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

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		Yes þ		No o
ARIZONA PUBLIC SERVICE COMPANY		Yes o		No þ

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

PINNACLE WEST CAPITAL CORPORATION		Yes o		No þ
ARIZONA PUBLIC SERVICE COMPANY		Yes o		No þ

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

PINNACLE WEST CAPITAL CORPORATION		Yes þ		No o
ARIZONA PUBLIC SERVICE COMPANY		Yes þ		No o

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

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 filer þ           Accelerated filer o          Non-accelerated filer o

ARIZONA PUBLIC SERVICE COMPANY

     Large accelerated filer o           Accelerated filer o          Non-accelerated filer þ

     Indicate by check mark whether each registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes o    No þ

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

PINNACLE WEST CAPITAL CORPORATION		$3,946,188,585 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

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

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

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:

	•		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

			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

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

     Cholla Cholla 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

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 Corners Four 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 Station The 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 Cycle Palo 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

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 Disposal See “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):

		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 Rules On 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

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.

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

     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.

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

     Navajo Nation Environmental Issues

     Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. 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

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

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.

     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.

     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’

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.

     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

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;

	•		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

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.

•

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.

     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.

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.

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.

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.

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.

APS Service Territory Map

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.

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

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.

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.

     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

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

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

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.

     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

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

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.

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);

	•		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:

	•		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.

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	)

     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.

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

     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

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

     Off-Balance Sheet Arrangements

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

     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under 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

     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%.

     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

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

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.

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

     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):

		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

     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.

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

     General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. For the years 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 Proceedings The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC, 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

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 Costs Fuel 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 Growth The 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.

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

     Wholesale Market Conditions The 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 Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher-trending pension and other postretirement benefit costs and other factors.

     Depreciation and Amortization Expenses Depreciation 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 Taxes Taxes 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 Expense Interest 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 Competition Although 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.

     Subsidiaries SunCor’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.

     General Our 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.

     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