2006 (see Note 6).
(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 2007.
(d)	These contractual obligations include commitments for capital expenditures and other obligations.

66

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.

67

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)	69
Report of Independent Registered Public Accounting Firm	70
Pinnacle West Consolidated Statements of Income for 2006, 2005 and 2004	72
Pinnacle West Consolidated Balance Sheets as of December 31, 2006 and 2005	73
Pinnacle West Consolidated Statements of Cash Flows for 2006, 2005 and 2004	75
Pinnacle West Consolidated Statements of Changes in Common Stock Equity for 2006, 2005 and 2004	76
Notes to Pinnacle West’s Consolidated Financial Statements	77
Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)	127
Report of Independent Registered Public Accounting Firm	128
APS Statements of Income for 2006, 2005 and 2004	130
APS Balance Sheets as of December 31, 2006 and 2005	131
APS Statements of Cash Flows for 2006, 2005 and 2004	133
APS Statements of Changes in Common Stock Equity for 2006, 2005 and 2004	134
Supplemental Notes to APS’ Financial Statements	136
Financial Statement Schedule for 2006, 2005 and 2004
Pinnacle West Schedule I – Condensed Statement of Income for 2006, 2005 and 2004	145
Pinnacle West Schedule I – Condensed Balance Sheets as of December 31, 2006 and 2005	146
Pinnacle West Schedule I – Condensed Statement of Cash Flows for 2006, 2005 and 2004	147
Pinnacle West Schedule II – Reserve for Uncollectibles for 2006, 2005 and 2004	148
APS Schedule II – Reserve for Uncollectibles for 2006, 2005 and 2004	149

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

68

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, 2006. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 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.

February 28, 2007

69

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, 2006 and 2005, 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, 2006. Our audits also included the financial statement schedules 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, 2006, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules, 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.

70

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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the criteria established inInternal Control—Integrated Frameworkissued 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, 2006, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 8 to the accompanying consolidated financial statements, effective December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158.

DELOITTE & TOUCHE LLP
Phoenix, Arizona

February 28, 2007

71

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

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

	Year Ended December 31,
	2006			2005			2004
OPERATING REVENUES
Regulated electricity segment	$	2,635,036		$	2,237,145		$	2,035,247
Real estate segment		399,798			338,031			350,315
Marketing and trading		330,742			351,558			400,628
Other revenues		36,172			61,221			42,816
Total		3,401,748			2,987,955			2,829,006
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		960,649			595,141			567,433
Real estate segment operations		324,861			278,366			284,194
Marketing and trading fuel and purchased power		290,637			293,091			320,667
Operations and maintenance		691,277			635,827			592,320
Depreciation and amortization		358,644			347,652			391,597
Taxes other than income taxes		128,395			132,040			120,722
Other expenses		28,415			51,987			34,108
Regulatory disallowance (Note 3)		—			138,562			—
Total		2,782,878			2,472,666			2,311,041
OPERATING INCOME		618,870			515,289			517,965
OTHER
Allowance for equity funds used during construction		14,312			11,191			4,885
Other income (Note 19)		44,016			23,360			53,289
Other expense (Note 19)		(27,800	)		(26,716	)		(21,340	)
Total		30,528			7,835			36,834
INTEREST EXPENSE
Interest charges		196,826			185,087			183,527
Capitalized interest		(20,989	)		(12,018	)		(11,460	)
Total		175,837			173,069			172,067
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		473,561			350,055			382,732
INCOME TAXES		156,418			126,892			136,142
INCOME FROM CONTINUING OPERATIONS		317,143			223,163			246,590
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $6,570, ($29,797) and ($1,805)		10,112			(46,896	)		(3,395	)
NET INCOME	$	327,255		$	176,267		$	243,195
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC		99,417			96,484			91,397
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED		100,010			96,590			91,532
EARNINGS PER WEIGHTED – AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	3.19		$	2.31		$	2.70
Net income – basic		3.29			1.83			2.66
Income from continuing operations – diluted		3.17			2.31			2.69
Net income – diluted		3.27			1.82			2.66
DIVIDENDS DECLARED PER SHARE	$	2.025		$	1.925		$	1.825

See Notes to Pinnacle West’s Consolidated Financial Statements.

72

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	December 31,
	2006			2005
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	87,210		$	154,003
Investment in debt securities		32,700			—
Customer and other receivables		501,628			502,681
Allowance for doubtful accounts		(5,597	)		(4,979	)
Materials and supplies (at average cost)		125,802			109,736
Fossil fuel (at average cost)		21,973			23,658
Deferred income taxes (Note 4)		982			—
Assets from risk management and trading activities (Note 18)		641,040			827,779
Assets held for sale (Note 22)		—			202,645
Other current assets		68,924			75,869
Total current assets		1,474,662			1,891,392
INVESTMENTS AND OTHER ASSETS
Real estate investments – net (Notes 1 and 6)		526,008			390,702
Assets from long-term risk management and trading activities (Note 18)		167,211			597,831
Decommissioning trust accounts (Note 12)		343,771			293,943
Other assets		111,388			111,931
Total investments and other assets		1,148,378			1,394,407
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
Plant in service and held for future use		11,154,919			10,727,695
Less accumulated depreciation and amortization		3,797,475			3,622,884
Net		7,357,444			7,104,811
Construction work in progress		368,284			327,172
Intangible assets, net of accumulated amortization of $218,836 and $182,576		96,100			90,916
Nuclear fuel, net of accumulated amortization of $50,741 and $53,984		60,100			54,184
Total property, plant and equipment		7,881,928			7,577,083
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Notes 1, 3 and 4)		160,268			172,756
Other regulatory assets (Notes 1, 3 and 4)		686,016			151,123
Other deferred debits		104,691			135,884
Total deferred debits		950,975			459,763
TOTAL ASSETS	$	11,455,943		$	11,322,645

See Notes to Pinnacle West’s Consolidated Financial Statements.

73

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

	December 31,
	2006			2005
LIABILITIES AND COMMON STOCK EQUITY
CURRENT LIABILITIES
Accounts payable	$	346,047		$	377,107
Accrued taxes		263,935			289,235
Accrued interest		48,746			31,774
Short-term borrowings (Note 5)		35,750			15,673
Current maturities of long-term debt (Note 6)		1,596			384,947
Customer deposits		70,168			60,509
Deferred income taxes (Note 4)		—			94,710
Liabilities from risk management and trading activities (Note 18)		558,195			720,693
Other current liabilities		134,123			297,425
Total current liabilities		1,458,560			2,272,073
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)		3,232,633			2,608,455
DEFERRED CREDITS AND OTHER
Deferred income taxes (Note 4)		1,225,798			1,225,253
Regulatory liabilities (Notes 1, 3 and 4)		635,431			592,494
Liability for asset retirements (Note 12)		268,389			269,011
Liabilities for pension and other postretirement benefits (Note 8)		588,852			264,476
Liabilities from risk management and trading activities (Note 18)		171,170			256,413
Unamortized gain – sale of utility plant (Note 9)		41,182			45,757
Other		387,812			363,749
Total deferred credits and other		3,318,634			3,017,153
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 99,961,066 at end of 2006 and 99,077,133 at end of 2005		2,114,550			2,067,377
Treasury stock at cost; 2,419 shares at end of 2006 and 20,058 shares at end of 2005		(449	)		(1,245	)
Total common stock		2,114,101			2,066,132
Accumulated other comprehensive income (loss):
Pension and other postretirement benefits (Note 8)		(19,263	)		(97,277	)
Derivative instruments		31,531			262,397
Total accumulated other comprehensive income		12,268			165,120
Retained earnings		1,319,747			1,193,712
Total common stock equity		3,446,116			3,424,964
TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	11,455,943		$	11,322,645

See Notes to Pinnacle West’s Consolidated Financial Statements.

74

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	327,255		$	176,267		$	243,195
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		386,760			381,604			432,161
Deferred fuel and purchased power		(252,849	)		(172,756	)		—
Deferred fuel and purchased power amortization		265,337			—			—
Allowance for equity funds used during construction		(14,312	)		(11,191	)		(4,885	)
Deferred income taxes		27,738			(23,806	)		(113,850	)
Change in mark-to-market valuations		28,464			(11,670	)		(18,915	)
Changes in current assets and liabilities:
Customer and other receivables		9,189			(38,763	)		(11,056	)
Materials, supplies and fossil fuel		(9,094	)		(16,836	)		2,621
Other current assets		10,673			(28,215	)		25,380
Accounts payable		(46,055	)		(6,392	)		85,344
Accrued taxes		(22,329	)		43,624			175,842
Other current liabilities		21,763			1,567			10,561
Proceeds from the sale of real estate assets		34,990			16,218			80,035
Real estate investments		(126,229	)		(88,055	)		(62,812	)
Change in risk management and trading – liabilities		(133,197	)		110,393			13,018
Collateral		(165,828	)		192,040			12,619
Change in pension and other postretirement liabilities		7,488			3,116			23,822
Change in other long-term assets		20,330			(97,893	)		(39,215	)
Change in other long-term liabilities		23,408			71,457			31,621
Net cash flow provided by operating activities		393,502			730,296			850,892
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(737,779	)		(633,532	)		(538,842	)
Capitalized interest		(20,990	)		(12,018	)		(16,311	)
Purchase of Sundance Plant		—			(185,046	)		—
Proceeds from the sale of Silverhawk		207,620			—			90,967
Proceeds from the sale of the Phoenix Suns partnership		—			—			23,101
Purchases of investment securities		(1,439,404	)		(2,962,278	)		(1,040,955	)
Proceeds from sale of investment securities		1,406,704			3,143,481			951,630
Proceeds from nuclear decommissioning trust sales		254,651			186,215			123,795
Investment in nuclear decommissioning trust		(275,393	)		(204,633	)		(135,239	)
Proceeds from sale of real estate investments		39,621			82,719			—
Other		(3,763	)		—			(3,072	)
Net cash flow used for investing activities		(568,733	)		(585,092	)		(544,926	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		757,636			1,088,815			478,328
Repayment of long-term debt		(527,864	)		(1,288,034	)		(604,015	)
Short-term borrowings and payments – net		9,911			(46,413	)		(15,051	)
Dividends paid on common stock		(201,220	)		(186,677	)		(166,772	)
Common stock equity issuance		39,548			298,168			18,291
Other		30,427			(20,426	)		9,690
Net cash flow provided by (used for) financing activities		108,438			(154,567	)		(279,529	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(66,793	)		(9,363	)		26,437
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		154,003			163,366			136,929
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	87,210		$	154,003		$	163,366
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid, net of refunds	$	157,245		$	86,711		$	66,447
Interest paid, net of amounts capitalized	$	153,503		$	181,975		$	191,865

See Notes to Pinnacle West’s Consolidated Financial Statements.

75

PINNACLE WEST CAPITAL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(dollars in thousands)

	Year Ended December 31,
	2006			2005			2004
COMMON STOCK (Note 7)
Balance at beginning of year	$	2,067,377		$	1,769,047		$	1,744,354
Issuance of common stock		39,420			298,330			18,291
Other		7,753			—			6,402
Balance at end of year		2,114,550			2,067,377			1,769,047
TREASURY STOCK (Note 7)
Balance at beginning of year		(1,245	)		(428	)		(3,273	)
Purchase of treasury stock		(229	)		(1,601	)		(2,986	)
Reissuance of treasury stock used for stock compensation, net		1,025			784			5,831
Balance at end of year		(449	)		(1,245	)		(428	)
RETAINED EARNINGS
Balance at beginning of year		1,193,712			1,204,122			1,127,699
Net income		327,255			176,267			243,195
Common stock dividends		(201,220	)		(186,677	)		(166,772	)
Balance at end of year		1,319,747			1,193,712			1,204,122
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year		165,120			(22,545	)		(39,001	)
Unrealized gain (loss) on derivative instruments, net of tax expense (benefit) of ($137,606), $179,927 and $31,117		(214,777	)		281,019			48,226
Reclassification of realized gain to income, net of tax benefit of ($10,308), ($50,056) and ($10,695)		(16,089	)		(77,865	)		(16,546	)
Minimum pension liability adjustment, net of tax expense (benefit) of $28,245, ($9,526) and ($9,756)		44,086			(15,489	)		(15,224	)
Adjustment to reflect a change in accounting for pension and other postretirement benefits, net of tax expense of $22,412 (Note 8)		33,928			—			—
Balance at end of year		12,268			165,120			(22,545	)
TOTAL COMMON STOCK EQUITY	$	3,446,116		$	3,424,964		$	2,950,196
COMPREHENSIVE INCOME
Net income	$	327,255		$	176,267		$	243,195
Other comprehensive income (loss)		(186,780	)		187,665			16,456
Comprehensive income	$	140,475		$	363,932		$	259,651

See Notes to Pinnacle West’s Consolidated Financial Statements.

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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 (dissolved as of August 31, 2006), APS Energy Services, SunCor, El Dorado and Pinnacle West Marketing & Trading. 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. 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.

Derivative Accounting

     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas 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 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

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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, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.

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

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

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

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     See Note 2 for information about a new accounting standard on fair value measurements.

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 purchased power costs and the amount of such costs currently included in base rates.

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

	December 31,
	2006		2005
Pension and other postretirement benefits (Note 8)	$	473	$	—
Deferred fuel and purchased power (a) (Note 3)		160		173
Deferred fuel and purchased power – mark-to-market		62		—
Competition rules compliance charge (a)		34		42
Deferred compensation		28		25
Regulatory asset for deferred income taxes		27		19
Loss on reacquired debt (b)		17		18
Other		45		47
Total regulatory assets	$	846	$	324

(a)	Subject to a carrying charge.
(b)	See “Reacquired Debt Costs” below.

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

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	December 31,
	2006		2005
Removal costs (a)	$	387	$	385
Regulatory liability related to asset retirement obligations		133		101
Tax benefit of Medicare subsidy		46		—
Deferred fuel and purchased power – mark-to-market		—		31
Regulatory liability for deferred income taxes		15		24
Deferred interest income (b)		18		22
Deferred gains on utility property (b)		20		20
Other		16		9
Total regulatory liabilities	$	635	$	592

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

Utility Plant and Depreciation

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

• material and labor;

• contractor costs;

• capitalized leases;

• 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.

     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, 2006 were as follows:

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• Fossil plant – 19 years;

• Nuclear plant – 18 years;

• Other generation – 28 years;

• Transmission – 40 years;

• Distribution – 28 years; and

• Other – 6 years.

     For the years 2004 through 2006, the depreciation rates ranged from a low of 1.18% to a high of 11.43%. The weighted-average rate was 3.14 % for 2006, 3.0% for 2005 and 3.36% for 2004. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 years.

Investments

     El Dorado accounts for its investments using 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 in the nuclear decommissioning trust fund are reviewed in accordance with EITF 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” See Note 12 for information for more information in these investments.

Capitalized Interest

     Capitalized interest represents the cost of debt funds used to finance non-regulated construction projects. The rate used to calculate capitalized interest was a composite rate of 6.8% for 2006, 5.7% for 2005 and 4.9% for 2004. 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 an allowed return on the equity funds used for construction of regulated utility plant. APS’ allowance for borrowed funds is included in capitalized interest on the Consolidated Financial Statements. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.

     AFUDC was calculated by using a composite rate of 8.0% for 2006, 7.7% for 2005 and 8.4% for 2004. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.

Electric Revenues

     We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. However, the determination and billing of electricity sales to individual Native Load customers is

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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 a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and purchased power and fuel costs.

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

Real Estate Revenues

     SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed under the percentage of completion method per SFAS No. 66, “Accounting for Sales of Real Estate.” SunCor recognizes income only after the 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, residential inventory, commercial property 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. Residential inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes and condos under construction. Residential 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.

Cash and Cash Equivalents

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

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     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.

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.

     APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel, and 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. The income tax liability accounts reflect the tax and interest associated with management’s estimate of the most probable resolution of all known and measurable tax exposures. See Note 4. Also, see Note 2 for information regarding new accounting guidance on income taxes.

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

     Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment,” using the modified prospective application method. Because the fair value recognition provisions of both SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements.

     In 2004, there was an immaterial difference between the stock compensation expense recorded in net income and the proforma stock compensation expense in accordance with SFAS No. 123.

Intangible Assets and Emission Allowance Inventory

     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.

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142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. Amortization expense was $39 million in 2006, $33 million in 2005 and $34 million in 2004. Estimated amortization expense on existing intangible assets over the next five years is $34 million in 2007, $20 million in 2008, $12 million in 2009, $10 million in 2010 and $5 million in 2011. At December 31, 2006, the weighted average remaining amortization period for intangible assets is 3 years.

     We account for our emission allowances at the lower of cost or market.

2. New Accounting Standards

     In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.” This guidance requires us to recognize the tax benefits of an uncertain tax position if it is more likely than not that the benefit will be sustained upon examination by the taxing authority. A tax position that meets the more-likely-than-not recognition threshold must be recognized in the financial statements at the largest amount of benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The Interpretation is effective for fiscal years beginning after December 15, 2006. We are currently evaluating this new guidance and believe it will not have a material impact on retained earnings.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for fiscal years beginning after November 15, 2007. We are currently evaluating this new guidance.

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating the impact of this new standard.

     See the following Notes for information about new accounting standards:

• See Note 8 and Note S-6 for a discussion of SFAS No. 158 on pension and other postretirement plans.

• See Note 16 for a discussion of the accounting standard (SFAS No. 123(R)) on stock-based compensation.

3. Regulatory Matters

APS General Rate Case

     On December 15, 2006, hearings concluded in APS’ general rate case before the ACC. APS is requesting a 20.4%, or $434.6 million, increase in its annual retail electricity revenues, designed to recover the following (dollars in millions):

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	Annual
	Revenue			Percentage
	Increase			Increase
Increased fuel and purchased power	$	314.4			14.8	%
Capital structure update		98.3			4.6	%
Rate base update, including acquisition of Sundance Plant		46.2			2.2	%
Pension funding		41.3			1.9	%
Other items		(65.6	)		(3.1	)%
Total increase	$	434.6			20.4	%

     The request is based on (a) a rate base of $4.5 billion as of September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.0325 per kWh based on estimated 2007 prices; and (c) a 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). If the ACC approves the requested base rate increase for fuel and purchased power costs, subsequent PSA rate adjustments and/or PSA surcharges would be reduced because more of such costs would be recovered in base rates. See “Power Supply Adjustor” below.

     APS has also suggested three additional measures for the ACC’s consideration to improve APS’ financial metrics while benefiting APS’ customers in the long run:

• Allowing accelerated depreciation to address the large imbalance between APS’ capital expenditures (estimated to average more than $900 million per year from 2007 through 2009) and its recovery of those expenses (in discussing this measure, APS assumed an increase of $50 million per year in allowed depreciation expense, which would increase APS’ revenue requirement by that same amount );

• Placing generation and distribution construction work in progress (“CWIP”) in rate base (in discussing this measure, APS assumed the inclusion of its June 30, 2006 CWIP balance of $261 million in rate base, which would increase APS’ revenue requirement by about $33 million); and

• Approving an “attrition adjustment” to provide APS a reasonable opportunity to earn an authorized return on equity given overall cost increases and higher levels of construction needed to accommodate ongoing customer growth (APS suggested a minimum attrition adjustment that would increase the allowed return on equity by 1.7% to 4.1%).

     The following table summarizes key rate case positions of APS, the ACC staff and the Arizona Residential Utility Consumer Office (“RUCO”), which the Arizona legislature established to represent the interests of residential utility consumers before the ACC:

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	APS (a)						ACC Staff (b)						RUCO (b)
	Annual						Annual						Annual
	Revenue			Percentage			Revenue			Percentage			Revenue			Percentage
	Increase			Increase			Increase			Increase			Increase			Income
Annual revenue increase (decrease)
Increased fuel and purchased power	$	314.4			14.8	%	$	193.5			9.2	%	$	280.0			13.2	%
Non-fuel components		120.2			5.6	%		(1.0	)		(0.1	)%		(68.0	)		(3.2	)%
Total	$	434.6			20.4	%	$	192.5			9.1	%	$	212.0			10.0	%
Base fuel rate (¢kWh)		3.25	¢					2.80	¢					3.12	¢
Return on equity		11.5	%					10.25	%					9.25	%
Capital structure
Long-term debt		45	%					45	%					50	%
Common equity		55	%					55	%					50	%
Rate base	$4.5 billion						$4.5 billion						$4.5 billion
Test year ended		9/30/2005						9/30/2005						9/30/2005

(a)

APS rejoinder testimony (10/4/06).

(b)

Final position per post-hearing brief and/or final schedules (1/22/07). The ACC staff has also recommended that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.

     Other intervenors in the rate case include Arizonans for Electric Choice and Competition (“AECC”), a business coalition that advocates on behalf of retail electric customers in Arizona; and Phelps Dodge Mining Company (“Phelps Dodge”). In jointly-filed testimony, AECC and Phelps Dodge recommended that the ACC reduce APS’ requested annual increase by at least $134 million.

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. APS later reduced this request to $232 million, or approximately 11%, due to a decline in expected 2006 natural gas and wholesale power prices. The purpose of the emergency interim rate increase was solely to address APS’ under-collection of higher annual fuel and purchased power costs. On May 2, 2006, the ACC approved an order in this matter that, among other things:

• authorized an interim PSA adjustor, effective May 1, 2006, that resulted in an interim retail rate increase of approximately 8.3% designed to recover approximately $138 million of fuel and purchased power costs incurred in 2006 (this interim adjustor, combined with the $15 million PSA surcharge approved by the ACC (see “Surcharge for Certain 2005 PSA Deferrals” below), resulted in a rate increase of

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	approximately 9.0% designed to recover approximately $149 million of fuel and purchased power costs during 2006);
•	provided that amounts collected through the interim PSA adjustor “remain subject to a prudency review at the appropriate time” and that “all unplanned Palo Verde outage costs for 2006 should undergo a prudence audit by [the ACC] Staff” (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below);
•	encouraged parties to APS’ general rate case to “propose modifications to the PSA that will address on a permanent basis, the issues with timing of recovery when deferrals are large and growing”;
•	affirmed APS’ ability to defer fuel and purchased power costs above the prior annual cap of $776.2 million until the ACC decides the general rate case; and
•	encouraged APS to diversify its resources “through large scale, sustained energy efficiency programs, [using] low cost renewable energy resources as a hedge against high fossil fuel costs.”

On December 8, 2006, the ACC approved APS’ request to continue the interim PSA adjustor until rates become effective as a result of the general rate case.

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. Such adjustments are to be implemented by use of a PSA adjustor and PSA surcharges. 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 records 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 PSA adjustor are limited to (a) a cumulative plus or minus $0.004 per kWh from the base fuel amount over the life of the PSA and (b) a maximum plus or minus $0.004 change in the adjustor rate in any one year;

• 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

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	ACC has removed the cap pending the ACC’s final ruling on APS’ pending request in the general rate case to have the cap eliminated or substantially raised;
•	the adjustment is made annually each February 1st and goes into effect automatically unless suspended by the ACC;
•	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.

     2007 PSA Annual AdjustorThe annual adjustor rate is set for twelve-month periods beginning February 1 of each year. The current PSA annual adjustor rate was set at $0.003987 per kWh effective February 1, 2007, down slightly from the maximum $0.004 annual adjustor rate effective February 1, 2006. The new adjustor rate (a) essentially maintains the approximate 5% retail rate increase that took effect February 1, 2006 as a result of the 2006 PSA Annual Adjustor and which expired on February 1, 2007 and (b) is designed to recover approximately $109 million of deferred fuel and purchased power costs over the twelve-month period that began February 1, 2007.

     Surcharge for Certain 2005 PSA DeferralsOn April 12, 2006, the ACC approved APS’ request to recover $15 million of 2005 PSA deferrals over a twelve-month period beginning May 2, 2006, representing a temporary rate increase of approximately 0.7%. Approximately $45 million of 2005 PSA deferrals remain subject to a pending application (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below).

     PSA Deferrals Related to Unplanned Palo Verde OutagesOn February 2, 2006, APS filed with the ACC an application to 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. On August 17, 2006, the ACC staff filed a report with the ACC recommending that the ACC disallow approximately $17.4 million ($10 million after income taxes) of the $45 million request. The report alleges that four of the eleven Palo Verde outages in 2005 were “avoidable,” three of which resulted in the recommended disallowance. The report also finds, among other things, that:

• Three of the outages were due to “faulty or defective vendor supplied equipment” and concludes that APS’ actions were not imprudent in connection with these outages. The report recommends, however, that the ACC evaluate “the degree to which APS has sought appropriate legal or other remedies” in connection with these outages and that APS “be given the opportunity to demonstrate the steps that it has taken in this regard.”

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• “Additional investigation will be needed to determine the cause of and responsibility for” the Palo Verde Unit 1 outage resulting from vibration levels in one of the Unit’s shutdown cooling lines.

     The report also recommends that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.

     APS disagrees with, and will contest, the report’s recommendation that the ACC disallow a portion of the $45 million of PSA deferrals. Under ACC regulations, prudent investments are those “which under ordinary circumstances would be deemed reasonable and not dishonest or obviously wasteful” and “investments [are] presumed to have been prudently made, and such presumptions may be set aside only by clear and convincing evidence that such investments were imprudent.” APS believes the expenses in question were prudently incurred and, therefore, are recoverable. At the request of the ACC staff, this matter is being addressed by the ACC as part of APS’ pending general rate case.

     As noted under “Interim Rate Increase” above, the ACC has directed the ACC staff to conduct a “prudence audit” on unplanned 2006 Palo Verde outage costs. PSA deferrals related to these 2006 outages are estimated to be about $79 million through December 31, 2006. APS believes these expenses were prudently incurred and, therefore, are recoverable.

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 cumulative plus or minus $0.004 per kWh limit from the base fuel amount over the life of the PSA would be eliminated, while the maximum plus or minus $0.004 per kWh limit to changes in the adjustor rate in any one year 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; and

• 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.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The ACC staff has recommended the following potential changes to the PSA:

• Establishing the PSA annual adjustor, beginning in 2007, based on projected fuel costs rather than historical fuel costs; and

• Removing all existing limitations on fuel cost recovery, including the 90/10 sharing arrangement.

     The following table shows the changes in the deferred fuel and purchase power regulatory asset in 2006 and 2005 (dollars in millions):

	2006			2005
Deferred fuel and purchased power regulatory asset-beginning balance	$	173		$	—
Deferred fuel and purchase power costs-current period		244			171
Interest on deferred fuel		8			2
Amounts recovered through revenues		(265	)		—
Deferred fuel and purchase power regulatory asset-ending balance	$	160		$	173

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 consisted of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006.

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.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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. 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. 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.

     See Note 2 for a discussion of a new accounting standard related to uncertain tax positions.

     In 2006 and 2004, 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,
	2006		2005			2004
Current:
Federal	$	110,029	$	107,837		$	200,133
State		21,507		13,064			48,054
Total current		131,536		120,901			248,187
Deferred:
Income from continuing operations		31,452		11,930			(113,850	)
Discontinued operations		—		(35,736	)		—
Total deferred		31,452		(23,806	)		(113,850	)
Total income tax expense		162,988		97,095			134,337
Less: income tax expense (benefit) on discontinued operations		6,570		(29,797	)		(1,805	)
Income tax expense – continuing operations	$	156,418	$	126,892		$	136,142

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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,
	2006			2005			2004
Federal income tax expense at 35% statutory rate	$	165,746		$	122,519		$	133,956
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		17,309			11,981			14,460
Credits and favorable adjustments related to prior years resolved in current year		(14,028	)		—			(6,138	)
Medicare Subsidy Part-D		(3,156	)		(2,733	)		(1,778	)
Allowance for equity funds used during construction (see Note 1)		(4,679	)		(3,694	)		(1,547	)
Other		(4,774	)		(1,181	)		(2,811	)
Income tax expense – continuing operations	$	156,418		$	126,892		$	136,142

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

	December 31,
	2006			2005
Current asset	$	982		$	—
Current liability		—			(94,710	)
Long-term liability		(1,225,798	)		(1,225,253	)
Accumulated deferred income taxes – net	$	(1,224,816	)	$	(1,319,963	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	December 31,
	2006			2005
DEFERRED TAX ASSETS
Risk management and trading activities	$	280,152		$	323,696
Regulatory liabilities:
Asset retirement obligation		203,846			189,726
Federal excess deferred income taxes		12,714			14,446
Deferred fuel and purchased power – mark-to-market		—			11,923
Tax benefit of Medicare subsidy		18,214			—
Other		27,283			29,720
Pension and other postretirement liabilities		272,484			83,753
Deferred gain on Palo Verde Unit 2 sale leaseback		16,160			17,868
Other		73,811			91,015
Total deferred tax assets		904,664			762,147
DEFERRED TAX LIABILITIES
Plant-related		(1,509,812	)		(1,426,158	)
Risk management and trading activities		(285,961	)		(524,940	)
Regulatory assets:
Deferred fuel and purchased power		(62,889	)		(67,461	)
Deferred fuel and purchased power – mark-to-market		(24,427	)		—
Pension and other postretirement benefits		(185,602	)		—
Other		(60,789	)		(63,551	)
Total deferred tax liabilities		(2,129,480	)		(2,082,110	)
Accumulated deferred income taxes – net	$	(1,224,816	)	$	(1,319,963	)

5. Lines of Credit and Short-Term Borrowings

     Pinnacle West had committed lines of credit of $300 million at December 31, 2006 and December 31, 2005, 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 line terminates in December 2010. Pinnacle West had no outstanding borrowings at December 31, 2006 and December 31, 2005. Pinnacle West had approximately $4 million of letters of credit issued under the line at December 31, 2006 and 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). The commitment fees were 0.15% in 2006 and 2005. Pinnacle West had commercial paper borrowings of $28 million outstanding at December 31, 2006 and none at December 31, 2005. All Pinnacle West and APS bank lines of credit and commercial paper agreements are unsecured.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     APS had two committed lines of credit with various banks totaling $900 million at December 31, 2006 and one committed line of credit of $400 million at December 31, 2005, all of 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 $400 million line terminates in December 2010 and the $500 million line terminates in September 2011. APS may increase the $500 million line to $600 million if certain conditions are met. The commitment fees for these lines of credit were 0.10% and 0.11% at December 31, 2006 and 0.11% at December 31, 2005. APS had no bank borrowings outstanding under these lines of credit at December 31, 2006 and 2005. APS had approximately $4 million of letters of credit issued under the $400 million line at December 31, 2006.

     APS had no commercial paper borrowings outstanding at December 31, 2006 and 2005. 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 $170 million at December 31, 2006 maturing in October 2008 and December 2008, and $150 million at December 31, 2005. The commitment fees were 0.125% in 2006 and 2005 for the $150 million line of credit. The commitment fees for the $20 million line of credit were 0.50% in 2006. SunCor had $118 million outstanding at December 31, 2006 and $123 million outstanding at December 31, 2005. The weighted-average interest rate was 7.09% at December 31, 2006 and 5.93% at December 31, 2005. Interest was based on LIBOR plus 2.0% for 2006 and LIBOR plus 1.5% for 2005. The balance is included in long-term debt on the Consolidated Balance Sheets at December 31, 2006 and 2005. SunCor had other short-term loans in the amount of $8 million at December 31, 2006 and $16 million at December 31, 2005. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2006 and LIBOR plus 2.25% and 2.50% or prime plus 1.75% at December 31, 2005.

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, 2006 and 2005 (dollars in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

						December 31,
	Maturity		Interest
	Dates (a)		Rates			2006			2005
APS
Pollution control bonds		2024-2034		(b	)	$	565,855		$	565,855
Pollution control bonds with senior notes		2029		5.05	%		90,000			90,000
Unsecured notes		2011		6.375	%		400,000			400,000
Unsecured notes		2012		6.50	%		375,000			375,000
Unsecured notes		2033		5.625	%		200,000			200,000
Unsecured notes		2015		4.650	%		300,000			300,000
Unsecured notes		2014		5.80	%		300,000			300,000
Secured note		2014		6.00	%		1,592			1,745
Senior notes (c)		2006		6.75	%		—			83,695
Senior notes		2035		5.50	%		250,000			250,000
Senior notes (c)		2016		6.25	%		250,000			—
Senior notes (c)		2036		6.875	%		150,000			—
Unamortized discount and premium							(9,857	)		(9,151	)
Capitalized lease obligations		2009-2012		(d	)		5,880			8,179
Subtotal (e)							2,878,470			2,565,323
SUNCOR
Notes payable		2008		(f	)		180,316			129,040
Capitalized lease obligations		2007-2010		6.25	%		328			266
Subtotal							180,644			129,306
PINNACLE WEST
Senior notes (g)		2006		6.40	%		—			298,518
Senior notes (h)		2011		5.91	%		175,000			—
Unamortized discount and premium							—			(29	)
Capitalized lease obligations		2007		5.45	%		115			284
Subtotal							175,115			298,773
Total long-term debt							3,234,229			2,993,402
Less current maturities							1,596			384,947
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES						$	3,232,633		$	2,608,455

(a)	This schedule does not reflect the timing of redemptions that may occur prior to maturity.
(b)	The weighted-average rate was 3.77% at December 31, 2006 and 3.25% at December 31, 2005. Changes in short-term interest rates would affect the costs associated with this debt.
(c)	On August 3, 2006, APS issued $250 million 6.25% notes due 2016 and $150 million 6.875% notes due 2036. A portion of the proceeds was used to repay outstanding commercial paper balances and $84 million of its 6.75% senior note that matured November 15, 2006. The remainder may be used to fund its construction program and other general corporate purposes.
(d)	The weighted-average interest rate was 6.20% at December 31, 2006 and 5.81% at December 31, 2005. Capital leases are included in property, plant and equipment on the Consolidated Balance Sheets.
(e)	APS’ long-term debt less current maturities was $2.878 billion at December 31, 2006 and $2.48 billion at December 31, 2005. APS’ current maturities of long-term debt were $1 million at December 31, 2006 and $86 million at December 31, 2005.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(f) SunCor had $118 million outstanding at December 31, 2006 under its revolving line of credit. The weighted-average interest rate was 7.08% at December 31, 2006. The remaining amount of approximately $62 million at December 31, 2006 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 2.25%. There is also a note at a fixed rate of 4.25%. 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%.

(g) On April 3, 2006 Pinnacle West repaid $300 million of its 6.40% senior notes. Pinnacle West used proceeds from the issuance of its $175 million 5.91% senior notes issued on February 28, 2006, and commercial paper to repay the notes.

(h) On February 28, 2006, Pinnacle West entered into a $200 million Senior Notes Uncommitted Master Shelf Agreement with Prudential Investment Management Inc. (“Prudential”). Under the terms of the agreement, Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential at any time prior to December 31, 2007. The maturity of the notes cannot exceed five years. On February 28, 2006, Pinnacle West issued $175 million of its 5.91% senior notes, series A, to Prudential. A portion of the proceeds was used to repay its $300 million debt (see note f).

     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At December 31, 2006, the ratio was approximately 48% for Pinnacle West and 46% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.7 times under APS’ bank financing agreements as of December 31, 2006. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

     Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, in the event of a rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

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

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     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
2007	$	2	$	1
2008		169		1
2009		8		1
2010		229		224
2011		576		401
Thereafter		2,260		2,260
Total	$	3,244	$	2,888

7. Common Stock and Treasury Stock

     Our common stock and treasury stock activity during each of the three years 2006, 2005 and 2004 is as follows (dollars in thousands):

	Common Stock				Treasury Stock
	Shares		Amount		Shares			Amount
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	)
Common stock issuance		883,933		39,420		—			—
Purchase of treasury stock (b)		—		—		(5,505	)		(229	)
Reissuance of treasury stock for stock compensation (net)		—		—		23,144			1,025
Other		—		7,753		—			—
Balance at December 31, 2006		99,961,066	$	2,114,550		(2,419	)	$	(449	)

(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.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

8. Retirement Plans and Other Benefits

     Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. 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.

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

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

     In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This guidance requires us to recognize the underfunded positions of our pension and other postretirement benefit plans on our December 31, 2006 balance sheet. The guidance requires that the offset be reported in other comprehensive income, net of tax; however, because the obligations relate primarily to APS’ regulated operations, the increase in liabilities related to APS’ share is offset by regulatory assets. The following tables provide details of the effects of implementing SFAS Statement No. 158 (dollars in thousands):

	Pension
Incremental Effect of Adopting	Balances			Adoption of			Regulatory			Balance
SFAS No. 158 as of	Before			SFAS No.			Accounting			After
December 31, 2006	Adoption			158			Adjustments			Adoption
Assets:
Intangible asset	$	12,932		$	(12,932	)	$	—		$	—
Regulatory asset		—			—			318,461			318,461
Liabilities:
Current benefit liability		—			(3,540	)		—			(3,540	)
Accumulated deferred income taxes - current		—			1,382			—			1,382
Noncurrent benefit liability		(212,262	)		(240,243	)		—			(452,505	)
Accumulated deferred income taxes – long-term		77,838			98,865			(124,359	)		52,344
Common Stock Equity:
Accumulated other comprehensive loss		53,192			156,468			(194,102	)		15,558

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Other Benefits
Incremental Effect of Adopting	Balances		Adoption of			Regulatory			Balance
SFAS No. 158 as of	Before		SFAS No.			Accounting			After
December 31, 2006	Adoption		158			Adjustments			Adoption
Assets:
Noncurrent benefit asset	$	23,589	$	(23,589	)	$	—		$	—
Regulatory asset		—		—			154,531			154,531
Liabilities:
Noncurrent benefit liability		—		(136,347	)		—			(136,347	)
Regulatory liability		—		—			(46,417	)		(46,417	)
Accumulated deferred income taxes – long-term		3,263		90,335			(42,219	)		51,379
Common Stock Equity:
Accumulated other comprehensive loss		—		69,601			(65,895	)		3,706

     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):

	Pension									Other Benefits
	2006			2005			2004			2006			2005			2004
Service cost-benefits earned during the period	$	47,287		$	45,027		$	41,207		$	19,968		$	20,913		$	17,557
Interest cost on benefit obligation		92,196			87,189			81,873			34,653			34,223			29,488
Expected return on plan assets		(95,912	)		(88,403	)		(78,790	)		(36,930	)		(30,471	)		(24,773	)
Amortization of:
Transition (asset) obligation		(645	)		(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		23,366			19,810			17,946			8,662			9,243			7,414
Net periodic benefit cost	$	68,693		$	62,797		$	61,410		$	29,233		$	36,788		$	32,566
Portion of cost charged to expense	$	30,912		$	26,375		$	25,792		$	13,155		$	15,451		$	13,678
APS share of costs charged to expense	$	29,203		$	24,169		$	22,483		$	12,428		$	14,159		$	11,923

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The following table shows the plans’ changes in the benefit obligations and funded status for the years 2006 and 2005 (dollars in thousands):

	Pension						Other Benefits
	2006			2005			2006			2005
Change in Benefit Obligation
Benefit obligation at January 1	$	1,596,068		$	1,454,244		$	585,678		$	536,213
Service cost		47,287			45,027			19,968			20,913
Interest cost		92,196			87,189			34,653			34,223
Benefit payments		(49,189	)		(46,109	)		(16,439	)		(16,962	)
Actuarial losses (gains)		(19,588	)		55,717			(6,875	)		11,291
Plan amendments		3,500			—			—			—
Benefit obligation at December 31		1,670,274			1,596,068			616,985			585,678
Change in Plan Assets
Fair value of plan assets at January 1		1,064,848			982,282			416,174			352,084
Actual return on plan assets		148,895			73,298			47,988			27,302
Employer contributions		46,500			52,700			29,233			36,788
Benefit payments		(46,014	)		(43,432	)		(12,757	)		—
Fair value of plan assets at December 31		1,214,229			1,064,848			480,638			416,174
Funded Status at December 31	$	(456,045	)	$	(531,220	)	$	(136,347	)	$	(169,504	)

     The following table shows the projected benefit obligation and the accumulated benefit obligation for the pension plan in excess of plan assets as of December 31, 2006 and 2005 (dollars in thousands):

	2006		2005
Projected benefit obligation	$	1,670,274	$	1,596,068
Accumulated benefit obligation		1,426,492		1,329,324
Fair value of plan assets		1,214,229		1,064,848

     The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2006 and 2005 (dollars in thousands):

	Pension						Other Benefits
	2006			2005			2006			2005
Current liability	$	(3,540	)	$	—		$	—		$	—
Noncurrent (liability) asset		(452,505	)		(264,476	)		(136,347	)		20,245
Intangible asset		—			11,833			—			—
Accumulated other comprehensive loss (pretax)		—			159,602			—			—
Net amount recognized	$	(456,045	)	$	(93,041	)	$	(136,347	)	$	20,245

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     The following table shows the details related to accumulated other comprehensive income (pretax) as of December 31, 2006 (dollars in thousands):

				Other
	Pension			Benefits
	2006			2006
Net actuarial loss	$	331,054		$	143,079
Prior service cost (credit)		12,932			(1,171	)
Transition obligation		—			18,029
APS’ portion reclassified as a regulatory asset		(318,461	)		(154,531	)
Accumulated other comprehensive loss (pretax)	$	25,525		$	5,406

     The following table shows the estimated amounts that will be amortized from accumulated other comprehensive income and regulatory asset into net periodic benefit cost in 2007 (dollars in thousands):

			Other
	Pension		Benefits
Net actuarial loss	$	14,939	$	6,173
Prior service cost (credit)		2,715		(125	)
Transition obligation		—		3,005
Total amount estimated to be amortized from accumulated other comprehensive income and regulatory asset in 2007	$	17,654	$	9,053

     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,
	2006			2005			2006			2005
Discount rate-pension		5.90	%		5.66	%		5.66	%		5.84	%
Discount rate-other benefits		5.93	%		5.68	%		5.68	%		5.92	%
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		2011			2010			2010			2009

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     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 2007, 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 one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):

	1% Increase		1% Decrease
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	$	8	$	(7	)
Effect on service and interest cost components of net periodic other postretirement benefit costs	$	11	$	(9	)
Effect on the accumulated other postretirement benefit obligation	$	105	$	(87	)

Plan Assets

     Pinnacle West’s qualified pension plan asset allocation at December 31, 2006 and 2005 is as follows:

	Percentage of Plan Assets at
	December 31,						Target Asset Allocation
Asset Category:	2006			2005			December 31, 2006
Equity securities		69	%		59	%		68	%
Fixed income		25			26			25	%
Other		6			15			7	%
Total		100	%		100	%		100	%

     The Board of Directors 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, 2006 and 2005, is as follows:

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	Percentage of Plan Assets at
	December 31,						Target Asset Allocation
Asset Category:	2006			2005			December 31, 2006
Equity securities		74	%		69	%		70	%
Fixed income		25			26			27	%
Other		1			5			3	%
Total		100	%		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.

Contributions

     The contribution to our pension plan in 2007 is estimated to be approximately $24 million. The contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $25 million. APS’ share is approximately 97% 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)
2007	$	55,110	$	17,410
2008		60,246		18,938
2009		66,346		20,644
2010		73,214		22,805
2011		82,517		25,087
Years 2012-2016		582,230		167,717

(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 2006, costs related to APS’ employees represented 97% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in the form of Pinnacle West stock. 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, 2006, approximately 20% of total plan assets were in Pinnacle West stock. Pinnacle West recorded expenses for this plan of approximately $6 million for 2006, $6 million for 2005 and $5 million for 2004. APS recorded expenses for this plan of approximately $6 million in 2006, $6 million in 2005 and $5 million in 2004.

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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.

     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 $72 million in 2006, $71 million in 2005 and $69 million in 2004. APS’ lease expense was $64 million in 2006, $58 million in 2005 and $57 million in 2004.

     The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2007 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
2007	$	79	$	72
2008		76		70
2009		72		66
2010		68		63
2011		65		60
Thereafter		253		234
Total future lease commitments	$	613	$	565

10. Jointly-Owned Facilities

     APS shares ownership of some of its generating and transmission facilities with other companies. Our share of operations and maintenance expense and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2006 (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	%	$	1,933,812	$	990,600	$	56,150
Palo Verde Unit 2 (see Note 9)		17.0	%		670,514		282,112		8,298
Four Corners Units 4 and 5		15.0	%		159,342		97,486		2,459
Navajo Generating Station Units 1, 2 and 3		14.0	%		254,280		137,658		3,440
Cholla common facilities (a)		63.2	%(b)		89,452		47,204		5,616
Transmission facilities:
ANPP 500KV System		35.8	%(b)		79,311		21,432		3,279
Navajo Southern System		31.4	%(b)		34,957		12,421		6,592
Palo Verde – Yuma 500KV System		23.9	%(b)		9,199		3,703		271
Four Corners Switchyards		27.5	%(b)		3,104		1,261		—
Phoenix – Mead System		17.1	%(b)		36,020		4,189		—
Palo Verde – Estrella 500KV System		55.5	%(b)		74,243		2,976		(28	)
Harquahala		80.0	%(b)		—		—		243

(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 at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim.

     APS currently estimates it will incur $147 million (in 2006 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, 2006, APS had a regulatory liability of $1 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

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     NRC Inspection

     In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 generator started but did not provide electrical output during routine inspections on July 25 and September 22, 2006. On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) for this matter. In connection with its finding, the NRC stated that it would “use the NRC Action Matrix to determine the most appropriate response and any increase in NRC oversight, or actions [APS needs] to take in response to the most recent performance deficiencies” and notify APS of its determination at a later date. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, will place one or more Palo Verde units in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix, which will result in an enhanced NRC inspection regimen. APS continues to implement its plan to improve Palo Verde’s operational performance.

     Nuclear Insurance

     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $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 $18.1 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 2007 and 2025 that include required purchase provisions. Pinnacle West estimates the contract requirements to be approximately $366 million in 2007; $259 million in 2008; $241 million in 2009; $221 million in 2010; $191 million in 2011; and $1.3 billion thereafter. APS estimates the contract requirements to be approximately $306 million in 2007; $231 million in 2008; $241 million in 2009; $221 million in 2010; $185 million in 2011; and $1.3 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.

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

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

	Actual						Estimated (a)
	2004		2005		2006		2007		2008		2009		2010		2011		Thereafter
Coal take-or-pay commitments	$	41	$	48	$	67	$	70	$	72	$	82	$	97	$	77	$	552

(a) Total take-or-pay commitments are approximately $950 million. The total net present value of these commitments is approximately $592 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 both December 31, 2006 and December 31, 2005 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. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope and the type of transactions that are properly subject to the refund orders. In the decision, the Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it potentially to include additional transactions, remanding the orders to the FERC for further proceedings. Petitions for rehearing on this order are due no later than February 28, 2007. In addition, on December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings, specifically addressing the application of the so-called “just and reasonable” standard as opposed to the “public interest” standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement that the FERC review the refund matter using the appropriate standard of review. Like the August 2, 2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the existing FERC refund proceedings. 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 was denied on July 31, 2006. On October 10, 2006, the State of California filed a motion to stay the issuance of the mandate (scheduled to be issued on November 2, 2006) until March 2, 2007. The request for stay was granted. 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 wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Ninth Circuit Court of Appeals and oral argument was held on January 8, 2007. Although the FERC ruling in this 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, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.

Construction Program

     Consolidated capital expenditures in 2007 are estimated to be (dollars in millions):

APS	$	893
SunCor		131
Other		13
Total	$	1,037

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.

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     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 cost responsibility associated with the changed contractual obligations in a way that would be less favorable to APS than under the FERC’s July 9, 2003 order. Should this party prevail on this point, APS’ annual capacity cost could be increased by approximately $3 million per year after income taxes for the period September 2003 through December 2005. This appeal had been stayed pending further consideration by the FERC. On May 26, 2006, the FERC issued an Order on Remand affirming its earlier decision that there is no basis for modifying the settlement rates during the remaining term of the settlement. The party seeking appellate review is continuing to pursue an appeal of this issue and has therefore sought rehearing of the May 26, 2006 order. FERC’s next status report is due to the DC Circuit Court of Appeals by May 2, 2007.

Navajo Nation Litigation

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

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

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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 results of operations, cash flows 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.

     The following schedule shows the change in our asset retirement obligations for 2006 and 2005 (dollars in millions):

	2006			2005
Asset retirement obligations at the beginning of year	$	269		$	252
Changes attributable to:
Liabilities settled		(2	)		(2	)
Accretion expense		19			17
Estimated cash flow revisions		(18	)		2
Asset retirement obligations at the end of year	$	268		$	269

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

     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income securities and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we

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record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have recorded the offsetting amount of unrealized gains 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, 2006 and December 31, 2005 (dollars in millions):

			Total
			Unrealized
	Fair Value		Gains
2006
Equity securities	$	164	$	63
Fixed income securities		180		3
Total	$	344	$	66
2005
Equity securities	$	150	$	50
Fixed income securities		144		3
Total	$	294	$	53

     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,
	2006		2005			2004
Realized gains	$	9	$	6		$	1
Realized losses		—		(6	)		(2	)
Proceeds from the sale of securities		255		186			124

     The fair value of fixed income securities summarized by contractual maturities, at December 31, 2006 is as follows (dollars in millions):

	Fair Value
Less than one year	$	10
1 year - 5 years		47
5 years - 10 years		47
Greater than 10 years		76
Total	$	180

13. Selected Quarterly Financial Data (Unaudited)

     The following note presents quarterly financial information for 2006 and 2005.

     Consolidated quarterly financial information for 2006 and 2005 is as follows (dollars in thousands, except per share amounts):

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	2006 Quarter Ended								2006
	March 31,		June 30,		September 30,		December 31,		Total
Operating revenues	$	670,206	$	925,028	$	1,076,442	$	730,072	$	3,401,748
Operations and maintenance		178,427		168,332		164,396		180,122		691,277
Operating income		57,163		191,197		310,440		60,070		618,870
Income taxes		6,793		49,271		98,836		1,518		156,418
Income from continuing operations		11,595		110,843		184,179		10,526		317,143
Net income		12,455		112,154		184,167		18,479		327,255

	2005 Quarter Ended								2005
	March 31,		June 30,		September 30,		December 31,		Total
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

Earnings per share:

	2006 Quarter Ended
	March 31,		June 30,		September 30,		December 31,
Basic earnings per share:
Income from continuing operations	$	0.12	$	1.12	$	1.85	$	0.11
Net income		0.13		1.13		1.85		0.19
Diluted earnings per share:
Income from continuing operations	$	0.12	$	1.11	$	1.84	$	0.10
Net income		0.13		1.13		1.84		0.18

	2005 Quarter Ended
	March 31,		June 30,		September 30,		December 31,
Basic earnings per share:
Income from continuing operations	$	0.32	$	0.88	$	0.86	$	0.24
Net income		0.27		0.28		1.05		0.22
Diluted earnings per share:
Income from continuing operations	$	0.32	$	0.88	$	0.86	$	0.24
Net income		0.27		0.28		1.05		0.22

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

14. Fair Value of Financial Instruments

     We believe that the carrying amounts of our cash equivalents are reasonable estimates of their fair values at December 31, 2006 and 2005 due to their short maturities.

     We hold investments in fixed income 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, 2006 and 2005 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, 2006 and 2005 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, 2006, the carrying value of our long-term debt for Pinnacle West, excluding capitalized lease obligations was $3.23 billion, with an estimated fair value of $3.19 billion. The carrying value of our long-term debt for Pinnacle West excluding capitalized lease obligations and interest rate swaps was $2.99 billion on December 31, 2005, with an estimated fair value of $3.00 billion. On December 31, 2006, the carrying value of APS’ long-term debt excluding capitalized lease obligations was $2.87 billion, with an estimated fair value of $2.84 billion. The carrying value of APS’ long-term debt excluding capital lease obligations was $2.56 billion on December 31, 2005, with an estimated fair value of $2.57 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, 2006, 2005 and 2004:

	2006		2005			2004
Basic earnings per share:
Income from continuing operations	$	3.19	$	2.31		$	2.70
Income (loss) from discontinued operations		0.10		(0.48	)		(0.04	)
Earnings per share – basic	$	3.29	$	1.83		$	2.66
Diluted earnings per share:
Income from continuing operations	$	3.17	$	2.31		$	2.69
Income (loss) from discontinued operations		0.10		(.49	)		(0.03	)
Earnings per share – diluted	$	3.27	$	1.82		$	2.66

     Dilutive stock options increased average common shares outstanding by approximately 593,000 shares in 2006, 106,000 shares in 2005 and 135,000 shares in 2004. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 100,010,108 shares in 2006, 96,589,949 shares in 2005 and 91,532,473 shares in 2004.

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     Options to purchase 437,401 shares of common stock were outstanding at December 31, 2006 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 495,367 at December 31, 2005 and 1,058,616 at December 31, 2004.

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. All options are now vested. The terms of the options cannot be longer than 10 years and the options cannot be repriced during their terms.

     Performance share awards under the 2002 Plan contain performance criteria that affect the number of shares that ultimately vest. Generally, each recipient of performance shares is entitled to receive shares of common stock at the end of a three-year performance period. The number of shares each recipient ultimately receives, if any, is based upon the relative percentile ranking of Pinnacle West’s earnings per share growth rate at the end of the three-year period as compared to the earnings per share growth rate of all relevant companies in a specified utilities index. The fair value of the grant is estimated using the Company’s closing stock price on the date of grant. Management evaluates the probability of meeting the performance criteria at each balance sheet date. If the goals are not achieved, no compensation cost is recognized and any recognized compensation cost is reversed.

     The 1994 Long-Term Incentive Plan (“1994 Plan”) includes outstanding options but no new awards may 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 2006, Retention Unit Awards (“Retention Units”) were granted to key employees. Each Retention Unit represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Retention Units will be redeemed the first business day of calendar years 2007, 2008, 2009 and 2010. In addition, the employee will receive the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. The Retention Units vest over a four year period from 2006 through 2009, unless the employee is eligible to retire, in which case the employee’s Retention Units are immediately vested and the compensation expense is recognized. As this award is accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, is remeasured at each balance sheet date.

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     Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment,” using the modified prospective application method. Because the fair value recognition provisions of both SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements.

     The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $13 million in 2006, $6 million in 2005 and $8 million in 2004. The compensation cost that Pinnacle West has capitalized was immaterial in 2006, 2005 and 2004. Pinnacle West’s total income tax benefit recognized in the condensed consolidated income statement for share-based compensation arrangements was $5 million in 2006, $2 million in 2005 and $3 million for 2004. APS’ share of compensation cost that has been charged against income was $12 million in 2006, $5 million in 2005 and $6 million in 2004.

     The following table is a summary of option activity under our equity incentive plans as of December 31, 2006 and changes during the year:

					Weighted-
					Average		Aggregate
			Weighted-		Remaining		Intrinsic Value
	Shares		Average Exercise		Contractual Term		(dollars in
Options	(in thousands)		Price		(Years)		thousands)
Outstanding at January 1, 2006		1,696	$	39.65
Exercised		588		37.64
Forfeited or expired		20		43.23
Outstanding at December 31, 2006		1,088		40.64		4.0	$	10,935
Exercisable at December 31, 2006		1,082		40.65		4.0	$	10,863

     There were no options granted during the years 2006 and 2005. The intrinsic value of options exercised was $5 million for 2006, $4 million for 2005 and $3 million for 2004.

     The following table is a summary of the status of stock compensation awards, other than options, as of December 31, 2006 and changes during the year:

	Shares			Weighted-Average Grant-Date
Nonvested shares	(in thousands)			Fair Value
Nonvested at January 1, 2006		528		$	38.23
Granted		286			41.50
Vested		(205	)		38.25
Forfeited		(180	)		35.72
Nonvested at December 31, 2006		429			41.45

     As of December 31, 2006, there was $8 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 1.9 years. The number of shares vested

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during the year ended December 31, 2006 was 205,204 shares. The total fair value of shares vested during 2006 was $10 million and $3 million for 2005.

     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, 2006, 2005 and 2004:

			2006 Grant					2005 Grant					2004 Grant
	2006		Date Fair			2005		Date Fair			2004		Date Fair
	Shares		Value			Shares		Value			Shares		Value
Restricted stock		—	$	—			—	$	—			4,000	$	37.68	(a)
Performance share awards		274,070		41.50	(b)		215,300		41.36	(b)		215,285		37.85	(b)
Stock ownership incentive awards		12,526		41.50	(b)		13,114		44.13	(b)		9,015		40.29	(b)
Retention unit awards		—		49.92	(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.

     Cash received from options exercised under our share-based payment arrangements was $22 million for 2006, $17 million for 2005 and $13 million for 2004. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was $2 million for 2006, $1 million for 2005 and $1 million for 2004.

     Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans and it does not expect to repurchase any shares during 2007.

17. Business Segments

     Pinnacle West’s two principal business segments are:

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

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

     Our reportable business segments reflect a change from the previously reported information. As of December 31, 2006, our marketing and trading activities are no longer considered a segment requiring separate reporting or disclosure. The marketing and trading activities consist of our competitive energy business, including wholesale marketing and trading and retail commodity-related energy services. These activities have decreased as a result of fewer market opportunities and the Company’s intention to deemphasize that part of our business. These activities are now reported

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

as part of the “Other” category in the table below. The corresponding information for earlier periods has been reclassified.

     Financial data for 2006, 2005 and 2004 by business segments is provided as follows (dollars in millions):

	Business Segments for the Year Ended December 31, 2006
	Regulated
	Electricity			Real Estate			Other		Total
Operating revenues	$	2,635		$	400		$	367	$	3,402
Purchased power and fuel costs		960			—			291		1,251
Other operating expenses		791			325			57		1,173
Operating margin		884			75			19		978
Depreciation and amortization		354			3			2		359
Interest expense		173			1			2		176
Other expense (income)		(22	)		(11	)		2		(31	)
Income from continuing operations before income taxes		379			82			13		474
Income taxes		120			32			5		157
Income from continuing operations		259			50			8		317
Income from discontinued operations – net of income tax expense of $7 (see Note 22)		—			10			—		10
Net income	$	259		$	60		$	8	$	327
Total assets	$	10,566		$	591		$	299	$	11,456
Capital expenditures	$	662		$	201		$	7	$	870

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Business Segments for the Year Ended December 31, 2005
	Regulated
	Electricity			Real Estate			Other			Total
Operating revenues (a)	$	2,237		$	338		$	413		$	2,988
Purchased power and fuel costs		595			—			293			888
Other operating expenses		740			278			80			1,098
Regulatory disallowance (see Note 3)		139			—			—			139
Operating margin		763			60			40			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			35			350
Income taxes		90			23			14			127
Income from continuing operations		167			35			21			223
Income (loss) from discontinued operations – net of income tax benefit of $(30) (see Note 22) (b)		—			17			(64	)		(47	)
Net income (loss)	$	167		$	52		$	(43	)	$	176
Total assets	$	9,732		$	483		$	1,108		$	11,323
Capital expenditures	$	811		$	106		$	11		$	928

	Business Segments for the Year Ended December 31, 2004
	Regulated
	Electricity		Real Estate			Other			Total
Operating revenues	$	2,035	$	350		$	444		$	2,829
Purchased power and fuel costs		567		—			321			888
Other operating expenses		683		284			64			1,031
Operating margin		785		66			59			910
Depreciation and amortization		384		4			4			392
Interest expense		170		1			1			172
Other expense (income) (c)		4		(6	)		(35	)		(37	)
Income from continuing operations before income taxes		227		67			89			383
Income taxes		75		27			34			136
Income from continuing operations		152		40			55			247
Income (loss) from discontinued operations – net of income tax benefit of $(2) (see Note 22) (b)		—		4			(8	)		(4	)
Net income	$	152	$	44		$	47		$	243
Capital expenditures	$	483	$	81		$	34		$	598

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(a)	Effective April 1, 2005, revenues of approximately $40 million from Off-System Sales, which were previously reported in the other segment, began being reported in the regulated electricity segment in accordance with the retail rate case settlement.
(b)	The other segment relates to the sale and operations of Silverhawk and NAC. See Note 22.
(c)	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 purchases and sales of electricity, fuels, and emissions allowances and credits. As of December 31, 2006, 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.

     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. In the following discussion amounts that would otherwise be recognized in income will be recorded as either a regulatory asset or liability and have no effect on earnings to the extent these amounts are eligible to be recovered through the PSA.

     We assess hedge effectiveness both at inception and on a continuing basis. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated and 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.

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     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 revenues on the Consolidated Statements of Income on a net basis. Trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.

     In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Consolidated Statement of Income, but this does not impact our financial condition, net income or cash flows.

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, 2006, 2005 and 2004 are comprised of the following (dollars in thousands):

	2006			2005		2004
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(5,666	)	$	14,289	$	(1,568	)
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness		(10	)		620		185
Gains from the discontinuance of cash flow hedges		453			556		1,137

     During 2007, we estimate that a net gain of $34 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Our assets and liabilities from risk management and trading activities are presented in two categories.

     The following table summarizes our assets and liabilities from risk management and trading activities at December 31, 2006 and 2005 (dollars in thousands):

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2006	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	458,034	$	96,892	$	(481,661	)	$	(135,056	)	$	(61,791	)
Margin account and options		77,705		—		(2,228	)		—			75,477
Marketing and trading:
Mark-to-market		105,301		69,480		(61,553	)		(36,114	)		77,114
Options and emission allowances – at cost		—		839		(12,753	)		—			(11,914	)
Total	$	641,040	$	167,211	$	(558,195	)	$	(171,170	)	$	78,886

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2005	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

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $73 million at December 31, 2006 and a liability of $123 million at December 31, 2005 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 $10 million at December 31, 2006 and $6 million at December 31, 2005, and is included in other current assets on

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the Consolidated Balance Sheets. Collateral provided to us by counterparties was $54 million at December 31, 2006 and $216 million at December 31, 2005, and is included in other current liabilities on the Consolidated Balance Sheets.

Credit Risk

     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ securities are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. 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 2006, 2005 and 2004 (dollars in thousands):

	2006			2005			2004
Other income:
Interest income	$	18,867		$	14,793		$	6,770
SunCor other income		10,881			2,623			4,458
SO2 emission allowance sales and other (a)		10,782			3,187			3,026
Investment gains — net (b)		2,537			752			38,256
Miscellaneous		949			2,005			779
Total other income	$	44,016		$	23,360		$	53,289
Other expense:
Non-operating costs (a)	$	(16,223	)	$	(13,589	)	$	(15,524	)
Asset dispositions		(2,056	)		(9,759	)		(1,212	)
Miscellaneous		(9,521	)		(3,368	)		(4,604	)
Total other expense	$	(27,800	)	$	(26,716	)	$	(21,340	)

(a)	As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).
(b)	Includes a $35 million gain ($21 million after tax) related to the sale of a limited partnership interest in the Phoenix Suns in 2004.

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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.

     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, 2006, APS would have been required to assume approximately $214 million of debt and pay the equity participants approximately $177 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 $39 million at December 31, 2006 and approximately $34 million at December 31, 2005.

21. Guarantees

     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of APS Energy Services. 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 APS Energy Services would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of its subsidiary. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. At December 31, 2006, we had guarantees totaling $16 million and surety bonds totaling $25 million with a term of approximately one year for APS Energy Services.

     At December 31, 2006, Pinnacle West had approximately $4 million of letters of credit related to workers’ compensation expiring in 2007. 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, 2006, 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 $91 million of letters of credit to support certain equity 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, at December 31, 2006, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2007. 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.

123

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

22. Discontinued Operations

     Silverhawk(other)–In June 2005, we entered into an agreement to sell our 75% interest in the Silverhawk Power Station 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 chart below includes 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.

     SunCor(real estate segment)–In 2006 and 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 $9 million ($15 million pretax) in 2006 and $15 million ($25 million pretax) in 2005.

     NAC(other)–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 income (loss) after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2006, 2005 and 2004 (dollars in millions):

124

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	2006			2005			2004
Revenue:
SunCor – commercial operations	$	3		$	9		$	21
Silverhawk		1			95			61
NAC		—			—			34
Total revenue	$	4		$	104		$	116
Income (loss) before taxes:
SunCor – commercial operations	$	17		$	28		$	6
Silverhawk (a)		1			(111	)		(18	)
NAC		(1	)		6			7
Total income (loss) before taxes	$	17		$	(77	)	$	(5	)
Income (loss) after taxes:
SunCor – commercial operations	$	10		$	17		$	4
Silverhawk		1			(67	)		(12	)
NAC		(1	)		3			4
Total income (loss) after taxes	$	10		$	(47	)	$	(4	)

(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.

125

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, 2006. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 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.

February 28, 2007

126

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, 2006 and 2005, 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, 2006. 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, 2006, based on criteria established inInternal 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.

127

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, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, 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, 2006, 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, 2006, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note S-6 to the accompanying financial statements, effective December 31, 2006, the Company adopted Statement of Financial Accounting Standards No. 158.

DELOITTE & TOUCHE LLP
Phoenix, Arizona

February 28, 2007

128

ARIZONA PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME

(dollars in thousands)

	Year Ended December 31,
	2006			2005			2004
Electric Operating Revenues:
Regulated electricity	$	2,640,989		$	2,244,951		$	2,051,602
Marketing and trading		17,524			25,842			145,519
Total		2,658,513			2,270,793			2,197,121
Operating Expenses:
Regulated electricity fuel and purchased power		965,712			656,654			612,300
Marketing and trading fuel and purchased power		4,055			32,328			150,954
Operations and maintenance		665,631			591,941			540,277
Depreciation and amortization		353,057			325,174			336,648
Income taxes (Notes 4 and S-1)		144,127			157,273			113,696
Other taxes		127,989			125,810			114,265
Total		2,260,571			1,889,180			1,868,140
Operating Income		397,942			381,613			328,981
Other Income (Deductions):
Regulatory disallowance (Note 3)		—			(138,562	)		—
Income taxes (Notes 4 and S-1)		5,200			59,263			(6,334	)
Allowance for equity funds used during construction		14,312			11,191			4,885
Other income (Note S-4)		31,902			22,141			30,593
Other expense (Note S-4)		(23,830	)		(23,204	)		(13,816	)
Total		27,584			(69,171	)		15,328
Interest Deductions:
Interest on long-term debt		149,240			138,476			140,556
Interest on short-term borrowings		9,529			7,026			6,427
Debt discount, premium and expense		4,363			4,085			4,854
Allowance for borrowed funds used during construction		(7,336	)		(7,624	)		(7,155	)
Total		155,796			141,963			144,682
Net Income	$	269,730		$	170,479		$	199,627

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

129

ARIZONA PUBLIC SERVICE COMPANY

BALANCE SHEETS

(dollars in thousands)

	December 31,
	2006			2005
ASSETS
Utility Plant (Notes 1, 6, 9 and 10)
Electric plant in service and held for future use	$	11,094,868		$	10,682,999
Less accumulated depreciation and amortization		3,789,534			3,616,886
Net		7,305,334			7,066,113
Construction work in progress		365,704			314,584
Intangible assets, net of accumulated amortization of $217,099 and $181,046		95,601			90,327
Nuclear fuel, net of accumulated amortization of $50,741 and $53,984		60,100			54,184
Total utility plant		7,826,739			7,525,208
Investments and Other Assets
Decommissioning trust accounts (Note 12)		343,771			293,943
Assets from risk management and trading activities (Note S-3)		96,892			234,372
Other assets		67,763			64,128
Total investments and other assets		508,426			592,443
Current Assets:
Cash and cash equivalents		81,870			49,933
Investment in debt securities		32,700			—
Customer and other receivables		410,436			421,621
Allowance for doubtful accounts		(4,223	)		(3,568	)
Materials and supplies (at average cost)		125,802			109,736
Fossil fuel (at average cost)		21,973			23,658
Assets from risk management and trading activities (Note S-3)		539,308			532,923
Deferred income taxes		19,220			—
Other		13,367			14,639
Total current assets		1,240,453			1,148,942
Deferred Debits:
Deferred fuel and purchased power regulatory asset (Notes 1, 3, 4 and S-1)		160,268			172,756
Other regulatory assets (Notes 1, 3, 4 and S-1)		686,016			151,123
Unamortized debt issue costs		26,393			25,279
Other		65,397			91,690
Total deferred debits		938,074			440,848
Total Assets	$	10,513,692		$	9,707,441

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,
	2006		2005
LIABILITIES AND EQUITY
Capitalization:
Common stock	$	178,162	$	178,162
Additional paid-in capital (Note 3)		2,065,918		1,853,098
Retained earnings		960,405		860,675
Accumulated other comprehensive income (loss):
Minimum pension liability adjustment		—		(86,132	)
Derivative instruments		2,988		179,422
Common stock equity		3,207,473		2,985,225
Long-term debt less current maturities (Note 6)		2,877,502		2,479,703
Total capitalization		6,084,975		5,464,928
Current Liabilities:
Current maturities of long-term debt (Note 6)		968		85,620
Accounts payable		223,417		215,384
Accrued taxes		381,444		360,737
Accrued interest		45,254		25,003
Customer deposits		61,900		55,474
Deferred income taxes (Notes 4 and S-1)		—		64,210
Liabilities from risk management and trading activities (Note S-3)		490,855		480,138
Other		74,728		227,398
Total current liabilities		1,278,566		1,513,964
Deferred Credits and Other:
Deferred income taxes (Notes 4 and S-1)		1,215,862		1,215,403
Regulatory liabilities (Notes 1, 3, 4, and S-1)		635,431		592,494
Liability for asset retirements (Note 12)		268,389		269,011
Pension and other postretirement liabilities (Notes 8 and S-6)		551,531		233,342
Customer advances for construction		71,211		60,287
Unamortized gain — sale of utility plant (Note 9)		41,182		45,757
Liabilities from risk management and trading activities (Note S-3)		135,056		83,774
Other		231,489		228,481
Total deferred credits and other		3,150,151		2,728,549
Commitments and Contingencies (Notes 3, 11, 12 and S-5)
Total Liabilities and Equity	$	10,513,692	$	9,707,441

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

STATEMENTS OF CASH FLOWS

(dollars in thousands)

	Year Ended December 31,
	2006			2005			2004
Cash Flows from Operating Activities:
Net income	$	269,730		$	170,479		$	199,627
Adjustments to reconcile net income to net cash provided by operating activities:
Regulatory disallowance		—			138,562			—
Depreciation and amortization including nuclear fuel		381,173			353,082			367,094
Deferred fuel and purchased power		(252,849	)		(172,756	)		—
Deferred fuel and purchased power amortization		265,337			—			—
Allowance for equity funds used during construction		(14,312	)		(11,191	)		(4,885	)
Deferred income taxes		(305	)		9,659			(140,855	)
Change in derivative mark-to-market valuations		6,893			3,492			(15,807	)
Changes in current assets and liabilities:
Customer and other receivables		20,970			(56,152	)		(24,146	)
Materials, supplies and fossil fuel		(14,381	)		(12,268	)		4,643
Other current assets		3,666			(2,592	)		(2,529	)
Accounts payable		5,825			(12,372	)		88,937
Accrued taxes		23,678			67,454			202,047
Collateral		(175,799	)		169,080			5,671
Other current liabilities		45,125			(37,781	)		22,715
Change in risk management and trading – liabilities		(121,833	)		115,495			8,879
Change in risk management and trading – assets		(74,208	)		15,449			(6,845	)
Change in pension and other postretirement liabilities		7,406			(10,730	)		22,361
Change in other long-term assets		2,828			(24,752	)		(37,541	)
Change in other long-term liabilities		14,769			19,732			28,772
Net cash flow provided by operating activities		393,713			721,890			718,138
Cash Flows from Investing Activities:
Capital expenditures		(648,743	)		(609,857	)		(513,677	)
Transfer of PWEC Dedicated Assets to APS		—			(500,000	)		—
Purchase of Sundance Plant		—			(185,046	)		—
Allowance for borrowed funds used during construction		(7,336	)		(7,624	)		(7,155	)
Purchases of investment securities		(1,291,903	)		(1,476,623	)		(871,610	)
Proceeds from sale of investment securities		1,259,203			1,657,798			760,285
Proceeds from nuclear decommissioning trust sales		254,651			186,215			123,795
Investment in nuclear decommissioning trust		(275,393	)		(204,633	)		(135,239	)
Repayment of loan by Pinnacle West Energy		—			500,000			—
Other		(4,470	)		(5,372	)		10,639
Net cash flow used for investing activities		(713,991	)		(645,142	)		(632,962	)
Cash Flows from Financing Activities:
Issuance of long-term debt		395,481			411,787			478,140
Equity infusion		212,820			250,000			—
Dividends paid on common stock		(170,000	)		(170,000	)		(170,000	)
Repayment and reacquisition of long-term debt		(86,086	)		(568,177	)		(385,893	)
Net cash flow (used for) provided by financing activities		352,215			(76,390	)		(77,753	)
Net increase in cash and cash equivalents		31,937			358			7,423
Cash and cash equivalents at beginning of year		49,933			49,575			42,152
Cash and cash equivalents at end of year	$	81,870		$	49,933		$	49,575
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes, net of refunds	$	117,831		$	34,252		$	68,074
Interest, net of amounts capitalized	$	131,183		$	146,207		$	149,148

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 CHANGES IN COMMON STOCK EQUITY

(dollars in thousands)

	Year Ended December 31,
	2006			2005			2004
COMMON STOCK	$	178,162		$	178,162		$	178,162
ADDITIONAL PAID-IN CAPITAL		2,065,918			1,853,098			1,246,804
RETAINED EARNINGS
Balance at beginning of year		860,675			860,196			830,569
Net income		269,730			170,479			199,627
Common stock dividends		(170,000	)		(170,000	)		(170,000	)
Balance at end of year		960,405			860,675			860,196
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Balance at beginning of year		93,290			(52,760	)		(51,905	)
Unrealized gain (loss) on derivative instruments, net of tax expense (benefit) of ($111,367), $140,135 and $16,824		(173,872	)		218,656			25,892
Reclassification of realized gain to income, net of tax benefit of ($1,657), ($37,082) and ($8,344)		(2,562	)		(57,561	)		(12,818	)
Minimum pension liability adjustment, net of tax expense (benefit) of $27,424, ($9,023) and ($8,936)		42,731			(15,045	)		(13,929	)
Adjustment to reflect a change in accounting for pension and other postretirement benefits, net of tax expense of $27,760 (Notes 8 and S-6)		43,401			—			—
Balance at end of year		2,988			93,290			(52,760	)
TOTAL COMMON STOCK EQUITY	$	3,207,473		$	2,985,225		$	2,232,402
COMPREHENSIVE INCOME
Net income	$	269,730		$	170,479		$	199,627
Other comprehensive income (loss)		(133,703	)		146,050			(855	)
Total comprehensive income	$	136,027		$	316,529		$	198,772

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

133

     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			—
New Accounting Standards	Note 2			—
Regulatory Matters	Note 3			—
Income Taxes	Note 4		Note S-1
Lines of Credit and Short-Term Borrowings	Note 5			—
Long-Term Debt	Note 6			—
Common Stock and Treasury Stock	Note 7			—
Retirement Plans and Other Benefits	Note 8		Note S-6
Leases	Note 9			—
Jointly-Owned Facilities	Note 10			—
Commitments and Contingencies	Note 11			—
Asset Retirement Obligations	Note 12			—
Selected Quarterly Financial Data (Unaudited)	Note 13		Note S-2
Fair Value 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-3
Other Income and Other Expense	Note 19		Note S-4
Variable Interest Entities	Note 20			—
Guarantees	Note 21			—
Discontinued Operations	Note 22			—
Related Party Transactions		—	Note S-5

134

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

S-1. Income Taxes

     APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’ taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.

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

     APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to 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. 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. 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 2006 and 2004, 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,
	2006		2005		2004
Current:
Federal	$	114,971	$	79,917	$	207,306
State		21,442		8,434		53,579
Total current		136,413		88,351		260,885
Deferred		2,514		9,659		(140,855	)
Total income tax expense	$	138,927	$	98,010	$	120,030

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

135

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

     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,
	2006			2005			2004
Federal income tax expense at 35% statutory rate	$	143,030		$	93,971		$	111,880
Increases (reductions) in tax expense resulting from:
State income tax net of federal income tax benefit		15,684			8,986			12,496
Credits and favorable adjustments related to prior years resolved in current year		(10,518	)		—			(315	)
Medicare Subsidy Part-D		(3,036	)		(2,465	)		(1,507	)
Allowance for equity funds used during construction (see Note 1)		(4,656	)		(3,694	)		(1,543	)
Other		(1,577	)		1,212			(981	)
Income tax expense	$	138,927		$	98,010		$	120,030

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

	December 31,
	2006			2005
Current asset	$	19,220		$	—
Current liability		—			(64,210	)
Long-term liability		(1,215,862	)		(1,215,403	)
Accumulated deferred income taxes – net	$	(1,196,642	)	$	(1,279,613	)

136

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

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

	December 31,
	2006			2005
DEFERRED TAX ASSETS
Regulatory liabilities:
Asset retirement obligation	$	203,846		$	189,726
Federal excess deferred income tax		12,714			14,446
Deferred fuel and purchased power – mark-to-market		—			11,923
Tax benefit of Medicare subsidy		18,214			—
Other		27,283			29,720
Risk management and trading activities		244,611			171,640
Pension and other postretirement liabilities		257,910			72,376
Deferred gain on Palo Verde Unit 2 sale-leaseback		16,160			17,868
Other		86,442			71,567
Total deferred tax assets		867,180			579,266
DEFERRED TAX LIABILITIES
Plant-related		(1,509,812	)		(1,426,158	)
Risk management and trading activities		(220,303	)		(301,709	)
Regulatory assets:
Deferred fuel and purchased power		(62,889	)		(67,461	)
Deferred fuel and purchased power – mark-to-market		(24,427	)		—
Pension and other postretirement benefits		(185,602	)		—
Other		(60,789	)		(63,551	)
Total deferred tax liabilities		(2,063,822	)		(1,858,879	)
Accumulated deferred income taxes – net	$	(1,196,642	)	$	(1,279,613	)

137

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

S-2. Selected Quarterly Financial Data (Unaudited)

     Quarterly financial information for 2006 and 2005 is as follows (dollars in thousands):

	2006 Quarter Ended,									2006
	March 31,			June 30,		September 30,		December 31,		Total
Operating revenues	$	476,869		$	718,850	$	886,686	$	576,108	$	2,658,513
Operations and maintenance		173,353			164,373		156,170		171,735		665,631
Operating income		25,044			119,967		200,580		52,351		397,942
Net income (loss)		(5,521	)		93,757		168,634		12,860		269,730

	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

S-3. Derivative and Energy Trading Accounting

     APS is exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, 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, 2006, 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, 2006, 2005 and 2004 are comprised of the following (dollars in thousands):

	2006			2005		2004
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	(5,666	)	$	14,452	$	(1,570	)
Gains (losses) from the change in options time value excluded from measurement of effectiveness		(10	)		620		185
Gains from the discontinuance of cash flow hedges		178			473		575

     During 2007, APS estimates that a net gain of $6 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).

138

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

     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, 2006 and 2005 (dollars in thousands):

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2006	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	458,034	$	96,892	$	(481,661	)	$	(135,056	)	$	(61,791	)
Margin account and options		77,705		—		(2,228	)		—			75,477
Marketing and Trading:
Mark-to-market		3,569		—		(6,654	)		—			(3,085	)
Options at cost		—		—		(312	)		—			(312	)
Total	$	539,308	$	96,892	$	(490,855	)	$	(135,056	)	$	10,289

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2005	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		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

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $73 million at December 31, 2006 and a liability of $123 million at December 31, 2005 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 APS’ open positions on certain energy-related contracts. Collateral provided to counterparties was $2 million at December 31, 2006 and is included in other current assets on the balance sheet. No collateral was provided to counterparties at December 31, 2005. Collateral provided to us by counterparties was $1 million at December 31, 2006 and $175 million at December 31, 2005, and is included in other current liabilities on the Balance Sheets.

139

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

S-4. Other Income and Other Expense

     The following table provides detail of APS’ other income and other expense for 2006, 2005 and 2004 (dollars in thousands):

	2006			2005			2004
Other income:
Interest income	$	16,526		$	14,513		$	22,354
SO2 emission allowance sales and other (a)		10,782			3,187			3,026
Investment gains – net		3,645			1,705			3,192
Miscellaneous		949			2,736			2,021
Total other income	$	31,902		$	22,141		$	30,593
Other expense:
Non-operating costs (a)	$	(15,415	)	$	(11,706	)	$	(8,923	)
Asset dispositions		(1,851	)		(9,759	)		(1,212	)
Miscellaneous		(6,564	)		(1,739	)		(3,681	)
Total other expense	$	(23,830	)	$	(23,204	)	$	(13,816	)

(a) As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).

S-5. Related Party Transactions

     From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s 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):

140

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

	Year Ended December 31,
	2006		2005		2004
Electric operating revenues:
Pinnacle West – marketing and trading	$	6	$	6	$	13
Pinnacle West Energy		—		2		3
Total	$	6	$	8	$	16
Fuel and purchased power costs:
Pinnacle West Energy	$	—	$	61	$	75
Capital expenditures:
Pinnacle West — marketing and trading	$	—	$	—	$	11
Pinnacle West		—		—		22
Total	$	—	$	—	$	33
Other:
Pinnacle West Energy interest income	$	—	$	7	$	19
Equity infusion from Pinnacle West (see Note 3)	$	210	$	250	$	—

	As of December 31,
	2006			2005
Net intercompany receivables (payables):
Pinnacle West – marketing and trading	$	2		$	82
APS Energy Services		1			2
Pinnacle West		(20	)		(2	)
Total	$	(17	)	$	82

     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. 02-3.”

     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.

141

NOTES TO ARIZONA PUBLIC SERVICE COMPANY

     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.

S-6. Retirement Plans and Other Benefits

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This guidance requires us to recognize the underfunded positions of our pension and other postretirement benefit plans on our December 31, 2006 balance sheet. The guidance requires that the offset be reported in other comprehensive income, net of tax; however, because the obligations relate to our regulated operations, the increase in liabilities is offset by regulatory assets. The following tables provide details of the effects of implementing SFAS Statement No. 158 (dollars in thousands):

	Pension
Incremental Effect of Adopting	Balances			Adoption of			Regulatory			Balance
SFAS No. 158 as of	Before			SFAS No.			Accounting			After
December 31, 2006	Adoption			158			Adjustments			Adoption
Assets:
Intangible asset	$	11,487		$	(11,487	)	$	—		$	—
Regulatory asset		—			—			318,461			318,461
Liabilities:
Current benefit liability		—			(3,122	)		—			(3,122	)
Accumulated deferred income taxes — current		—			1,225			—			1,225
Noncurrent benefit liability		(183,432	)		(232,421	)		—			(415,853	)
Accumulated deferred income taxes — long term		67,471			95,709			(124,964	)		38,217
Common Stock Equity:
Accumulated other comprehensive loss (income)		43,401			150,095			(193,497	)		—

	Other Benefits
Incremental Effect of Adopting	Balances		Adoption of			Regulatory			Balance
SFAS No. 158 as of	Before		SFAS No.			Accounting			After
December 31, 2006	Adoption		158			Adjustments			Adoption
Assets:
Noncurrent benefit asset	$	18,853	$	(18,853	)	$	—		$	—
Regulatory asset		—		—			154,531			154,531
Liabilities:
Noncurrent benefit liability		—		(135,678	)		—			(135,678	)
Regulatory liability		—		—			(46,417	)		(46,417	)
Accumulated deferred income taxes — long term		4,663		88,841			(42,424	)		51,080
Common Stock Equity:
Accumulated other comprehensive loss (income)		—		65,690			(65,690	)		—

142

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENT OF INCOME
(in thousands)

	Year Ended December 31,
	2006			2005			2004
Operating Revenues	$	119,224		$	154,053		$	81,716
Operating Expenses
Fuel and purchased power		101,360			95,223			49,926
Other operating expenses		9,607			3,268			3,380
Total		110,967			98,491			53,306
Operating Income		8,257			55,562			28,410
Other
Equity in earnings of subsidiaries		324,504			58,759			240,732
Other income		2,208			5,337			2,058
Total		326,712			64,096			242,790
Interest Expense		20,522			16,472			15,490
Income from continuing operations		314,447			103,186			255,710
Income tax benefit		(12,898	)		(62,761	)		(12,789	)
Income from continuing operations – net of income taxes		327,345			165,947			268,499
Income (loss) from discontinued operations		(90	)		10,320			(25,304	)
Net Income	$	327,255		$	176,267		$	243,195

143

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(in thousands)

	Balance at December 31,
	2006			2005
ASSETS
Current Assets
Cash and cash equivalents	$	11		$	85,374
Customer and other receivables		174,583			180,083
Allowance for doubtful accounts		(1,200	)		(1,200	)
Assets from risk management and trading activities		101,604			294,856
Other current assets		10,810			4,805
Total current assets		285,808			563,918
Investments and other assets
Assets from long-term risk management and trading activities		70,319			363,459
Investments in subsidiaries		3,545,329			3,396,150
Other assets		73,300			68,848
Total investments and other assets		3,688,948			3,828,457
Total Assets		$3,974,756			$4,392,375
Liabilities and Common Stock Equity
Current Liabilities
Accounts payable	$	80,903		$	126,353
Accrued taxes		(118,073	)		(68,545	)
Short-term borrowings		27,900			—
Current maturities of long-term debt		115			298,672
Deferred income taxes		18,238			—
Liabilities from risk management and trading activities		67,340			240,555
Other current liabilities		130,985			184,275
Total current liabilities		207,408			781,310
Long-term debt less current maturities		175,000			101
Deferred credits and other
Deferred income taxes		19,582			42,325
Pension and other postretirement liabilities		13,437			23,828
Liabilities from risk management and trading activities		36,114			172,639
Other		23,218			300
Total deferred credits and other		92,351			239,092
Common Stock Equity
Common stock		2,587,201			2,539,233
Accumulated other comprehensive income		17,512			71,830
Retained earnings		895,284			760,809
Total common stock equity		3,499,997			3,371,872
Total Liabilities and Common Stock Equity	$	3,974,756		$	4,392,375

144

PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENT OF CASH FLOWS
(in thousands)

	Year Ended December 31
	2006			2005			2004
Cash flows from operating activities
Net Income	$	327,255		$	176,267		$	243,195
Less: equity in earnings of subsidiaries – net		(324,504	)		(58,759	)		(240,732	)
Net income attributable to Pinnacle West		2,751			117,508			2,463
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		470			551			5,693
Deferred income taxes		30,384			(19,929	)		4,449
Change in mark-to-market valuations		21,698			(15,162	)		(3,107	)
Customer and other receivables		2,816			1,730			94,067
Accounts payable		(55,675	)		43,969			8,345
Accrued taxes		(49,529	)		(84,758	)		17,698
Change in risk management and trading – net		65,633			(82,650	)		8,435
Other net		(20,746	)		102,432			(24,410	)
Net cash flow (used for) provided by operating activities		(2,198	)		63,691			113,633
Cash flows from investing activities
Investments in and advances to subsidiaries – net		(4,677	)		(230,229	)		(324,017	)
Repayments and advances of loans from subsidiaries		2,686			2,402			330,161
Dividends received from subsidiaries		180,000			220,000			255,000
Purchases of investment securities		(147,501	)		(1,485,655	)		(169,145	)
Proceeds from sale of investment securities		147,501			1,485,683			191,145
Other		—			—			(1,336	)
Net cash flow (used for) provided by investing activities		178,009			(7,799	)		281,808
Cash flows from financing activities
Issuance of long-term debt		175,000			—			—
Short-term borrowings and payments – net		27,900			—			—
Dividends paid on common stock		(201,221	)		(186,677	)		(166,772	)
Repayment of long-term debt		(298,687	)		(165,104	)		(215,854	)
Common stock equity issuance		35,834			290,542			—
Other		—			—			18,181
Net cash flow (used for) by financing activities		(261,174	)		(61,239	)		(364,445	)
Net increase (decrease) in cash and cash equivalents		(85,363	)		(5,347	)		30,996
Cash and cash equivalents at beginning of year		85,374			90,721			59,725
Cash and cash equivalents at end of year	$	11		$	85,374		$	90,721

145

PINNACLE WEST CAPITAL CORPORATION

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:
2006	$	4,979	$	4,096	$	—	$	3,478	$	5,597
2005		4,896		2,638		—		2,555		4,979
2004		9,223		2,868		—		7,195		4,896

146

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:
2006	$	3,568	$	4,096	$	—	$	3,441	$	4,223
2005		3,444		2,638		—		2,514		3,568
2004		3,743		2,446		—		2,745		3,444

147

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, 2006. 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, 2006. 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 69 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 127 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 70 of this report and “Report of Independent Registered Public Accounting Firm” on page 128 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

148

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, 2006 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

     None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE
OFFICERS AND CORPORATE GOVERNANCE OF PINNACLE WEST

     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance,” “Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting Compliance” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 23, 2007 (the “2007 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?” and “Executive Compensation” in the 2007 Proxy Statement.

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

     Reference is hereby made to “Shares of Pinnacle West Stock Owned by Management and Large Shareholders” and to “Approval of the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan – Equity Compensation Plan Information” in the 2007 Proxy Statement.

149

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance” and to “Related Party Transactions” in the 2007 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 2006?” and “– What are the Audit Committee’s pre-approval policies?” in the 2007 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	2005		2006
Audit Fees (1)	$	2,167,319	$	1,925,550
Audit-Related Fees (2)		33,899		167,912
Tax Fees (3)		1,025		17,096

(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 employee benefit plan audits in 2006.
(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.

150

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statements and Financial Statement Schedules

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

Exhibits Filed

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

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
3.1	Pinnacle West	Articles of Incorporation, restated as of July 29, 1988	19.1 to Pinnacle West’s September 30, 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
4.1	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

151

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
4.2	Pinnacle West APS	Indenture dated as of January 1, 1995 among APS and The Bank of New York, 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
4.3	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
4.4	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
4.5	Pinnacle West APS	First Supplemental Indenture dated as of November 15, 1996	4.6 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473	11-22-96
4.6	Pinnacle West APS	Second Supplemental Indenture dated as of April 1, 1997	4.10 to APS’ Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report, File No. 1-4473	4-9-97
4.7	Pinnacle West APS	Third Supplemental Indenture dated as of November 1, 2002	10.2 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962	5-15-03
4.8	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. 333-52476	12-21-00

152

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
4.9	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
4.10	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
4.11	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. 333-52476	12-21-00
4.12	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
4.13	Pinnacle West	Agreement, dated March 29, 1988, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets	4.1 to Pinnacle West’s 1987 Form 10-K Report, File No. 1-8962	3-30-88
4.14	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

153

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
4.15	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
4.16	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
4.17	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
4.18	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
4.19	Pinnacle West APS	Fifth Supplemental Indenture dated as of October 1, 2001	4.1 to APS’ September 30, 2001 Form 10-Q, File No. 1-4473	11-6-01
4.20	Pinnacle West APS	Sixth Supplemental Indenture dated as of March 1, 2002	4.1 to APS’ Registration Statement Nos. 333-63994 and 333-83398 by means of February 26, 2002 Form 8-K Report, File No. 1-4473	2-28-02
4.21	Pinnacle West APS	Seventh Supplemental Indenture dated as of May 1, 2003	4.1 to APS’ Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report, File No. 1-4473	5-9-03

154

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
4.22	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
4.23	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
4.24	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
4.25	Pinnacle West	Amendment to Rights Agreement, effective as of January 1, 2002	4.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	5-15-02
4.26	Pinnacle West	Second Amended and Restated Investor’s Advantage Plan dated as of June 23, 2004	4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962	8-9-04

155

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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	10.6A 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	10.7A 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	Filed
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 30, 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	Filed
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 30, 1996 Form 10-Q Report, File No. 1-4473	8-9-96

158

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 31, 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 31, 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 31, 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 30, 1991 Form 10-Q Report, File No. 1-4473	8-8-91

159

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 30, 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	Filed
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	Filed
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	Filed
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 31, 1991 Form 10-Q Report, File No. 1-4473	5-15-91

163

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 30, 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 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	12-4-86

164

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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	Filed
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	10.48b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
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	10.14A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

166

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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	10.15A 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 30, 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 Directors’ Deferred Compensation Plan, effective as of January 1, 1993	10.2A to APS’ 1993 Form 10-K Report, File No. 1-4473	3-30-94
10.53b	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 30, 1994 Form 10-Q Report, File No. 1-4473	11-10-94
10.54b	Pinnacle West APS	Fourth Amendment to the Arizona Public Service Company Directors Deferred Compensation Plan, effective as of January 1, 1999	10.8A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

167

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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	10.3A 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 30, 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	10.3A 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	10.8A to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962	3-14-01

168

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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	10.10A to APS’ 1995 Form 10-K Report, File No. 1-4473	3-29-96
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	10.7A 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	10.10A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

169

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 31, 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	10.64 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.65b	Pinnacle West APS	Schedules of William J. Post and Jack E. Davis to Arizona Public Service Company Deferred Compensation Plan, as amended	10.3A to Pinnacle West 2002 Form 10-K Report, File No. 1-8962	3-31-03
10.66b	Pinnacle West APS	Letter Agreement dated July 28, 1995 between Arizona Public Service Company and Armando B. Flores	10.16A 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	10.6A to APS’ 1994 Form 10-K Report, File No. 1-4473	3-30-95

170

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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
10.69b	Pinnacle West APS	Letter Agreement dated October 3, 1997 between APS and William L. Stewart	10.2 to APS’ September 30, 1997 Form 10-Q Report, File No. 1-4473	11-12-97
10.70b	Pinnacle West APS	Letter Agreement dated December 13, 1999 between APS and William L. Stewart	10.9A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00
10.71b	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 30, 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	10.17A 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 31, 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 31, 2003 Form 10-Q Report, File No. 1-8962	5-15-03
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 September 30, 2002 Form 10-Q Report, File No. 1-8962	11-14-02

171

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 30, 2004 Form 10-Q Report, File No. 1-8962	11-8-04
10.75.2b	Pinnacle West APS	Second 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	10.4A 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	10.77 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.78b	APS	Letter Agreement dated December 20, 2006 between APS and Randall K. Edington
10.79b	Pinnacle West APS	Pinnacle West Capital Corporation 1994 Long- Term Incentive Plan, effective as of March 23, 1994	Appendix A to the Proxy Statement for the Plan Report for Pinnacle West’s 1994 Annual Meeting of Shareholders, File No. 1-8962	4-15-94
10.80b	Pinnacle West APS	First Amendment dated December 7, 1999 to the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan	10.12A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	3-30-00

172

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.81b	Pinnacle West APS	Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.5A to Pinnacle West’s 2002 Form 10-K Report	3-31-03
10.82b	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
10.83	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
10.84	Pinnacle West APS	Territorial Agreement between APS and Salt River Project	10.1 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473	5-15-98
10.85	Pinnacle West APS	Power Coordination Agreement between APS and Salt River Project	10.2 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473	5-15-98
10.86	Pinnacle West APS	Memorandum of Agreement between APS and Salt River Project	10.3 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473	5-15-98
10.87	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

173

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	12-15-05
10.89 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
10.90d	Pinnacle West APS	Performance Accelerated Stock Option Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.98 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-16-05
10.91bd	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
10.92 bd	Pinnacle West APS	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	10.91 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.93 bd	Pinnacle West APS	Summary of 2006 CEO Variable Incentive Plan and Officer Variable Incentive Plan	10.92 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06

174

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.94	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
10.95	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
10.96	Pinnacle West APS	Amended and Restated Five-Year Credit Agreement dated as of December 9, 2005 between APS, as Borrower, Citibank, N.A., as Agent, and the lenders and other parties thereto	10.95 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.97	Pinnacle West	$200,000,000 Senior Notes Uncommitted Master Shelf Agreement dated as of February 28, 2006	10.96 to Pinnacle West 2005 Form 10-K Report, File No. 1-8962	3-13-06

175

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.98	Pinnacle West	Amended and Restated Credit Agreement dated as of December 9, 2005 among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Agent, and the other agent parties thereto	10.97 to Pinnacle West 2005 Form 10-K Report, File No. 1-8962	3-13-06
10.99	Pinnacle West	First Amendment to Amended and Restated Credit Agreement, dated as of May 15, 2006, supplementing and amending the Amended and Restated Credit Agreement, dated as of December 9, 2005, among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A. as Agent and the other parties thereto	10.1 to Pinnacle West’s June 30, 2006 Form 10-Q Report, File No. 1-8962	8-8-06
10.100	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

176

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.101	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
10.102	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
10.103	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
10.104	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
10.104.1	Pinnacle West APS	Amendment to Asset Purchase Agreement dated as of December 14, 2004 between PPL Sundance Energy, LLC and APS	99.1 to Pinnacle West’s November 18, 2004 Form 8-K Report, File No. 1-8962	12-20-04
10.105	Pinnacle West APS	Credit Agreement dated as of October 19, 2004 among Pinnacle West, other lenders, and JPMorgan Chase Bank, as Administrative Agent	10.1 to Pinnacle West’s September 30, 2004 Form 10-Q Report, File No. 1-8962	11-8-04

177

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.106b	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
10.107	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
10.108	Pinnacle West APS	Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996; Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998	10.107 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06

178

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
10.109	Pinnacle West APS	Navajo Project Participation Agreement dated as of September 30, 1969, and Amendment and Supplement No. 1 dated as of January 16, 1970, and Coordinating Committee Agreement No. 1 dated as of September 30, 1971	10.108 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	3-13-06
10.110	APS	$500,000,000 Five-Year Credit Agreement dated as of September 29, 2006 among Arizona Public Service Company as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, The Bank of New York as Syndication Agent and Issuing Bank and the other parties thereto	10.1 to APS’ September 2006 Form 10-Q Report, File No. 1-4473	11-8-06
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

179

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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

180

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Pinnacle West APS	Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	4.2 to APS’ 1992 Form 10-K Report, File No. 1-4473	3-30-93
99.2	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

181

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 30, 1992 Form 10-Q Report, File No. 1-4473	11-9-92
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 30, 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8, File No. 1-4473	12-4-86

182

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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
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

183

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	12-4-86
99.8c	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

184

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 30, 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8, File No. 1-4473	12-4-86
99.11c	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 30, 1992 Form 10-Q Report, File No. 1-4473	11-9-92

185

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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

186

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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

187

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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

188

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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
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 30, 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 31, 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
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 31, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473	5-9-05

189

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 30, 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 30, 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
99.29	Pinnacle West	Non-GAAP Financial Measure Reconciliation – Operating Income (GAAP measure) to Gross Margin (non-GAAP financial measure)

190

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit:a	Filed
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 15(b) of Form 10-K.
c	An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.
d	Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.

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: February 28, 2007	/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(William J. Post, Chairman of the Board of Directors and Chief Executive Officer)	Principal Executive Officer and Director	February 28, 2007
/s/ Jack E. Davis(Jack E. Davis, President and Chief Operating Officer)	Director	February 28, 2007
/s/ Donald E. Brandt(Donald E. Brandt, Executive Vice President and Chief Financial Officer)	Principal Accounting Officer and Principal Financial Officer	February 28, 2007

192

Signature	Title	Date
/s/ Edward N. Basha, Jr.(Edward N. Basha, Jr.)	Director	February 28, 2007
/s/ Michael L. Gallagher(Michael L. Gallagher)	Director	February 28, 2007
/s/ Pamela Grant(Pamela Grant)	Director	February 28, 2007
/s/ Roy A. Herberger, Jr.(Roy A. Herberger, Jr.)	Director	February 28, 2007
/s/ Martha O. Hesse(Martha O. Hesse)	Director	February 28, 2007
/s/ William S. Jamieson, Jr.(William S. Jamieson, Jr.)	Director	February 28, 2007
/s/ Humberto S. Lopez(Humberto S. Lopez)	Director	February 28, 2007
/s/ Kathryn L. Munro(Kathryn L. Munro)	Director	February 28, 2007
/s/ Bruce J. Nordstrom(Bruce J. Nordstrom)	Director	February 28, 2007
/s/ William L. Stewart(William L. Stewart)	Director	February 28, 2007

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: February 28, 2007	/s/ Jack E. Davis
	(Jack E. Davis, 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(William J. Post, Chairman of the Board of Directors )	Director	February 28, 2007
/s/ Jack E. Davis(Jack E. Davis, Chief Executive Officer)	Principal Executive Officer and Director	February 28, 2007
/s/ Donald E. Brandt(Donald E. Brandt, President and Chief Financial Officer)	Principal Financial Officer	February 28, 2007
/s/ Chris N. Froggatt(Chris N. Froggatt, Vice President and Controller)	Principal Accounting Officer	February 28, 2007

194

Signature	Title	Date
/s/ Edward N. Basha, Jr.(Edward N. Basha, Jr.)	Director	February 28, 2007
/s/ Michael L. Gallagher(Michael L. Gallagher)	Director	February 28, 2007
/s/ Pamela Grant(Pamela Grant)	Director	February 28, 2007
/s/ Roy A. Herberger, Jr.(Roy A. Herberger, Jr.)	Director	February 28, 2007
/s/ Martha O. Hesse(Martha O. Hesse)	Director	February 28, 2007
/s/ William S. Jamieson, Jr.(William S. Jamieson, Jr.)	Director	February 28, 2007
/s/ Humberto S. Lopez(Humberto S. Lopez)	Director	February 28, 2007
/s/ Kathryn L. Munro(Kathryn L. Munro)	Director	February 28, 2007
/s/ Bruce J. Nordstrom(Bruce J. Nordstrom)	Director	February 28, 2007
/s/ William L. Stewart(William L. Stewart)	Director	February 28, 2007

195

EXHIBIT INDEX

Exhibit
No.	Registrant(s)	Description
10.78a	APS	Letter Agreement dated December 20, 2006 between APS and Randall K. Edington
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 Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K.