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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, 2007
OR
 	 	 	
o	 	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the transition period from                      to                     
 	 	 	 	 	
Commission	 	Registrants; State of Incorporation;	 	IRS Employer	
File Number	 	Addresses; and Telephone Number	 	Identification No.	
1-8962	 	PINNACLE WEST CAPITAL CORPORATION	 	86-0512431	
 	 	(An Arizona corporation)	 	 	
 	 	400 North Fifth Street, P.O. Box 53999	 	 	
 	 	Phoenix, Arizona 85072-3999	 	 	
 	 	(602) 250-1000	 	 	
1-4473	 	ARIZONA PUBLIC SERVICE COMPANY	 	86-0011170	
 	 	(An Arizona corporation)	 	 	
 	 	400 North Fifth Street, P.O. Box 53999	 	 	
 	 	Phoenix, Arizona 85072-3999	 	 	
 	 	(602) 250-1000	 	 	
 	 	 	 	 	
Securities registered pursuant to Section 12(b) of the Act:	
 	
 	 	Title Of Each Class	 	Name Of Each Exchange On Which Registered	
PINNACLE WEST CAPITAL CORPORATION	 	Common Stock,	 	New York Stock Exchange	
 	 	No Par Value	 	 	
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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
PINNACLE WEST CAPITAL CORPORATION

Large accelerated filer þ	 	Accelerated filer o	 	Non-accelerated filer o	 	Smaller reporting company o	
 	 	 	 	(Do not check if a smaller reporting company)	 	 	
ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer o	 	Accelerated filer o	 	Non-accelerated filer þ	 	Smaller reporting company o	
 	 	 	 	(Do not check if a smaller reporting company)	 	 	
     Indicate by check mark whether each registrant is a shell company (as defined in 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	 	$3,979,906,800 as of June 30, 2007	
ARIZONA PUBLIC SERVICE COMPANY	 	$0 as of June 30, 2007	
     The number of shares outstanding of each registrant’s common stock as of February 21, 2008
 	 	 	
PINNACLE WEST CAPITAL CORPORATION	 	100,499,104 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 21, 2008 are incorporated by reference into Part III hereof.
 
      Arizona Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.
     This combined Form 10-K is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 10-K that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

   

 

TABLE OF CONTENTS
 	 	 	 	 	
 	 	Page	 	
GLOSSARY	 	 	1	 	
 	 	 	 	 	
PART I	 	 	3	 	
Item 1. Business	 	 	3	 	
Item 1A. Risk Factors	 	 	21	 	
Item 1B. Unresolved Staff Comments	 	 	28	 	
Item 2. Properties	 	 	29	 	
Item 3. Legal Proceedings	 	 	31	 	
Item 4. Submission of Matters to a Vote of Security Holders	 	 	31	 	
Supplemental Item	 	 	 	 	
Executive Officers of Pinnacle West	 	 	32	 	
 	 	 	 	 	
PART II	 	 	35	 	
Item 5. Market for Registrants’ Common Equity, Pinnacle West Related Stockholder Matters and Issuer Purchases of Equity Securities	 	 	35	 	
Item 6. Selected Financial Data	 	 	37	 	
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	39	 	
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	 	 	72	 	
Item 8. Financial Statements and Supplementary Data	 	 	73	 	
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	 	 	151	 	
Item 9A. Controls and Procedures	 	 	151	 	
Item 9B. Other Information	 	 	152	 	
 	 	 	 	 	
PART III	 	 	152	 	
Item 10. Directors, Executive Officers and Corporate Governance of Pinnacle West	 	 	152	 	
Item 11. Executive Compensation	 	 	152	 	
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	 	 	152	 	
Item 13. Certain Relationships and Related Transactions, and Director Independence	 	 	154	 	
Item 14. Principal Accountant Fees and Services	 	 	154	 	
 	 	 	 	 	
PART IV	 	 	156	 	
Item 15. Exhibits and Financial Statement Schedules	 	 	156	 	
 	 	 	 	 	
SIGNATURES	 	 	197	 	
  EX-10.1.2H	
  EX-10.6.5	
  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	
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GLOSSARY
ACC – Arizona Corporation Commission
ADEQ – Arizona Department of Environmental Quality
AFUDC – Allowance for Funds Used During Construction
ALJ – Administrative Law Judge
ANPP – Arizona Nuclear Power Project, also known as Palo Verde
APS – Arizona Public Service Company, a subsidiary of the Company
APSES – APS Energy Services Company, Inc., a subsidiary of the Company
Base Fuel Rate – the portion of APS’ retail base rates attributable to fuel and purchased power costs
Cholla – Cholla Power Plant
Clean Air Act – Clean Air Act, as amended
Company – Pinnacle West Capital Corporation
DOE – United States Department of Energy
EITF – FASB’s Emerging Issues Task Force
El Dorado – El Dorado Investment Company, a subsidiary of the Company
EPA – United States Environmental Protection Agency
ERMC – Energy Risk Management Committee
FASB – Financial Accounting Standards Board
FERC – United States Federal Energy Regulatory Commission
FIN – FASB Interpretation Number
FIP – Federal Implementation Plan
Fitch – Fitch, Inc.
Four Corners – Four Corners Power Plant
GAAP – accounting principles generally accepted in the United States of America
IRS – United States Internal Revenue Service
kW – kilowatt, one thousand watts
kWh – kilowatt-hour, one thousand watts per hour
Moody’s – Moody’s Investors Service
MW – megawatt, one million watts
MWh – megawatt-hour, one million watts per hour
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
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NPC – Nevada Power Company
NRC – United States Nuclear Regulatory Commission
OCI – other comprehensive income
Off-System Sales – sales of electricity from generation owned or contracted by the Company that is over and above the amount required to serve APS’ retail customers and traditional wholesale contracts
Palo Verde – Palo Verde Nuclear Generating Station
Pinnacle West – Pinnacle West Capital Corporation, the Company
Pinnacle West Energy (PWEC) – Pinnacle West Energy Corporation, a subsidiary of the Company, dissolved as of August 31, 2006
Pinnacle West Marketing & Trading – Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the Company
PRP – potentially responsible parties under Superfund
PSA – power supply adjustor approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate
PWEC Dedicated Assets – the following power plants, each of which was transferred by Pinnacle West Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3
Salt River Project – Salt River Project Agricultural Improvement and Power District
SEC – United States Securities and Exchange Commission
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
2005 Deferrals – PSA deferrals related to 2005 replacement power costs associated with Palo Verde outages
2006 Deferrals – PSA deferrals related to 2006 replacement power costs associated with outages or reduced power operations at Palo Verde
VIE – variable-interest entity
West Phoenix – West Phoenix Power Plant
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INTRODUCTION
Filing Format
     This Annual Report on Form 10-K is a combined report being filed by two separate registrants: Pinnacle West and APS. The information required with respect to each company is set forth within the applicable items.
     The Management’s Discussion and Analysis of Financial Condition and Results of Operations included under Item 7 of this report is divided into the following two sections:

 	•	 	Pinnacle West Consolidated —This section describes the financial condition and results of operations of Pinnacle West and its subsidiaries on a consolidated basis. It includes discussions of Pinnacle West’s regulated utility and non-utility operations. A substantial part of Pinnacle West’s revenues and earnings is derived from its regulated utility, APS.	
 		
 	•	 	APS —This section includes a detailed description of the results of operations and contractual obligations of APS.	
     Item 8 of this report includes Consolidated Financial Statements of Pinnacle West and Financial Statements of APS. Item 8 also includes Notes to Pinnacle West’s Consolidated Financial Statements, the majority of which also relates to APS, and Supplemental Notes to APS’ Financial Statements.
PART I
ITEM 1. BUSINESS
OVERVIEW
General
     Pinnacle West was incorporated in 1985 under the laws of the State of Arizona and owns all of the outstanding equity securities of APS, its major subsidiary. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona.
     Pinnacle West’s other principal subsidiary is SunCor, which is engaged in real estate development activities in the western United States. See “Business of SunCor Development Company” in this Item 1. Pinnacle West’s other first-tier subsidiaries, APSES, El Dorado and Pinnacle West Marketing & Trading are discussed in “Business of Other Subsidiaries” in this Item 1.
     Pinnacle West Energy, which owned and operated unregulated generating plants, transferred the PWEC Dedicated Assets to APS on July 29, 2005 and sold its 75% ownership interest in Silverhawk to NPC on January 10, 2006. As a result, Pinnacle West Energy no longer owned any generating plants and was dissolved as of August 31, 2006.
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Business Segments
     Pinnacle West has two principal business segments (determined by products, services and the regulatory environment):

 	•	 	the regulated electricity segment (accounting for 83% of operating revenues in 2007), which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities, and includes electricity generation, transmission and distribution; and	
 		
 	•	 	the real estate segment (accounting for 6% of operating revenues in 2007), which consists of SunCor’s real estate development and investment activities.	
     See Note 17 for financial information about the business segments.
APS ACC Proceedings
     The key issue affecting Pinnacle West’s and APS’ financial outlook is adequate and timely retail rate treatment by the ACC. Note 3 discusses the results of APS’ most recent retail rate case as well as other rate matters.
Employees
     At December 31, 2007, Pinnacle West employed approximately 7,600 people, including the employees of its subsidiaries. Of these employees, approximately 6,800 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;	
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 	•	 	Ethics Policy and Standards of Business Practices;	
 		
 	•	 	Director Independence Standards;	
 		
 	•	 	Executive Officer Stock Ownership Guidelines; and	
 		
 	•	 	Restricted Stock Retention Policy.	
 		
     Pinnacle West will post any amendments to the Code of Ethics and Ethics Policy and Standards of Business Practices, and any waivers that are required to be disclosed by the rules of either the SEC or the New York Stock Exchange, on its 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, particularly those affecting our rates and our recovery of fuel and purchased power costs;	
 		
 	•	 	the outcome of regulatory, legislative and judicial proceedings, both current and future, relating to the restructuring of the electric industry and environmental matters (including those related to climate change);	
 		
 	•	 	the ongoing restructuring of the electric industry, including decisions impacting wholesale competition and the introduction of retail electric competition in Arizona;	
 		
 	•	 	market prices for electricity and natural gas;	
 		
 	•	 	volatile market liquidity, any deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);	
 		
 	•	 	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 and Pacific Northwest energy situations, 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;	
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 	•	 	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);	
 		
 	•	 	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 or encumbrance of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates.
     APS is subject to varying degrees of competition from other investor-owned utilities in Arizona (such as Southwest Gas Corporation), as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet their own energy requirements.
     In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. As a result, as of January 1, 2001, all of APS’ retail customers were eligible to choose alternate energy suppliers. However, there are currently no active retail competitors offering unbundled energy or other utility services to APS’ customers. In 2000, an Arizona Superior Court found that the rules were in part unconstitutional and in other respects unlawful, the latter finding being primarily on procedural grounds, and invalidated all ACC orders authorizing competitive electric services providers to operate in Arizona. In 2004, the Arizona Court of Appeals invalidated some, but not all of the rules and upheld the invalidation of the orders authorizing competitive electric service providers. In 2005, the Arizona Supreme Court declined to review the Court of Appeals decision. To date, the ACC has taken no action on either the rules or the prior 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. However, the ACC has scheduled a hearing during the first quarter of 2008 to consider the new application of a competitive electric service provider for authority to provide competitive electric services. Certain intervenors in that proceeding have requested the ACC to dismiss the application because of, among other reasons, the legal uncertainties
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associated with the rules, as described above. The ACC has taken this motion to dismiss under advisement. APS cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
Wholesale
      General
     The FERC regulates rates for wholesale power sales and transmission services. See “Rate Requests for Transmission and Ancillary Services” in Note 3 for information regarding APS’ pending rate case at the FERC. During 2007, approximately 4.4% of APS’ electric operating revenues resulted from such sales and services. APS’ wholesale activity primarily consists of managing fuel and purchased power risks in connection with the costs of serving retail customer energy requirements. APS also sells, in the wholesale market, its generation output that is not needed for APS’ Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. Additionally, subject to specified parameters, APS markets, hedges and trades 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 1.1 million customers. APS does not distribute any products. During 2007, no single purchaser or user of energy accounted for more than 5.8% of electric revenues. See “Overview” and “Regulation and Competition” above for additional background information about APS.
     At December 31, 2007, APS employed approximately 6,800 people, including employees at jointly-owned generating facilities for which APS serves as the generating facility manager. APS’ principal executive offices are located at 400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-1000).
Portfolio Resources
     APS’ sources of energy during 2007 were: coal – 36.8%; purchased power – 23.3%; nuclear – 21.5%; and gas – 18.4%. In accordance with GAAP, a substantial portion of APS’ purchased power expense is netted against wholesale sales on the Consolidated Statements of Income. See Note 18. The disclosure below provides a more detailed description of each of APS’ current sources of energy.
      Generation Facilities
     APS’ portfolio of owned or leased generating capacity is provided in the table below:
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 	 	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	1	

Solar	 	 	       5,817	 	

Total	 	 	6,157,569	 	

			
1	 	As of January 26, 2008, nuclear capacity increased to 1,147,122 kW, reflecting completion of the steam generator replacement program.	
      Coal Fueled Generating Facilities
      Four Corners – Four Corners is a coal-fired power plant located in the northwestern corner of New Mexico. APS operates the plant and owns 100% of Four Corners Units 1, 2 and 3 and 15% of Units 4 and 5. APS purchases all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation. The Four Corners coal contract runs through 2016, with options on APS’ part to extend the contract for five to fifteen additional years. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” below for additional information.
      Cholla – Cholla is a coal-fired power plant located in northeastern Arizona. APS operates the plant and owns 100% of Cholla Units 1, 2 and 3. PacifiCorp owns Cholla Unit 4 and APS operates that unit for PacifiCorp. Cholla’s common facilities are jointly owned by APS and PacifiCorp. APS purchases most of Cholla’s coal requirements from coal suppliers that mine all of the coal under long-term leases of coal reserves with the Navajo Nation, the federal government and private landholders. There are currently two coal contracts in place with two separate suppliers for Cholla. One supplier is ramping down its supply to the plant, which will be complete in 2009, and the other is ramping up its supply to the plant to provide Cholla’s full coal requirement by 2010. This agreement runs through 2024. Additionally, APS may purchase a portion of Cholla’s coal requirements on the spot market to take advantage of competitive pricing options and to supplement coal required for increased operating capacity. APS believes that the current fuel contracts and
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competitive fuel supply options ensure the continued operation of Cholla for its useful life. In addition, APS has a long-term coal transportation contract.
      Navajo Generating Station – The Navajo Generating Station is a coal-fired power plant located in northern Arizona. Salt River Project operates the plant and APS owns a 14% interest in Navajo Units 1, 2 and 3. The Navajo Generating Station’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is under contract with its coal supplier through 2011, with options to extend through 2019. The Navajo Generating Station plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. See “Plant and Transmission Line Leases and Easements on Indian Lands” below for additional information.
     See “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 Note 11 for information regarding APS’ coal mine reclamation obligations.
      Natural Gas Fueled Generating Facilities
     APS has seven natural gas power plants located throughout Arizona, consisting of Redhawk, located near the Palo Verde Nuclear Generating Station; Ocotillo, located in Tempe; Sundance, located in Coolidge; West Phoenix, located in southwest Phoenix; Saguaro, located north of Tucson; Douglas, located in the town of Douglas; and Yucca, located near Yuma. APS owns and operates each plant with the exception of one combustion turbine unit and one steam unit at Yucca that are operated by APS and owned by the Imperial Irrigation District.
      Nuclear Generating Facility
      Palo Verde Nuclear Generating Station – Palo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. APS operates the plant and owns 29.1% of Palo Verde Units 1 and 3 and about 17% of Unit 2. In addition, APS leases about 12.1% of Unit 2, resulting in a 29.1% combined interest in that Unit. See “Palo Verde Leases” below for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.
      Palo Verde Fuel Cycle – The fuel cycle for Palo Verde is comprised of the following stages:

 	•	 	mining and milling of uranium ore to produce uranium concentrates;	
 		
 	•	 	conversion of uranium concentrates to uranium hexafluoride;	
 		
 	•	 	enrichment of uranium hexafluoride;	
 		
 	•	 	fabrication of fuel assemblies;	
 		
 	•	 	utilization of fuel assemblies in reactors; and	
 		
 	•	 	storage and disposal of spent nuclear fuel.	
     The Palo Verde participants are continually identifying their future resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates and conversion services through 2008 and for approximately 50% of uranium concentrates and conversion services in 2009. The participants have
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also contracted for all of Palo Verde’s enrichment services through 2013 and all of Palo Verde’s fuel assembly fabrication services until at least 2015.
      Spent Nuclear Fuel and Waste Disposal – See “Palo Verde Nuclear Generating Station” in Note 11 for a discussion of spent nuclear fuel and waste disposal.
      Palo Verde Leases – In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases and to purchase the property for fair market value at the end of the lease terms. See Notes 9 and 20 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.
      Regulatory – Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period of approximately 40 years, authorize APS, as operating agent for Palo Verde, to operate the three Palo Verde units at full power.
      NRC Inspection – In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 generator started, but did not provide electrical output during routine inspections on July 25 and September 22, 2006. On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) for this matter. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), which has resulted in an enhanced NRC inspection regime. Although only Palo Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need for improvements, APS’ management has been conducting site-wide assessments of equipment and operations.
     Preliminary work in support of the NRC’s enhanced inspection regime took place throughout the summer of 2007. On June 21, 2007, the NRC issued an initial confirmatory action letter confirming APS’ commitments regarding specific actions APS will take to improve Palo Verde’s performance. From October 1, 2007 through November 2, 2007, a team of NRC inspectors performed on-site in-depth inspections of Palo Verde’s equipment and operations. The NRC’s inspection results were presented at a public meeting on December 19, 2007, and documented in an NRC letter to APS dated February 1, 2008 (the “Inspection Report”). The Inspection Report indicated that the facility is being operated safely, but also identified certain performance deficiencies. On December 31, 2007, APS submitted its improvement plan to the NRC, which addresses issues identified by APS’ management during its site-wide assessments of equipment and operations that occurred during 2007. The NRC reviewed the adequacy of this improvement plan and issued a revised confirmatory action letter on February 15, 2008 that outlines the actions APS must take in order for the NRC to return the Palo Verde site to the NRC’s routine inspection and assessment process. This revised confirmatory action letter was anticipated as part of the NRC’s inspection procedure and a substantial majority of the actions required therein were contained in APS’ improvement plan. In March 2008, APS intends to submit to the NRC a revision to its improvement plan to address issues raised by the NRC in its Inspection Report. The NRC will continue to provide increased oversight at Palo Verde until the facility demonstrates sustained performance improvement. APS will continue cooperating fully with the NRC throughout this process.
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      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 for additional information about APS’ nuclear decommissioning costs.
      Palo Verde Liability and Insurance Matters – See “Palo Verde Nuclear Generating Station” in Note 11 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde.
      Alternative Generation Sources
     In connection with its ongoing resource planning efforts, APS continues to focus on increasing the percentage of its energy that is produced by renewable resources. On November 1, 2006, the ACC approved the Arizona Renewable Energy Standard and Tariff (the “Renewable Energy Standard”). Under the Renewable Energy Standard, covered utilities like APS must supply an increasing percentage of their retail electric energy sales from renewable resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable energy requirement increases from 1.5% in 2007 to 15% in 2025. In addition, an increasing percentage of that requirement must be supplied from distributed resources (generally speaking, small-scale renewable technologies that are located on customers’ properties) to increase system reliability. The distributed resource requirement increases from 5% of the overall renewable energy requirement in 2007 to 30% in 2012 and subsequent years. APS currently has a diverse portfolio of renewable resources including wind from New Mexico, geothermal from California and Utah, and solar and biomass in Arizona, which collectively will generate over 120 MW of renewable energy for our customers.
     On February 8, 2008, APS entered into a Renewable Energy Purchase and Sale Agreement under which APS agreed to purchase the energy and related renewable energy credits from a solar power plant for a period of thirty years after the plant begins commercial operation. The plant, which will have a nameplate rating of 280 MW and a projected annual output of 900,000 MWh, will be located near Gila Bend, Arizona, about 70 miles southwest of Phoenix, Arizona. The agreement is subject to various conditions, including ACC approval. If these conditions are met, commercial operation is expected during 2011.
     APS continues to actively consider opportunities to enhance its renewable energy portfolio, both to ensure its compliance with the Renewable Energy Standard and to meet the needs of its customer base.
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      Purchased Power Agreements
     In addition to its own available generating capacity, APS purchases electricity under various arrangements. APS’ purchased power capacity under long-term contracts, as of December 31, 2007, is summarized in the table below, and does not include the recently-executed solar agreement described under “Alternative Generation Sources.” APS also purchases power through short-term markets to supplement its long-term resources and hedge its energy requirements.
 	 	 	 	 	 	 	
 	 	 	 	Capacity	
Purchased Power Agreement	 	Dates Available	 	(MW)	
Purchase Agreement (a)	 	Year-round through June 15, 2010	 	 	234	 	
Exchange Agreement (b)	 	May 15 to September 15 annually through 2020	 	 	480	 	
Tolling Agreement	 	June 2007 through May 2017	 	 	510	 	
Tolling Agreement	 	June 2010 through October 2019	 	 	560	 	
Day-Ahead Call Option Agreement	 	June 2007 through September 2015 (summer seasons)	 	 	500	 	
Day-Ahead Call Option Agreement	 	June 2007 through summer 2016	 	 	150	 	
Wind Agreement	 	December 2006 through December 2026	 	 	90	 	
Geothermal Agreement	 	January 2006 through 2029	 	 	10	 	
Landfill Gas Agreement	 	Deliveries expected to commence in 2008; expires 2028	 	 	3	 	
Biomass Agreement	 	Deliveries expected to commence in 2008; expires 2022	 	 	14	 	

(a)	 	The amount of electricity available to APS under this agreement is based in large part on customer demand and is adjusted annually. Effective June 16, 2007, the seller, Salt River Project, reduced the capacity available to APS by 150 MW. Additionally, Salt River Project has elected to cancel this contract effective June 15, 2010.	
 		
(b)	 	This is a seasonal capacity exchange agreement with PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and APS returns 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 2007, APS received 571,342 MWh of energy under the capacity exchange. Additionally, under a supplemental energy sales agreement, APS must also make additional offers of energy to PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2007, PacifiCorp received offers of 1,093,175 MWh and purchased 174,340 MWh.	
     APS continually assesses its need for additional capacity resources to assure system reliability. APS remains committed to seeking proposals from the competitive wholesale market for filling its future resource needs, including renewable resource capacity.
      Reserve Margin
     APS’ 2007 peak one-hour demand on its electric system was recorded on August 13, 2007 at 7,545,100 kW, compared with the 2006 peak of 7,652,000 kW recorded on July 21, 2006. Taking into account additional capacity then available to APS under long-term purchased power contracts as well as APS generating capacity, APS had capacity of 6,783,000 kW to meet system demand on August 13, 2007, for an installed reserve margin of negative 11.3%. The power actually available to
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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 2007 peak amounted to 5,839,000 kW, for a margin of a negative 33.5%. Firm purchases totaling 3,484,000 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 10.1%.
Transmission and Distribution Facilities
     APS’ transmission facilities consist of approximately 5,759 pole miles of overhead lines and approximately 45 miles of underground lines, 5,535 miles of which are located in Arizona. APS’ distribution facilities consist of approximately 12,471 miles of overhead lines and approximately 16,210 miles of underground primary cable, all of which are located in Arizona. APS shares ownership of some of its transmission facilities with other companies. The following table shows APS’ jointly-owned interests in those transmission facilities recorded on the Consolidated Balance Sheets at December 31, 2007:
 	 	 	 	 	
 	 	Percent Owned	
 	 	(Weighted Average)	
Harquahala	 	 	80.0	%	
Palo Verde – Estrella 500KV System	 	 	55.5	%	
ANPP500KV System	 	 	35.8	%	
Navajo Southern System	 	 	31.4	%	
Four Corners Switchyards	 	 	27.5	%	
Palo Verde – Yuma 500KV System	 	 	23.9	%	
Phoenix – Mead System	 	 	17.1	%	
Plant and Transmission Line Leases and Easements on Indian Lands
     The Navajo Generating Station and Four Corners are located on land held under leases from the Navajo Nation and also under easements from the federal government. The easement and lease for the Navajo Generating Station expire in 2019 and the easement and lease for Four Corners expire in 2016. Each of the leases contains an option to extend for an additional 25-year period from the end of the existing lease term, for a rental amount tied to the original rent payment adjusted based on an index. The easements do not contain an express renewal option and it is unclear what conditions to renewal or extension of the easements may be imposed. The ultimate cost of renewal of the Navajo Generating Station and Four Corners leases and easements is uncertain. As noted above under “Portfolio Resources — Coal Fueled Generating Facilities,” the coal contracted for use in these plants is also located on Indian reservations.
     Certain portions of the transmission lines that carry power from several of our power plants are located on Indian lands pursuant to easements or other rights-of-way that are effective for specified periods. Some of these rights-of-way have expired and our renewal applications have not yet been acted upon by the appropriate Indian tribes. Other rights expire at various times in the future and will have to be acted on for renewal by the applicable tribe at that time. The majority of our transmission lines residing on Indian lands are on the Navajo Nation. The Four Corners and Navajo Generating Station plant leases provide Navajo Nation consent to certain of the rights-of-way for transmission lines related to those plants at a specified rental rate for the original term of the
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rights-of-way and for a like payment in any renewal period. In addition, a 1985 amendment to the leases provides a formula for calculating payments for certain new and renewal rights-of-way. However, some of our rights-of-way are not covered by the leases, or are granted by other Indian tribes. In recent negotiations with other utilities or companies for renewal of similar rights-of-way, certain of the affected Indian tribes have required payments substantially in excess of amounts that we have paid in the past for such rights-of-way or that are typical for similar permits across non-Indian lands; however, we are unaware of the underlying agreements and/or specific circumstances surrounding these renewals. The ultimate cost of renewal of the rights-of-way for our transmission lines is uncertain. We are monitoring these rights-of-way and easement issues and are currently unable to predict the outcome of this matter.
Construction Program
     During the years 2005 through 2007, APS incurred approximately $2.4 billion in capital expenditures. APS’ capital expenditures for the years 2008 through 2010 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 $900 million in 2007. APS’ capital expenditures, including expenditures for environmental control facilities, for the years 2008 through 2010, have been estimated as follows (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Estimate	 	
 	 	2008	 	 	2009	 	 	2010	 	
Major facilities:	 	 	 	 	 	 	 	 	 	 	 	 	
Distribution	 	$	410	 	 	$	440	 	 	$	430	 	
Generation	 	 	380	 	 	 	390	 	 	 	380	 	
Transmission	 	 	220	 	 	 	320	 	 	 	290	 	
Other	 	 	50	 	 	 	40	 	 	 	50	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	$	1,060	 	 	$	1,190	 	 	$	1,150	 	
 	 	 	 	 	 	 	 	 	 	
     The above amounts do not include any impacts from the recent changes in the line extension policy (see Note 3). In addition, the amounts exclude capitalized interest costs and include capitalized property taxes. Nuclear fuel expenditures of approximately $90 million to $120 million per year are also included. As part of our planning and cost control process, APS conducts a continuing review of its construction program.
     See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 for additional information about APS’ construction program.
Environmental Matters
      EPA Environmental Regulation
      Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These regulations required states to submit state implementation plans (SIPs) by December 2007 to demonstrate “reasonable progress” towards achieving natural visibility conditions in certain “Class I Areas,” including several on the Colorado Plateau. SIPs are required to consider and potentially apply “best available retrofit technology” (BART) for certain older major stationary sources. The
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rules allow nine western states and Indian tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule.
     On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional haze rules by providing guidelines, known as the BART guidelines, for states to use in determining which facilities must install controls and the type of controls the facilities must use. The EPA also issued a Revised Annex Rule on October 13, 2006 to address a previous challenge and court remand of that rule.
     ADEQ is currently undertaking a rulemaking process to amend its SIP to reconcile it with the Revised Annex Rule and to implement the Clean Air Visibility Rule requirements. ADEQ’s Regional Haze SIPs were due to EPA Region 9 in December 2007, but are actually expected to be submitted during 2008. As part of the rulemaking process, ADEQ is requiring certain sources in the state to conduct BART analyses. Cholla and West Phoenix received letters from ADEQ asserting that the plants are potentially subject to BART and requesting that we either perform a BART analysis on each plant or provide information demonstrating that we are not subject to BART. We recently completed a BART analysis for Cholla and submitted our BART recommendations to ADEQ on February 4, 2008. ADEQ will now review our submission and determine what constitutes BART for Cholla. Our recommendations include the installation of certain pollution control equipment that we believe constitutes BART. Once we receive ADEQ’s final determination, we will have five years to complete the installation of the equipment and to achieve the emission limits established by ADEQ. However, in order to coordinate with the plant’s other scheduled activities, we are currently implementing our recommended plan for Cholla on a voluntary basis. Costs related to the implementation of our recommended plan are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in Item 7).
     Because we believed that ADEQ’s baseline modeling for West Phoenix may have contained some errors, we re-performed the baseline modeling using correct input and have determined that West Phoenix is not subject to BART. We submitted these findings for West Phoenix to ADEQ, and ADEQ has verbally informed us that West Phoenix is not subject to BART.
     In addition, EPA Region 9 requested us to perform a BART analysis for Four Corners. We recently completed the analysis and submitted it to the EPA on January 30, 2008. The EPA will now review our submission and determine what constitutes BART for Four Corners. Our recommendations include the installation of certain pollution control equipment that we believe constitutes BART. Once we receive the EPA’s final determination, we will have five years to complete the installation of the equipment and to achieve the emission limits established by EPA Region 9. Until the EPA makes a final determination on this matter, we cannot accurately estimate the expenditures that may be required. As a result, our current environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in Item 7) do not include amounts for Four Corners BART expenditures.
     While we continue to monitor this matter, at the present time we cannot predict whether the agencies will agree with our BART recommendations or, if the agencies disagree with our recommendations, the nature of the BART controls the agencies may ultimately mandate and the resulting financial or operational impact.
      Mercury On March 15, 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to control mercury emissions from coal-fired power plants. This rule establishes performance standards
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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.
     In November 2006, ADEQ submitted a SIP to the EPA to implement the CAMR. ADEQ’s SIP generally incorporates the EPA’s model cap-and-trade program, but it includes additional requirements, including the requirement to meet a 90% mercury removal control level or 0.0087 lbs/GWh, whichever is greater, the requirement to obtain mercury allowances at a 2:1 ratio for any emissions that fall below the specified control level, and the requirement, beginning in 2013, to consider clean coal technologies as part of permitting any new generation.
     On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR and the EPA rule that allowed for the creation of the CAMR. While we continue to monitor this matter, we cannot predict the timing of the court’s issuance of a mandate to vacate the rules, the response of ADEQ or the scope, timing or impact of any alternate rules that may be proposed to address mercury emissions.
     We have installed, and may continue to install, certain of the equipment necessary to meet these mercury standards. However, due to the recent U.S. Court of Appeals decision, we will monitor the type and timing of any necessary equipment installation. The estimated costs expected to be incurred over the next three years for such equipment are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Expenditures” in Item 7).
      Federal Implementation Plan In September 1999, the EPA proposed FIPs to set air quality standards at certain power plants, including Four Corners and the Navajo Generating Station. On September 12, 2006, the EPA proposed revised FIPs to establish air quality standards at both of these plants.
      Four Corners FIP
     On April 30, 2007, the EPA adopted a source specific FIP to set air quality standards at Four Corners. The FIP essentially federalizes the requirements contained in the New Mexico State Implementation Plan, which Four Corners has historically followed. The FIP also includes a requirement to maintain and enhance dust suppression methods. On July 2, 2007, APS filed a petition for review in the United States District Court of Appeals for the Tenth Circuit seeking revisions to the FIP to clarify certain requirements and allow operational flexibility. The Sierra Club has intervened in this action. On July 6, 2007, the Sierra Club and other parties filed a petition for review with the same court challenging the FIP’s compliance with the Clean Air Act and we have intervened in their action. In our lawsuit, we challenge two key provisions of the FIP: a 20% opacity limit on certain fugitive dust emissions, which the EPA filed a motion to remand and vacate in early December 2007, and a 20% stack opacity limit on Units 4 and 5. Briefing in this case is now complete, and the court is next expected to determine whether to hold oral arguments on the matter, as requested by the EPA. Although we cannot predict the outcome or the timing of these matters, we do not believe that they will have a material adverse impact on our financial position, results of operations or cash flows.
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      Navajo Generating Station FIP
     The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently predict the effect of this proposed FIP on its financial position, results of operations or cash flows, or whether the proposed FIP will be adopted in its current form.
      Superfund Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.
      Manufactured Gas Plant Sites APS is currently investigating properties, which it now owns or which were previously owned by it or its corporate predecessors, that were at one time sites of, or sites associated with, manufactured gas plants. APS is taking action to voluntarily remediate these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations, cash flows or liquidity.
      Navajo Nation Environmental Issues
     Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. See “Portfolio Resources – Coal Fueled Generating Facilities” above for additional information regarding these plants.
     In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those activities that occur at Four Corners and the Navajo Generating Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners and the Navajo Generating Station. The Court has stayed these proceedings pursuant to a request by the parties, and the parties are seeking to negotiate a settlement.
     In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. APS believes the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners and the Navajo Generating Station. On July 12, 2000, the Four Corners participants and the Navajo Generating Station participants each filed a petition with the Navajo Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the settlement negotiations mentioned above. APS cannot currently predict the outcome of this matter.
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     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.
Climate Change
     In 2007, six western states (Arizona, California, New Mexico, Oregon, Utah and Washington) and two Canadian provinces (British Columbia and Manitoba) entered into an accord, the Western Climate Initiative (the “Initiative”), to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. In August 2007, the Initiative participants set a goal of reducing greenhouse gas emissions 15% below 2005 levels by 2020. By August 2008, the Initiative participants intend to develop a plan for implementation of this goal. Any such implementation would require independent action by each individual state’s or province’s legislature or Governor to adopt a version of the plan. While we continue to monitor the impact of the Initiative, at the present time we cannot predict what form it will ultimately take, whether it will be implemented or, if it is implemented, what impact it will have on our operations.
     We are currently developing a Climate Management Report to comply with an ACC order in which the ACC directed APS to undertake a climate management plan, carbon emission reduction study and commitment and action plan with public input and ACC review. We expect to complete the report in 2008.
     In January 2008, APS joined the Climate Registry as a Founding Reporter. Founding Reporters are companies that voluntarily join the non-profit organization before May 2008 to measure and report greenhouse gas emissions in a common, accurate and transparent manner consistent across industry sectors and borders. Pinnacle West also makes available on its website ( www.pinnaclewest.com ) its annual Corporate Responsibility Report, which provides information related to the Company, its approach to sustainability and its workplace and environmental performance. The information on Pinnacle West’s website, including the Corporate Responsibility Report, is not incorporated by reference into this report.
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.
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APS is one of a number of parties in a proceeding, filed March 13, 1975, before the Eleventh Judicial District Court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.
     A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987, in an action pending in Maricopa County, Arizona, Superior Court. Palo Verde is located within the geographic area subject to the summons. APS’ rights and the rights of the other Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As operating agent of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Five of APS’ other power plants are also located within the geographic area subject to the summons. APS’ claims dispute the court’s jurisdiction over its groundwater rights with respect to these plants. Alternatively, APS seeks confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued a decision affirming the lower court’s criteria for resolving groundwater claims. Litigation on both of these issues has continued in the trial court. In December 2005, APS and other parties filed a petition with the Arizona Supreme Court requesting interlocutory review of a September 2005 trial court order regarding procedures for determining whether groundwater pumping is affecting surface water rights. The Court denied the petition in May 2007, and the trial court is now proceeding with implementation of its 2005 order. No trial date concerning APS’ water rights claims has been set in this matter.
     APS has also filed claims to water in the Little Colorado River Watershed in Arizona in an action pending in the Apache County, Arizona, Superior Court, which was originally filed on September 5, 1985. APS’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and, therefore, is potentially at issue in the case. APS’ claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. A number of parties are in the process of settlement negotiations with respect to certain claims in this matter. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’ water rights claims has been set in this matter.
     Although the above matters remain subject to further evaluation, 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 future operations of the plant. The effect of the drought cannot be fully assessed at this time, and APS cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from Four Corners.
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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 that, 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 this Act on our operations at this time.
BUSINESS OF SUNCOR DEVELOPMENT COMPANY
     SunCor was incorporated in 1965 under the laws of Arizona and is a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. The principal executive offices of SunCor are located at 80 East Rio Salado Parkway, Suite 410, Tempe, Arizona 85281 (telephone 480-317-6800). SunCor and its subsidiaries had approximately 650 employees at December 31, 2007.
     At December 31, 2007, SunCor had total assets of about $670 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, and mixed-use residential, commercial, office and industrial projects.
     SunCor projects include six master-planned communities and several commercial and residential projects. Four of the master-planned communities and the commercial and residential projects are in Arizona. Other master-planned communities are located in Idaho, New Mexico and Utah.
     SunCor’s operating revenues were approximately $215 million in 2007, $400 million in 2006 and $338 million in 2005. SunCor’s net income was approximately $24 million in 2007, $61 million in 2006 and $56 million in 2005. 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.
     See Note 6 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
     APSES was incorporated in 1998 under the laws of Arizona and provides energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation, and project management) and competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) to commercial and industrial retail customers in the western United States. Recently, APSES has de-emphasized its commodity-related energy services. APSES had approximately 60
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employees as of December 31, 2007. APSES’ principal offices are located at 400 East Van Buren Street, Phoenix, Arizona 85004 (telephone 602-250-5000).
     APSES had a net loss of $4 million in 2007, a net loss of $3 million in 2006 and a net loss of $6 million in 2005. At December 31, 2007, APSES had total assets of $95 million.
     El Dorado was incorporated in 1983 under the laws of Arizona. El Dorado owns minority interests in several energy-related investments and Arizona community-based ventures. El Dorado’s short-term goal is to prudently realize the value of its existing investments. On a long-term basis, Pinnacle West may use El Dorado, when appropriate, for investments that are strategic to the business of generating, distributing and marketing electricity. El Dorado’s offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-3517).
     El Dorado had a net loss of $6 million in 2007, a net loss of $4 million in 2006 and net income of $4 million in 2005. Income taxes related to El Dorado are recorded by Pinnacle West. At December 31, 2007, El Dorado had total assets of $30 million.
     Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006. Pinnacle West Marketing & Trading had a net loss of $11 million in 2007. At December 31, 2007, Pinnacle West Marketing & Trading had total assets of $73 million.
ITEM 1A. RISK FACTORS
     In addition to the factors affecting specific business operations identified in connection with the description of these operations contained elsewhere in this report, set forth below are risks and uncertainties that could affect our financial results. Unless otherwise indicated or the context otherwise requires, the following risks and uncertainties apply to Pinnacle West and its subsidiaries, including APS.
      APS is subject to comprehensive government regulation by several federal, state and local regulatory agencies that could have a material adverse impact on its business 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 and ancillary matters which are before or which may come 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
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conducted in accordance with applicable laws in all material respects. However, changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations. We are also unable to predict the impact on our business and operating results from pending or future regulatory activities of any of these agencies.
     The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose monetary civil penalties or a progressively increased inspection regime that could ultimately result in the shut down of a unit, or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. In early 2007, the NRC placed Palo Verde Unit 3 in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix (“Column 4”), which has resulted in an enhanced NRC inspection regime, including on-site in-depth inspections of Palo Verde equipment and operations. Although only Palo Verde Unit 3 is in NRC’s Column 4, in order to adequately assess the need for improvements, APS management has been conducting site-wide assessments of equipment and operations. APS continues to cooperate fully with the NRC throughout this process. The enhanced NRC inspection regime and APS’ ongoing commitment to the conservatively safe operation of Palo Verde could result in NRC action or an APS decision to shut down one or more units in the event of noncompliance with operating requirements or in light of other operational considerations.
      APS is subject to numerous environmental laws and regulations that may increase its cost of operations, impact its business plans, or expose it to environmental liabilities.
     APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions, water quality, wastewater discharges, solid waste, 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.
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      Concern over climate change could result in significant legislative and regulatory efforts to limit greenhouse gas emissions or related litigation, which may increase APS’ cost of operations.
     Concern over climate change, deemed by many to be induced by rising levels of greenhouse gases in the atmosphere, has led to significant legislative and regulatory efforts to limit CO 2 , which is a major byproduct of the combustion of fossil fuel, and other greenhouse gas emissions. In addition, lawsuits have been filed against companies that emit greenhouse gasses, including a recent lawsuit filed against us and several other utilities, seeking damages related to climate change. In the past several years, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions, but such bills have not received sufficient Congressional approval to date to become law; however, there is growing consensus that some form of regulation or legislation is likely to occur in the near future at the federal level with respect to greenhouse gas emissions. 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 CO 2 and other greenhouse gas emissions could result in the creation of substantial additional costs in the form of taxes, emissions allowances or required equipment upgrades and could have a material adverse impact on all fossil fuel fired generation facilities (particularly coal fired facilities), 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 monetary civil penalties or a progressively increased inspection regime, which could ultimately result in the shut down of a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. See the first risk factor above for a discussion of the enhanced NRC inspection regime currently in effect at Palo Verde and the related operational and regulatory implications. In addition, although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and adversely affect our results of operations 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.
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      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 weather conditions.
     Weather conditions directly influence the demand for electricity and affect the price of energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, our overall operating results fluctuate substantially on a seasonal basis. In addition, APS has historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish our results of operations and harm our financial condition.
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      Our cash flow largely depends on the performance of our subsidiaries.
     We conduct our operations primarily through subsidiaries. Substantially all of our consolidated assets are held by such subsidiaries. Accordingly, our cash flow is dependent upon the earnings and cash flows of these subsidiaries and their distributions to us. The subsidiaries are separate and distinct legal entities and have no obligation to make distributions to us.
     The debt agreements of some of our subsidiaries may restrict their ability to pay dividends, make distributions or otherwise transfer funds to us. An ACC financing order requires APS to maintain a common equity ratio of at least 40% and does not allow APS to pay common dividends if the payment would reduce its common equity below that threshold. The common equity ratio, as defined in the ACC order, is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt.
      Our ability to meet our debt service obligations could be adversely affected because our debt securities are structurally subordinated to the debt securities and other obligations of our subsidiaries.
     Because we are structured as a holding company, all existing and future debt and other liabilities of our subsidiaries will be effectively senior in right of payment to our debt securities. None of the indentures under which we or our subsidiaries may issue debt securities limits our ability or the ability of our subsidiaries to incur additional debt in the future. The assets and cash flows of our subsidiaries will be available, in the first instance, to service their own debt and other obligations. Our ability to have the benefit of their assets and cash flows, particularly in the case of any insolvency or financial distress affecting our subsidiaries, would arise only through our equity ownership interests in our subsidiaries and only after their creditors have been satisfied.
      Financial market disruptions may increase our financing costs or limit our access to the credit markets, which may adversely affect our liquidity and our ability to implement our financial strategy.
     We rely on access to short-term money markets, longer-term capital markets and the bank markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets 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	
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 	•	 	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 with our competitors that have less debt.	
     Recent sub-prime mortgage issues have adversely affected the overall financial markets, generally resulting in increased interest rates, reduced access to the capital markets, and actual or potential downgrades of bond insurers, among other negative matters. The interest rates on certain issues of APS’ pollution control bonds are periodically reset through auction processes. These bonds are supported by bond insurance policies provided by Ambac, and the interest rates on those bonds are directly affected by the rating of the bond insurer. Accordingly, interest rates on these bonds have recently increased. We do not expect, however, that any such increase will have a material adverse impact on our financial position, results of operations, cash flows or liquidity.
      A reduction in our credit ratings could materially and adversely affect our business, financial condition and results of operations.
     We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade 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
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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.
      The market price of our common stock may be volatile.
     The market price of our common stock could be subject to significant fluctuations in response to factors such as the following, some of which are beyond our control:

 	•	 	variations in our quarterly operating results;	
 		
 	•	 	operating results that vary from the expectations of management, securities analysts and investors;	
 		
 	•	 	changes in expectations as to our future financial performance, including financial estimates by securities analysts and investors;	
 		
 	•	 	developments generally affecting industries in which we operate, particularly the energy distribution and energy generation industries;	
 		
 	•	 	announcements by us or our competitors of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;	
 		
 	•	 	announcements by third parties of significant claims or proceedings against us;	
 		
 	•	 	favorable or adverse regulatory or legislative developments;	
 		
 	•	 	our dividend policy;	
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 	•	 	future sale of equity or equity-linked securities; and	
 		
 	•	 	general domestic and international economic conditions.	
     In addition, the stock market in general has experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations may adversely affect the market price of our common stock.
      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 continue to be adversely affected by a variety of factors affecting the real estate market, including downward changes in general economic, real estate construction or other business conditions; the 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 2007 fiscal year and that remain unresolved .
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ITEM 2. PROPERTIES
Information Regarding Our Properties
     See “Business of Arizona Public Service Company – Portfolio Resources” in Item 1 for the location and a description of our principal properties.
     See “Business of Arizona Public Service Company – Environmental Matters” and “Water Supply” in Item 1 with respect to matters having a possible impact on the operation of certain of APS’ power plants.
     See “Business of Arizona Public Service Company – Construction Program” in Item 1 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources” in Item 7 for a discussion of APS’ construction program.
Real Estate Segment Properties
     See “Business of SunCor Development Company” in Item 1 for information regarding SunCor’s properties. Substantially all of SunCor’s debt is collateralized by interests in certain real property.
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ITEM 3. LEGAL PROCEEDINGS
     See “Business of Arizona Public Service Company – Environmental Matters” and “Water Supply” in Item 1 with regard to pending or threatened litigation and other disputes.
     See Note 3 with respect to retail rate proceedings before the ACC.
     See Note 11 with regard to a lawsuit against APS and the other Navajo Generating Station participants and for information relating to the FERC proceedings on California energy market issues.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
     Not applicable.
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SUPPLEMENTAL ITEM.
EXECUTIVE OFFICERS OF PINNACLE WEST
     Pinnacle West’s executive officers are as follows:
 	 	 	 	 	 	 	
Name	 	Age at February 27, 2008	 	Position(s) at February 27, 2008	
William J. Post	 	 	57	 	 	Chairman of the Board and Chief Executive Officer (1)	
 	 	 	 	 	 	 	
Jack E. Davis	 	 	61	 	 	President and Chief Operating Officer, and Chief Executive Officer, APS (1)	
 	 	 	 	 	 	 	
Donald E. Brandt	 	 	53	 	 	Executive Vice President and Chief Financial Officer, and President and Chief Financial Officer of APS	
 	 	 	 	 	 	 	
Jan H. Bennett	 	 	60	 	 	Senior Vice President, Energy Delivery, APS	
 	 	 	 	 	 	 	
John R. Denman	 	 	65	 	 	Senior Vice President, Fossil Operations, APS	
 	 	 	 	 	 	 	
Randall K. Edington	 	 	54	 	 	Executive Vice President and Chief Nuclear Officer, APS	
 	 	 	 	 	 	 	
Armando B. Flores	 	 	64	 	 	Executive Vice President, Corporate Business Services, APS	
 	 	 	 	 	 	 	
Chris N. Froggatt	 	 	50	 	 	Vice President and Controller, APS	
 	 	 	 	 	 	 	
Barbara M. Gomez	 	 	53	 	 	Vice President and Treasurer	
 	 	 	 	 	 	 	
Nancy C. Loftin	 	 	54	 	 	Senior Vice President, General Counsel and Secretary	
 	 	 	 	 	 	 	
Donald G. Robinson	 	 	54	 	 	Senior Vice President, Planning and Administration, APS	
 	 	 	 	 	 	 	
Lori S. Sundberg	 	 	44	 	 	Vice President, Human Resources, APS	
 	 	 	 	 	 	 	
Steven M. Wheeler	 	 	59	 	 	Executive Vice President, Customer Service and Regulation, APS	

(1)	 	Member of the Board of Directors.	
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     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 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). Mr. Davis has announced that he will retire effective March 1, 2008. He is also a director of APS.
     Mr. Brandt was elected Executive Vice President of Pinnacle West in September 2003. Prior to that time, he was Senior Vice President of Pinnacle West (December 2002 – September 2003). He was also elected Chief Financial Officer of Pinnacle West in December 2002. Mr. Brandt was also elected President of APS in December 2006. Prior to that time, he was Executive Vice President of APS (September 2003 – December 2006) and Senior Vice President of APS (January 2003 – September 2003). He was also elected Chief Financial Officer of APS in January of 2003. Effective March 1, 2008, Mr. Brandt will serve as President and Chief Operating Officer of Pinnacle West, and President and Chief Executive Officer of APS.
     Mr. Bennett was elected to his present position effective November 2007. Prior to that time, he was Vice President, Customer Service of APS (May 1991 – November 2007).
     Mr. Denman was elected to his present position effective November 2007. Prior to that time, he was Vice President, Fossil Generation of APS (April 1997 – November 2007).
     Mr. Edington was elected to his present position effective November 2007. Prior to that time, he was Senior Vice President and Chief Nuclear Officer of APS (January 2007 – November 2007). He was previously with Entergy Corporation, serving as Site Vice President and Chief Nuclear Officer of Cooper Generating Station (2003 – January 2007) 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. Flores has announced that he will retire effective March 31, 2008.
     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.
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     Ms. Loftin was elected to her present position effective November 2007. Prior to that time, she was Vice President, General Counsel and Secretary of Pinnacle West (October 2002 – November 2007) and Vice President and General Counsel (July 1999 – October 2002). She was also elected Vice President and General Counsel of APS in July 1999 and Secretary of APS in October 2002.
     Mr. Robinson was elected to his present position effective November 2007. Prior to that time, he was Vice President, Planning of APS (September 2003 – November 2007), 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).
     Ms. Sundberg was elected Vice President, Human Resources of APS effective November 2007. Prior to that time, she was with American Express Company, serving as Vice President, Employee Relations, Safety, Compliance & Embrace (January 2007 – November 2007), Vice President, HR Relationship Leader, Global Corporate Travel Division (August 2003 – January 2007) and Vice President, Global Culture Initiative (January 2003 – August 2003).
     Mr. Wheeler was elected to his present position in September 2003. Prior to that time, he was Senior Vice President, Regulation, System Planning and Operations of APS (October 2002 – September 2003) and Senior Vice President, Transmission, Regulation and Planning of Pinnacle West and APS (June 2001 – October 2002).
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PART II
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED
 STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
     Pinnacle West’s common stock is publicly held and is traded on the New York Stock Exchange. At the close of business on February 21, 2008, Pinnacle West’s common stock was held of record by approximately 30,177 shareholders.
QUARTERLY STOCK PRICES AND DIVIDENDS PAID PER SHARE STOCK SYMBOL: PNW
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Dividends	
2007	 	High	 	Low	 	Close	 	Per Share	
1st Quarter	 	$	51.67	 	 	$	46.43	 	 	$	48.25	 	 	$	0.525	 	
2nd Quarter	 	 	50.68	 	 	 	39.38	 	 	 	39.85	 	 	 	0.525	 	
3rd Quarter	 	 	41.76	 	 	 	36.79	 	 	 	39.51	 	 	 	0.525	 	
4th Quarter	 	 	44.50	 	 	 	39.04	 	 	 	42.41	 	 	 	0.525	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	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	 	
     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 2007 and 2006.
Common Stock Dividends
(Dollars in Thousands)
 	 	 	 	 	
Quarter	 	2007	 	2006	
1 st Quarter	 	$42,500	 	$42,500	
2 nd Quarter	 	42,500	 	42,500	
3 rd Quarter	 	42,500	 	42,500	
4 th Quarter	 	42,500	 	42,500	
     The sole holder of APS’ common stock, Pinnacle West, is entitled to dividends when and as declared out of funds legally available therefor. As of December 31, 2007, APS did not have any outstanding preferred stock.
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      Issuer Purchases of Equity Securities
     The following table contains information about our purchases of our common stock during the fourth quarter of 2007.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total	 	 	 	 	 	Total Number of	 	 	
 	 	Number of	 	 	 	 	 	Shares Purchased	 	Maximum Number of	
 	 	Shares	 	Average	 	as Part of Publicly	 	Shares that May Yet Be	
 	 	Purchased	 	Price Paid	 	Announced Plans	 	Purchased Under the	
Period	 	(1)	 	per Share	 	or Programs	 	Plans or Programs	
October 1 – October 31, 2007	 	 	862	 	 	$	41.90	 	 	 	—	 	 	 	—	 	
November 1 – November 30, 2007	 	 	6	 	 	 	 42.37	 	 	 	—	 	 	 	—	 	
December 1 – December 31, 2007	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

Total	 	 	868	 	 	$	41.90	 	 	 	—	 	 	 	—	 	

			
(1)	 	Represents shares of common stock withheld by Pinnacle West to satisfy tax withholding obligations upon the vesting of restricted stock.	
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ITEM 6. SELECTED FINANCIAL DATA
 PINNACLE WEST CAPITAL CORPORATION
SELECTED CONSOLIDATED FINANCIAL DATA
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	 	2003	 	
 	 	(dollars in thousands, except per share amounts)	 	
OPERATING RESULTS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Regulated electricity segment	 	$	2,918,163	 	 	$	2,635,036	 	 	$	2,237,145	 	 	$	2,035,247	 	 	$	1,978,075	 	
Real estate segment	 	 	215,068	 	 	 	399,798	 	 	 	338,031	 	 	 	350,315	 	 	 	361,604	 	
Marketing and trading	 	 	342,371	 	 	 	330,742	 	 	 	351,558	 	 	 	400,628	 	 	 	391,196	 	
Other revenues	 	 	48,018	 	 	 	36,172	 	 	 	61,221	 	 	 	42,816	 	 	 	27,929	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total operating revenues	 	$	3,523,620	 	 	$	3,401,748	 	 	$	2,987,955	 	 	$	2,829,006	 	 	$	2,758,804	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations (a)	 	$	298,780	 	 	$	317,143	 	 	$	223,163	 	 	$	246,590	 	 	$	225,384	 	
Discontinued operations – net of income taxes (b)	 	 	8,363	 	 	 	10,112	 	 	 	(46,896	)	 	 	(3,395	)	 	 	15,195	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	307,143	 	 	$	327,255	 	 	$	176,267	 	 	$	243,195	 	 	$	240,579	 	

COMMON STOCK DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Book value per share – year-end	 	$	35.15	 	 	$	34.48	 	 	$	34.58	 	 	$	32.14	 	 	$	30.97	 	
Earnings (loss) per weighted-average common share outstanding:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing operations – basic	 	$	2.98	 	 	$	3.19	 	 	$	2.31	 	 	$	2.70	 	 	$	2.47	 	
Net income – basic	 	$	3.06	 	 	$	3.29	 	 	$	1.83	 	 	$	2.66	 	 	$	2.64	 	
Continuing operations – diluted	 	$	2.96	 	 	$	3.17	 	 	$	2.31	 	 	$	2.69	 	 	$	2.47	 	
Net income – diluted	 	$	3.05	 	 	$	3.27	 	 	$	1.82	 	 	$	2.66	 	 	$	2.63	 	
Dividends declared per share	 	$	2.10	 	 	$	2.025	 	 	$	1.925	 	 	$	1.825	 	 	$	1.725	 	
Weighted-average common shares outstanding – basic	 	 	100,255,807	 	 	 	99,417,008	 	 	 	96,483,781	 	 	 	91,396,904	 	 	 	91,264,696	 	
Weighted-average common shares outstanding – diluted	 	 	100,834,871	 	 	 	100,010,108	 	 	 	96,589,949	 	 	 	91,532,473	 	 	 	91,405,134	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
BALANCE SHEET DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets	 	$	11,243,712	 	 	$	11,455,943	 	 	$	11,322,645	 	 	$	9,896,747	 	 	$	9,519,042	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Liabilities and equity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities	 	$	1,384,967	 	 	$	1,458,560	 	 	$	2,272,073	 	 	$	1,625,896	 	 	$	1,432,568	 	
Long-term debt less current maturities	 	 	3,127,125	 	 	 	3,232,633	 	 	 	2,608,455	 	 	 	2,584,985	 	 	 	2,616,585	 	
Deferred credits and other	 	 	3,200,009	 	 	 	3,318,634	 	 	 	3,017,153	 	 	 	2,735,670	 	 	 	2,640,110	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities	 	 	7,712,101	 	 	 	8,009,827	 	 	 	7,897,681	 	 	 	6,946,551	 	 	 	6,689,263	 	
Common stock equity	 	 	3,531,611	 	 	 	3,446,116	 	 	 	3,424,964	 	 	 	2,950,196	 	 	 	2,829,779	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities and equity	 	$	11,243,712	 	 	$	11,455,943	 	 	$	11,322,645	 	 	$	9,896,747	 	 	$	9,519,042	 	

			
(a)	 	Includes regulatory disallowance of $8 million after tax in 2007 and $84 million after tax in 2005. See Note 3.	
 		
(b)	 	Amounts primarily related to Silverhawk and SunCor discontinued operations. See Note 22.	
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SELECTED FINANCIAL DATA
ARIZONA PUBLIC SERVICE COMPANY
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	 	2003	 	
 	 	(dollars in thousands)	 	
OPERATING RESULTS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Electric operating revenues	 	$	2,936,277	 	 	$	2,658,513	 	 	$	2,270,793	 	 	$	2,197,121	 	 	$	2,104,931	 	
Fuel and purchased power costs	 	 	1,151,392	 	 	 	969,767	 	 	 	688,982	 	 	 	763,254	 	 	 	703,431	 	
Operating expenses	 	 	1,358,890	 	 	 	1,290,804	 	 	 	1,200,198	 	 	 	1,104,886	 	 	 	1,103,342	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income	 	 	425,995	 	 	 	397,942	 	 	 	381,613	 	 	 	328,981	 	 	 	298,158	 	
Other income (deductions)	 	 	20,870	 	 	 	27,584	 	 	 	(69,171	)	 	 	15,328	 	 	 	26,347	 	
Interest deductions – net	 	 	162,925	 	 	 	155,796	 	 	 	141,963	 	 	 	144,682	 	 	 	143,568	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	283,940	 	 	$	269,730	 	 	$	170,479	 	 	$	199,627	 	 	$	180,937	 	

BALANCE SHEET DATA	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets	 	$	10,402,905	 	 	$	10,513,692	 	 	$	9,707,441	 	 	$	8,098,552	 	 	 	$7,722,533	 	

Liabilities and equity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common stock equity	 	$	3,351,441	 	 	$	3,207,473	 	 	$	2,985,225	 	 	$	2,232,402	 	 	$	2,203,630	 	
Long-term debt less current maturities	 	 	2,876,881	 	 	 	2,877,502	 	 	 	2,479,703	 	 	 	2,267,094	 	 	 	2,135,606	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total capitalization	 	 	6,228,322	 	 	 	6,084,975	 	 	 	5,464,928	 	 	 	4,499,496	 	 	 	4,339,236	 	
Current liabilities	 	 	1,096,224	 	 	 	1,278,566	 	 	 	1,513,964	 	 	 	1,178,770	 	 	 	915,884	 	
Deferred credits and other	 	 	3,078,359	 	 	 	3,150,151	 	 	 	2,728,549	 	 	 	2,420,286	 	 	 	2,467,413	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities and equity	 	$	10,402,905	 	 	$	10,513,692	 	 	$	9,707,441	 	 	$	8,098,552	 	 	$	7,722,533	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
     The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’ Financial Statements and the related Notes that appear in Item 8 of this report.
OVERVIEW
     Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so. Customer growth in APS’ service territory is above the national average and remains an important driver of our revenues and earnings.
     Our cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed below under “Liquidity and Capital Resources,” are substantial because of customer growth in APS’ service territory and inflationary impacts on the capital budget, highlighting APS’ need for the timely recovery through rates of these and other expenditures. On June 28, 2007, the ACC issued an order in a general rate case granting APS retail base rate increases. The ACC rate case decision and other retail and wholesale rate matters are discussed in Note 3.
     SunCor, our real estate development subsidiary, has been an important source of earnings in recent years, although SunCor’s earnings in 2007 and expected earnings in 2008 reflect a slowdown in the western United States real estate markets. See discussion below in “Pinnacle West Consolidated – Factors Affecting our Financial Outlook – Subsidiaries.” Our subsidiary, APSES, provides energy-related products and services and competitive commodity-related energy services to commercial and industrial retail customers in the western United States. Recently, APSES has de-emphasized its commodity-related energy services. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures.
     We continue to focus on solid operational performance in our electricity generation and delivery activities. In the delivery area, we focus on superior reliability and customer satisfaction. We plan to expand long-term energy resources and our transmission and distribution systems to meet the electricity needs of our growing retail 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.
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PINNACLE WEST CONSOLIDATED –
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
     Pinnacle West’s two reportable business segments are:

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

 	•	 	our real estate segment, which consists of SunCor’s real estate development and investment activities.	
     The following table summarizes income from continuing operations for the years ended December 31, 2007, 2006 and 2005 and reconciles net income in total (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	
Regulated electricity segment (a)	 	$	274	 	 	$	259	 	 	$	167	 	
Real estate segment	 	 	12	 	 	 	50	 	 	 	35	 	
All other (b)	 	 	13	 	 	 	8	 	 	 	21	 	
 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	 	299	 	 	 	317	 	 	 	223	 	
Discontinued operations – net of tax:	 	 	 	 	 	 	 	 	 	 	 	 	
Real estate (c)	 	 	11	 	 	 	10	 	 	 	17	 	
Sale of Silverhawk (d)	 	 	—	 	 	 	1	 	 	 	(67	)	
All other (b)	 	 	(3	)	 	 	(1	)	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	
Net income	 	$	307	 	 	$	327	 	 	$	176	 	

			
(a)	 	Includes an $84 million after-tax regulatory disallowance of plant costs in 2005 in accordance with APS’ 2003 general retail rate case settlement.	
 		
(b)	 	Includes activities related to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.	
 		
(c)	 	Primarily relates to sales of commercial properties.	
 		
(d)	 	See Note 22.	
PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS
2007 Compared with 2006
     Our consolidated net income for 2007 was $307 million compared with $327 million for 2006. The current period includes income from discontinued operations of $11 million related to sales of commercial properties by SunCor and a loss from discontinued operations of $3 million related to an APSES project. The prior year includes income from discontinued operations of $10 million related to sales of commercial properties by SunCor. Income from continuing operations decreased $18 million in the year-to-year comparison and is reflected in the segments as follows:
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 	•	 	Regulated Electricity Segment – Income from continuing operations increased approximately $15 million primarily due to higher retail sales related to customer growth; the effects of weather on retail sales; and impacts of the retail rate increase. These positive factors were partially offset by higher operations and maintenance expense primarily due to increased generation costs (including increased maintenance and overhauls and the Palo Verde performance improvement plan), customer service and other costs; higher depreciation and amortization primarily due to increased plant balances; lower other income, net of expense, primarily due to miscellaneous asset sales in the prior year and lower interest income as a result of lower investment balances; and a regulatory disallowance. In addition, higher fuel and purchased power costs related to commodity price increases were substantially offset by deferral of such costs in accordance with the PSA. See Note 3 for further discussion of the regulatory disallowance and the PSA.	

 	•	 	Real Estate Segment – Income from continuing operations decreased approximately $38 million primarily due to lower sales of residential property and land parcels resulting from the continued slowdown in the western United States real estate markets.	
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     · Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2007 compared with the prior year are contained in the following table (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Increase (Decrease)	 	
 	 	Pretax	 	 	After Tax	 	
Regulated electricity segment:	 	 	 	 	 	 	 	 	
Higher retail sales primarily due to customer growth, excluding weather effects	 	$	46	 	 	$	28	 	
Effects of weather on retail sales	 	 	37	 	 	 	23	 	
Impacts of retail rate increase effective July 1, 2007:	 	 	 	 	 	 	 	 	
Revenue increase related to higher Base Fuel Rate	 	 	185	 	 	 	113	 	
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate	 	 	(171	)	 	 	(104	)	
Non-fuel rate increase	 	 	6	 	 	 	4	 	
Net changes in fuel and purchased power costs related to price:	 	 	 	 	 	 	 	 	
Higher fuel and purchased power costs related to increased commodity prices	 	 	(121	)	 	 	(74	)	
Increased deferred fuel and purchased power costs related to increased prices	 	 	115	 	 	 	70	 	
Mark-to-market fuel and purchased power costs, net of related deferred fuel and purchased power costs	 	 	18	 	 	 	11	 	
Regulatory disallowance (see Note 3)	 	 	(14	)	 	 	(8	)	
Operations and maintenance increases primarily due to:	 	 	 	 	 	 	 	 	
Increased generation costs, including increased maintenance and overhauls and Palo Verde performance improvement plan	 	 	(25	)	 	 	(15	)	
Customer service and other costs	 	 	(21	)	 	 	(13	)	
Higher depreciation and amortization primarily due to increased plant balances	 	 	(12	)	 	 	(7	)	
Lower other income, net of expense, primarily due to lower interest income as a result of lower investment balances and miscellaneous asset sales in prior year	 	 	(15	)	 	 	(9	)	
Income tax benefits resolved in 2007 related to prior years	 	 	—	 	 	 	13	 	
Income tax credits resolved in 2006 related to prior years	 	 	—	 	 	 	(14	)	
Miscellaneous items, net	 	 	6	 	 	 	(3	)	
 	 	 	 	 	 	 	
Increase in regulated electricity segment net income	 	 	34	 	 	 	15	 	
Lower real estate segment income from continuing operations primarily due to:	 	 	 	 	 	 	 	 	
Lower sales of residential property resulting from the continued slowdown in the western United States real estate markets	 	 	(47	)	 	 	(29	)	
Lower sales of land parcels	 	 	(12	)	 	 	(7	)	
Higher other costs	 	 	(5	)	 	 	(2	)	
Higher marketing and trading contribution primarily due to higher mark-to-market gains resulting from changes in forward prices and higher unit margins	 	 	8	 	 	 	5	 	
Other miscellaneous items, net	 	 	(2	)	 	 	—	 	
 	 	 	 	 	 	 	
Decrease in income from continuing operations	 	$	(24	)	 	 	(18	)	
 	 	 	 	 	 	 	 	
Discontinued operations:	 	 	 	 	 	 	 	 	
Increased commercial property real estate sales	 	 	 	 	 	 	1	 	
Other discontinued operations	 	 	 	 	 	 	(3	)	
 	 	 	 	 	 	 	 	
Decrease in net income	 	 	 	 	 	$	(20	)	
 	 	 	 	 	 	 	 	
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Regulated Electricity Segment Revenues
     Regulated electricity segment revenues were $283 million higher for the year ended December 31, 2007 compared with the prior year primarily because of:

 	•	 	a $191 million increase in retail revenues due to a rate increase effective July 1, 2007;	
 		
 	•	 	a $60 million increase in retail revenues primarily related to customer growth, excluding weather effects;	
 		
 	•	 	a $50 million increase in retail revenues due to the effects of weather;	
 		
 	•	 	a $3 million increase in revenues from Off-System Sales due to higher prices and volumes;	
 		
 	•	 	a $35 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 3); and	
 		
 	•	 	a $14 million net increase due to miscellaneous factors.	
Real Estate Segment Revenues
     Real estate segment revenues were $185 million lower for the year ended December 31, 2007 compared with the prior year primarily because of:

 	•	 	a $167 million decrease in residential property sales due to the continued slowdown in western United States real estate markets; and	
 		
 	•	 	an $18 million decrease primarily due to lower sales of land parcels.	
All Other Revenues
     Marketing and trading revenues were $12 million higher for the year ended December 31, 2007 compared with the prior year primarily because of higher mark-to-market gains resulting from changes in forward prices and higher competitive retail sales volumes in California.
     Other revenues were $12 million higher for the year ended December 31, 2007 compared with the prior year primarily as a result of increased sales by APSES of energy-related products and services.
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:
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 	•	 	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.	
 		
 	•	 	Real Estate Segment – Income from continuing operations increased approximately $15 million primarily due to increased margins on residential sales and the sale of certain joint venture assets, partially offset by higher general and administrative expenses. Income from discontinued operations decreased $7 million due to lower commercial property sales.	
 		
 	•	 	Other – Income from continuing operations decreased approximately $13 million primarily due to lower mark-to-market gains, partially offset by higher unit margins on wholesale sales and competitive retail sales in California.	
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Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2006 compared with the prior year are contained in the following table (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Increase (Decrease)	 	
 	 	Pretax	 	 	After Tax	 	
Regulated electricity segment:	 	 	 	 	 	 	 	 	
Higher fuel and purchased power costs	 	$	(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	 	
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	 	 	3	 	 	 	2	 	
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	 	 	13	 	 	 	8	 	
Income tax credits related to prior years resolved in 2006	 	 	—	 	 	 	14	 	
Miscellaneous items, net	 	 	(4	)	 	 	2	 	
 	 	 	 	 	 	 	
Increase in regulated electricity segment net income	 	 	122	 	 	 	92	 	
Lower marketing and trading contribution 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	 	
Miscellaneous items, net	 	 	(5	)	 	 	(2	)	
 	 	 	 	 	 	 	
Increase in income from continuing operations	 	$	124	 	 	 	94	 	
 	 	 	 	 	 	 	 	
Discontinued operations:	 	 	 	 	 	 	 	 	
Silverhawk loss in 2005	 	 	 	 	 	 	68	 	
Lower commercial property real estate sales	 	 	 	 	 	 	(7	)	
Income in 2005 related to sale of NAC	 	 	 	 	 	 	(4	)	
 	 	 	 	 	 	 	 	
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;	
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 	•	 	a $124 million increase in retail revenues related to customer growth, excluding weather effects;	

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

 	•	 	a $3 million increase due to miscellaneous factors.	
Real Estate Segment Revenues
     Real estate segment revenues were $62 million higher for 2006 compared with the prior-year period primarily as a result of:

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

 	•	 	a $7 million increase in commercial real estate sales.	
Other Revenues
     Other revenues were $25 million lower for 2006 compared with the prior-year period primarily as a result of decreased sales-related products and services by APSES.
     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.	
LIQUIDITY AND CAPITAL RESOURCES – Pinnacle West Consolidated
      Operating Cash Flows
     Net cash provided by operating activities was $658 million for 2007, compared with $394 million for 2006, an increase in net cash flow of $264 million. This change was primarily due to a decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
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     Net cash provided by operating activities was $394 million for 2006, compared with $730 million for 2005, a decrease in net cash flow of $336 million. This change was primarily due to an increase in 2006 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
      Investing Cash Flows
     Net cash used for investing activities was $873 million for 2007, compared with $569 million for 2006, a decrease in net cash flow of $304 million.
     This cash flow decrease was primarily due to:

 	•	 	A decrease in cash provided by investing activities related to proceeds of $208 million received in 2006 from the sale of Silverhawk; and	

 	•	 	An increase in cash used for capital expenditures and capitalized interest of $183 million (see table and discussion below).	
     The cash flow decreases were partially offset by:

 	•	 	A decrease of $65 million in cash invested in securities at APS;	

 	•	 	An increase of $19 million cash provided by sale of real estate investments; and	

 	•	 	A net increase of $3 million due to miscellaneous factors.	
     Net cash used for investing activities was $569 million for 2006, compared with $585 million for 2005, an increase in net cash flow of $16 million.
     This cash flow increase was primarily due to:

 	•	 	Proceeds of $208 million received in 2006 from the sale of Silverhawk; and	

 	•	 	Less cash used for capital expenditures (including the 2005 acquisition of the Sundance Plant) and capitalized interest of approximately $72 million (see table and discussion below).	
     The cash flow increases were partially offset by:

 	•	 	An increase of $214 million in cash invested in securities at APS;	

 	•	 	A decrease of $43 million in cash provided by sale of real estate investments; and	
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 	•	 	A net decrease of $7 million due to miscellaneous factors.	
      Financing Cash Flows
     Net cash provided by financing activities was $185 million for 2007, compared with $108 million for 2006, an increase in net cash flow of $77 million.
     This cash flow increase was primarily due to a net increase of $295 million in short-term borrowings to fund day-to-day operations and liquidity needs.
     The cash flow increases were partially offset by:

 	•	 	A decrease of $161 million in net new long-term debt (issuances net of redemptions and refinancing) to fund our construction program and for other general corporate purposes; and	

 	•	 	A net decrease of $57 million due to miscellaneous factors.	
     Net cash provided by financing activities was $108 million for 2006, compared with net cash used for financing activities in 2005 of $155 million, an increase in net cash flow of $263 million.
     This cash flow increase was primarily due to:

 	•	 	An increase of $429 million in net new long-term debt (issuances net of redemptions and refinancing) to fund our construction program and for other general corporate purposes;	

 	•	 	A net increase of $56 million in short-term borrowings to fund day-to-day operations and liquidity needs; and	

 	•	 	A net increase of $37 million due to miscellaneous factors.	
     The cash flow increases were partially offset by:

 	•	 	A decrease of $259 million related to common stock issuance, primarily due to a 2005 public offering.	
      Liquidity
      Capital Expenditure Requirements
     The following table summarizes the actual capital expenditures for 2005, 2006 and 2007 and estimated capital expenditures for the next three years:
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CAPITAL EXPENDITURES
(dollars in millions)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Actual	 	 	Estimated	 	
 	 	2005	 	 	2006	 	 	2007	 	 	2008	 	 	2009	 	 	2010	 	
APS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distribution	 	$	325	 	 	$	357	 	 	$	372	 	 	$	410	 	 	$	440	 	 	$	430	 	
Generation (a)	 	 	356	 	 	 	176	 	 	 	353	 	 	 	380	 	 	 	390	 	 	 	380	 	
Transmission	 	 	92	 	 	 	113	 	 	 	138	 	 	 	220	 	 	 	320	 	 	 	290	 	
Other (b)	 	 	36	 	 	 	16	 	 	 	37	 	 	 	50	 	 	 	40	 	 	 	50	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Subtotal	 	 	809	 	 	 	662	 	 	 	900	 	 	 	1,060	 	 	 	1,190	 	 	 	1,150	 	
SunCor (c)	 	 	106	 	 	 	201	 	 	 	161	 	 	 	100	 	 	 	90	 	 	 	100	 	
Other	 	 	13	 	 	 	7	 	 	 	3	 	 	 	20	 	 	 	20	 	 	 	10	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	928	 	 	$	870	 	 	$	1,064	 	 	$	1,180	 	 	$	1,300	 	 	$	1,260	 	

			
(a)	 	Includes $185 million in 2005 for the acquisition of the Sundance Plant.	
 		
(b)	 	Primarily information systems and facilities projects.	
 		
(c)	 	Consists primarily of capital expenditures for residential, land development and retail and office building construction reflected in “Real estate investments” and “Capital expenditures” on the Consolidated Statements of Cash Flows.	
          Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. In addition, these amounts do not include any impacts from the recent changes in the line extension policy (see Note 3). Major transmission projects are driven by regional customer growth.
          Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Installation of new steam generators in Palo Verde Unit 3 was completed in the fourth quarter of 2007 at an approximate cost of $70 million (APS’ share), which completed the steam generator replacement program for all three units. Environmental expenditures are estimated at approximately $70 million to $120 million per year for 2008, 2009 and 2010. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require additional environmental expenditures. (See “Business of Arizona Public Service Company – Environmental Matters – Regional Haze Rules” in Item 1.) Generation also includes nuclear fuel expenditures of approximately $90 million to $120 million per year for 2008, 2009 and 2010.
          Capital expenditures will be funded with internally generated cash and/or external financings, which may include issuances of long-term debt and Pinnacle West common stock.
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           Pinnacle West (Parent Company)
          Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
          On January 23, 2008, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on March 3, 2008, to shareholders of record on February 1, 2008.
          Our primary sources of cash are dividends from APS, external debt and equity financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2005 through 2007, total dividends from APS were $510 million and total distributions from SunCor were $70 million. For 2007, 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, 2007, APS’ common equity ratio, as defined, was approximately 54%.
          At December 31, 2007, 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, 2007, Pinnacle West had no borrowings outstanding under its revolving line of credit. At December 31, 2007, we had $115 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 our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We contributed approximately $52 million in 2007. The contribution to our pension plan in 2008 is estimated to be approximately $50 million. The expected contribution to our other postretirement benefit plans in 2008 is estimated to be approximately $20 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.
           Significant Financing Activities – 2007. 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.
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          In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.
           Significant Financing Activities –2006. In January 2006, Pinnacle West infused into APS $210 million of the proceeds from the sale of Silverhawk.
          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.
           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, equity infusions from Pinnacle West 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. As noted above, in May 2007, Pinnacle West infused approximately $40 million of equity into APS.
          APS’ outstanding long-term debt, including current maturities, was approximately $2.9 billion at December 31, 2007. 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, 2007, APS had borrowings of $218 million under its revolving line of credit. The amount drawn was used for general corporate purposes.
           Significant Financing Activities –2007. Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs.
           Significant Financing Activities –2006. 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’
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6.75% Senior Notes due November 15, 2006. The remainder was used to fund its construction program and other general corporate purposes.
          On September 28, 2006, APS put in place the $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.
           Other Financing Matters — See Note 3 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.
          See “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 2007 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 entered into a secured construction loan on April 13, 2007, in the amount of $60 million, of which $48 million was outstanding at December 31, 2007. The loan matures on April 19, 2009, and may be extended one year if certain conditions are met.
          On July 31, 2007, SunCor borrowed $12 million under a new secured construction loan. The loan matures on July 31, 2009, and may be extended annually up to two years.
          SunCor’s total outstanding debt was approximately $246 million as of December 31, 2007, including $94 million of debt classified as current maturities of long-term debt under revolving lines of credit totaling $170 million. SunCor’s long-term debt, including current maturities, was $238 million and total short-term debt was $8 million at December 31, 2007. See Note 6.
          El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.
          APSES expects minimal capital expenditures over the next three years.
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           Debt Provisions
          Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2007, the ratio was approximately 50% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require 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, 2007. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.
          Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank financial agreements contain a pricing grid in which the interest costs we pay are determined by our current credit ratings.
          All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.
          See Note 6 for further discussions.
           Credit Ratings
          The ratings of securities of Pinnacle West and APS as of February 25, 2008 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, natural gas transportation, fuel supply, and other energy-related contracts.
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 	 	Moody’s	 	Standard & Poor’s	 	Fitch	
Pinnacle West	 	 	 	 	 	 	
Senior unsecured (a)	 	Baa3 (P)	 	BB+ (prelim)	 	N/A	
Commercial paper	 	P-3	 	A-3	 	F3	
Outlook	 	Negative	 	Stable	 	Negative	
 	 	 	 	 	 	 	
APS	 	 	 	 	 	 	
Senior unsecured	 	Baa2	 	BBB-	 	BBB	
Secured lease obligation bonds	 	Baa2	 	BBB-	 	BBB	
Commercial paper	 	P-2	 	A-3	 	F3	
Outlook	 	Negative	 	Stable	 	Stable	

(a)	 	Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim) rating to the senior unsecured securities that can be issued under such shelf registration.	
           Off-Balance Sheet Arrangements
          In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them (see Note 9).
          APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2007, APS would have been required to assume approximately $194 million of debt and pay the equity participants approximately $170 million.
           Guarantees and Letters of Credit
          We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading and APS relate to commodity energy products. Our credit support instruments enable APSES to offer energy-related products and commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 21 for additional information regarding guarantees and letters of credit.
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Contractual Obligations
          The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2007 (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	2009-	 	 	2011-	 	 	 	 	 	 	 	
 	 	2008	 	 	2010	 	 	2012	 	 	Thereafter	 	 	Total	 	
Long-term debt payments, including interest: (a)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
APS	 	$	158	 	 	$	537	 	 	$	1,038	 	 	$	3,135	 	 	$	4,868	 	
SunCor	 	 	173	 	 	 	78	 	 	 	2	 	 	 	2	 	 	 	255	 	
Pinnacle West	 	 	10	 	 	 	21	 	 	 	177	 	 	 	—	 	 	 	208	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total long-term debt payments, including interest	 	 	341	 	 	 	636	 	 	 	1,217	 	 	 	3,137	 	 	 	5,331	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Short-term debt payments, including interest (b)	 	 	342	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	342	 	
Purchased power and fuel commitments (c)	 	 	418	 	 	 	651	 	 	 	434	 	 	 	1,584	 	 	 	3,087	 	
Operating lease payments	 	 	79	 	 	 	148	 	 	 	133	 	 	 	195	 	 	 	555	 	
Nuclear decommissioning funding requirements	 	 	21	 	 	 	46	 	 	 	49	 	 	 	210	 	 	 	326	 	
Purchase obligations (d)	 	 	99	 	 	 	29	 	 	 	2	 	 	 	91	 	 	 	221	 	
Uncertain tax positions	 	 	203	 	 	 	12	 	 	 	—	 	 	 	—	 	 	 	215	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total contractual commitments	 	$	1,503	 	 	$	1,522	 	 	$	1,835	 	 	$	5,217	 	 	$	10,077	 	

			
(a)	 	The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using the rates at December 31, 2007 (see Note 6).	
 		
(b)	 	The short-term debt is primarily related to APS bank borrowings under its revolving line of credit and commercial paper at Pinnacle West (see Note 5).	
 		
(c)	 	Our purchased power and fuel commitments include purchases of coal, electricity, natural gas and nuclear fuel (see Note 11).	
 		
(d)	 	These contractual obligations include commitments for capital expenditures and other obligations.	
CRITICAL ACCOUNTING POLICIES
          In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
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Regulatory Accounting
          Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. A major component of our regulatory assets is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery 90% of the difference between actual retail fuel and power costs and the amount of such costs currently included in base rates. We had $625 million, including $111 million related to the PSA, of regulatory assets on the Consolidated Balance Sheets at December 31, 2007.
          Also included in the balance of regulatory assets at December 31, 2007 is a regulatory asset of $338 million in accordance with SFAS No. 158 for pension and other postretirement benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.
          In addition, we had $643 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2007, which primarily are related to removal costs. See Notes 1 and 3 for more information.
Pensions and Other Postretirement Benefit Accounting
          Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
          The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2007 reported pension liability on the Consolidated Balance Sheets and our 2007 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
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 	 	Increase (Decrease)	
 	 	Impact on	 	Impact on	
 	 	Pension	 	Pension	
Actuarial Assumption (a)	 	Liability	 	Expense	
Discount rate:	 	 	 	 	 	 	 	 	
Increase 1%	 	$	(213	)	 	$	(5	)	
Decrease 1%	 	 	243	 	 	 	9	 	
Expected long-term rate of return on plan assets:	 	 	 	 	 	 	 	 	
Increase 1%	 	 	—	 	 	 	(6	)	
Decrease 1%	 	 	—	 	 	 	6	 	

(a)	 	Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.	
          The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2007 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2007 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Increase (Decrease)	
 	 	Impact on Other	 	Impact on Other	
 	 	Postretirement Benefit	 	Postretirement	
Actuarial Assumption (a)	 	Obligation	 	Benefit Expense	
Discount rate:	 	 	 	 	 	 	 	 	
Increase 1%	 	$	(90	)	 	$	(4	)	
Decrease 1%	 	 	105	 	 	 	5	 	
Health care cost trend rate (b):	 	 	 	 	 	 	 	 	
Increase 1%	 	 	94	 	 	 	7	 	
Decrease 1%	 	 	(76	)	 	 	(5	)	
Expected long-term rate of return on plan assets – pretax:	 	 	 	 	 	 	 	 	
Increase 1%	 	 	—	 	 	 	(2	)	
Decrease 1%	 	 	—	 	 	 	2	 	

(a)	 	Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.	
 		
(b)	 	This assumes a 1% change in the initial and ultimate health care cost trend rate.	
          See Note 8 for further details about our pension and other postretirement benefit plans.
Derivative Accounting
          Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we
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use accrual accounting (for contracts designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)).
          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 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 us on January 1, 2008. We are currently evaluating this new guidance but do not expect it to have a material impact on our financial statements.
          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 this new guidance but do not expect it to have a material impact on our financial statements.
          In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1).  Under FSP FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement.  This new guidance is effective for us on January 1, 2008, with early application permitted.  We are currently evaluating the impacts of FSP FIN 39-1 on our balance sheet. We do not expect the guidance to have an impact on our results of operations or cash flows.
          See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007.
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 2005 through 2007, retail electric revenues comprised approximately 84% of
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our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer growth, variations in weather from period to period, customer mix, average usage per customer, electricity rates and tariffs and the recovery of PSA deferrals. Off-System Sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess economic generation or other energy resources and wholesale market conditions, including demand and prices. Competitive retail sales of energy and energy-related products and services are made by APSES in certain western states that have opened to competition.
           Rate Proceedings Our cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed above under “Liquidity and Capital Resources,” are substantial because of customer growth in APS’ service territory and inflationary impacts on the capital budget, highlighting APS’ need for the timely recovery through rates of these and other expenditures. On June 28, 2007, the ACC issued an order in a general rate case granting APS retail base rate increases. The ACC rate case decision and other retail and wholesale rate matters are discussed in Note 3.
           Fuel and Purchased Power Costs Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and, since April 1, 2005, PSA deferrals and the amortization thereof. See “PSA Modifications” and “2006 Deferrals” in Note 3 for information regarding the PSA, including the 2006 Deferrals. APS’ recovery of PSA deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.
           Customer and Sales Growth The customer and sales growth referred to in this paragraph apply to Native Load customers and sales to them. Customer growth in APS’ service territory was 3.3% during 2007. Customer growth averaged 4.0% a year for the three years 2005 through 2007; and we currently expect customer growth to decline, averaging about 1% to 2% per year for 2008 through 2010 due to factors reflecting the economic conditions both nationally and in Arizona. For the three years 2005 through 2007, APS’ actual retail electricity sales in kilowatt-hours grew at an average annual rate of 4.8%; adjusted to exclude the effects of weather variations, such retail sales growth averaged 3.8% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 1% to 2% on average per year, during 2008 through 2010, excluding the effects of weather variations. We currently expect our retail sales growth in 2008 to be below average because of potential effects on customer usage from the economic conditions mentioned above and retail rate increases (see Note 3).
          Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors can result in increases or decreases in annual net income of up to $10 million.
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           Weather In forecasting retail sales growth, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.
           Wholesale Market Our marketing and trading activities focus primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. Our marketing and trading activities include, subject to specified parameters, marketing, hedging and trading in electricity, fuels and emission allowances and credits. See “Rate Requests for Transmission and Ancillary Services” in Note 3 for information regarding APS’ recent filing with the FERC requesting an increase in transmission rates.
Other Factors Affecting Financial Results
           Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs and other factors.
           Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Capital Expenditures” above for information regarding planned additions to our facilities.
           Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.3% of the assessed value for 2007, 8.9% of assessed value for 2006 and 9.2% for 2005. We expect property taxes to increase as we add new utility plant (including new generation, transmission and distribution facilities) and as we improve our existing facilities. See “Capital Expenditures” above for information regarding planned additions to our facilities.
           Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. 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 electric service providers providing unbundled energy or other utility services to APS’ customers. We cannot predict when, and the extent to which, additional electric service providers will re-enter APS’ service territory.
           Subsidiaries SunCor’s net income was $24 million in 2007, $61 million in 2006 and $56 million in 2005. See Note 17 for further discussion. We currently expect SunCor’s net income in 2008 to be approximately $20 million. This estimate reflects continuation of the slowdown in the western United States real estate markets.
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          The historical results of APSES, Pinnacle West Marketing & Trading and El Dorado are not indicative of future performance.
           General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” below 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, 2007 and 2006. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2007 and 2006 (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Variable-Rate	 	 	Fixed-Rate	 	
 	 	Short-Term Debt	 	 	Long-Term Debt	 	 	Long-Term Debt	 	
 	 	Interest	 	 	 	 	 	 	Interest	 	 	 	 	 	 	Interest	 	 	 	 	
2007	 	Rates	 	 	Amount	 	 	Rates	 	 	Amount	 	 	Rates	 	 	Amount	 	
2008	 	 	5.54	%	 	$	340,661	 	 	 	7.33	%	 	$	159,337	 	 	 	4.65	%	 	$	4,436	 	
2009	 	 	—	 	 	 	—	 	 	 	7.20	%	 	 	71,054	 	 	 	5.76	%	 	 	1,050	 	
2010	 	 	—	 	 	 	—	 	 	 	9.20	%	 	 	201	 	 	 	5.71	%	 	 	1,104	 	
2011	 	 	—	 	 	 	—	 	 	 	8.91	%	 	 	2,284	 	 	 	6.23	%	 	 	576,218	 	
2012	 	 	—	 	 	 	—	 	 	 	9.50	%	 	 	103	 	 	 	6.50	%	 	 	376,293	 	
Years thereafter	 	 	—	 	 	 	—	 	 	 	3.77	%	 	 	567,239	 	 	 	5.64	%	 	 	1,540,462	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	 	$	340,661	 	 	 	 	 	 	$	800,218	 	 	 	 	 	 	$	2,499,563	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value	 	 	 	 	 	$	340,661	 	 	 	 	 	 	$	800,218	 	 	 	 	 	 	$	2,414,301	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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 	 	 	 	 	 	 	 	 	 	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	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
          The tables below present contractual balances of APS’ long-term debt at the expected maturity dates as well as the fair value of those instruments on December 31, 2007 and 2006. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2007 and 2006 (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Variable-Rate	 	 	Fixed-Rate	 	
 	 	Short-Term Debt	 	 	Long-Term Debt	 	 	Long-Term Debt	 	
 	 	Interest	 	 	 	 	 	 	Interest	 	 	 	 	 	 	Interest	 	 	 	 	
2007	 	Rates	 	 	Amount	 	 	Rates	 	 	Amount	 	 	Rates	 	 	Amount	 	
2008	 	 	5.36	%	 	$	218,000	 	 	 	—	 	 	$	—	 	 	 	5.66	%	 	$	978	 	
2009	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	5.60	%	 	 	934	 	
2010	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	5.59	%	 	 	1,012	 	
2011	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	6.37	%	 	 	401,208	 	
2012	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	6.50	%	 	 	376,293	 	
Years thereafter	 	 	—	 	 	 	—	 	 	 	3.76	%	 	 	565,855	 	 	 	5.64	%	 	 	1,540,462	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	 	$	218,000	 	 	 	 	 	 	$	565,855	 	 	 	 	 	 	$	2,320,887	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value	 	 	 	 	 	$	218,000	 	 	 	 	 	 	$	565,855	 	 	 	 	 	 	$	2,235,624	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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 	 	Variable-Rate	 	 	Fixed-Rate	 	
 	 	Long-Term Debt	 	 	Long-Term Debt	 	
 	 	Interest	 	 	 	 	 	 	Interest	 	 	 	 	
2006	 	Rates	 	 	Amount	 	 	Rates	 	 	Amount	 	
2007	 	 	—	 	 	$	—	 	 	 	6.18	%	 	$	1,033	 	
2008	 	 	—	 	 	 	—	 	 	 	6.18	%	 	 	1,230	 	
2009	 	 	—	 	 	 	—	 	 	 	6.17	%	 	 	1,020	 	
2010	 	 	—	 	 	 	—	 	 	 	6.17	%	 	 	1,111	 	
2011	 	 	—	 	 	 	—	 	 	 	6.38	%	 	 	401,320	 	
Years thereafter	 	 	3.77	%	 	 	565,855	 	 	 	5.81	%	 	 	1,916,758	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	 	 	 	$	565,855	 	 	 	 	 	 	$	2,322,472	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair Value	 	 	 	 	 	$	565,855	 	 	 	 	 	 	$	2,288,814	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity Price Risk
          We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas and emissions allowances. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.
          The following tables show the net pretax changes in mark-to-market of our derivative positions in 2007 and 2006 (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	
Mark-to-market of net positions at beginning of year	 	$	15	 	 	$	516	 	
Recognized in earnings:	 	 	 	 	 	 	 	 	
Change in mark-to-market losses for future period deliveries	 	 	(2	)	 	 	(27	)	
Mark-to-market gains realized including ineffectiveness during the period	 	 	(15	)	 	 	(3	)	
Decrease (increase) in regulatory asset	 	 	55	 	 	 	(93	)	
Recognized in OCI:	 	 	 	 	 	 	 	 	
Change in mark-to-market losses for future period deliveries (a)	 	 	(1	)	 	 	(352	)	
Mark-to-market gains realized during the period	 	 	(12	)	 	 	(26	)	
Change in valuation techniques	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	
Mark-to-market of net positions at end of year	 	$	40	 	 	$	15	 	

			
(a)	 	The decreases in mark-to-market recorded in OCI are due primarily to decreases in forward natural gas prices.	
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          The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at December 31, 2007 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” for more discussion of our valuation methods.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Total	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	fair	 	
Source of Fair Value	 	2008	 	 	2009	 	 	2010	 	 	2011	 	 	2012	 	 	Years thereafter	 	 	value	 	
Prices actively quoted	 	$	(12	)	 	$	10	 	 	$	14	 	 	$	2	 	 	$	—	 	 	$	—	 	 	$	14	 	
Prices provided by other external sources	 	 	(4	)	 	 	(16	)	 	 	1	 	 	 	4	 	 	 	3	 	 	 	—	 	 	 	(12	)	
Prices based on models and other valuation methods	 	 	12	 	 	 	15	 	 	 	(1	)	 	 	—	 	 	 	2	 	 	 	10	 	 	 	38	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total by maturity	 	$	(4	)	 	$	9	 	 	$	14	 	 	$	6	 	 	$	5	 	 	$	10	 	 	$	40	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
          The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets at December 31, 2007 and 2006 (dollars in millions).
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	December 31, 2007	 	 	December 31, 2006	 	
 	 	Gain (Loss)	 	 	Gain (Loss)	 	
 	 	Price Up 10%	 	 	Price Down 10%	 	 	Price Up 10%	 	 	Price Down 10%	 	
Mark-to-market changes reported in:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Electricity	 	$	3	 	 	$	(3	)	 	$	—	 	 	$	—	 	
Natural gas	 	 	4	 	 	 	(4	)	 	 	—	 	 	 	—	 	
Regulatory asset (liability) or OCI (a)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Electricity	 	 	45	 	 	 	(45	)	 	 	38	 	 	 	(38	)	
Natural gas	 	 	85	 	 	 	(85	)	 	 	80	 	 	 	(80	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	137	 	 	$	(137	)	 	$	118	 	 	$	(118	)	

			
(a)	 	These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.	
Credit Risk
          We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 1, “Derivative Accounting” for a discussion of our credit valuation adjustment policy. See Note 18 for further discussion of credit risk.
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ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS
Regulatory Matters
          See “Pinnacle West Consolidated – Results of Operations — Regulatory Matters” above for information about the ACC’s order in APS’ general retail rate case and the PSA.
2007 Compared with 2006
          Our net income for 2007 was $284 million compared with $270 million for 2006. APS’ net income increased approximately $14 million primarily due to higher retail sales related to customer growth; the effects of weather on retail sales; and impacts of the retail rate increase. These positive factors were partially offset by higher operations and maintenance expense primarily due to increased generation costs (including increased maintenance and overhauls and the Palo Verde performance improvement plan), customer service and other costs; higher depreciation and amortization primarily due to increased plant balances; higher interest expense due to higher debt balances and higher rates; lower other income, net of expense, primarily due to miscellaneous asset sales in the prior year and lower interest income as a result of lower investment balances; and a regulatory disallowance (see Note 3). In addition, higher fuel and purchased power costs related to commodity price increases were partially offset by the deferral of such costs in accordance with the PSA. See Note 3 for further discussion.
          Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2007 compared with the prior year are contained in the following table (dollars in millions):
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 	 	Increase (Decrease)	 	
 	 	Pretax	 	 	After Tax	 	
Higher retail sales primarily due to customer growth, excluding weather effects	 	$	46	 	 	$	28	 	
Effects of weather on retail sales	 	 	37	 	 	 	23	 	
Impacts of retail rate increase effective July 1, 2007:	 	 	 	 	 	 	 	 	
Revenue increase related to higher Base Fuel Rate	 	 	185	 	 	 	113	 	
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate	 	 	(171	)	 	 	(104	)	
Non-fuel rate increase	 	 	6	 	 	 	4	 	
Net changes in fuel and purchased power costs related to price:	 	 	 	 	 	 	 	 	
Higher fuel and purchased power costs related to increased commodity prices	 	 	(121	)	 	 	(74	)	
Increased deferred fuel and purchased power costs related to increased prices	 	 	115	 	 	 	70	 	
Mark-to-market fuel and purchased power costs, net of related deferred fuel and purchased power costs	 	 	18	 	 	 	11	 	
Regulatory disallowance (see Note 3)	 	 	(14	)	 	 	(8	)	
Operations and maintenance increases primarily due to:	 	 	 	 	 	 	 	 	
Increased generation costs, including increased maintenance and overhauls and Palo Verde performance improvement plan	 	 	(25	)	 	 	(15	)	
Customer service and other costs	 	 	(19	)	 	 	(11	)	
Higher depreciation and amortization primarily due to increased plant balances	 	 	(12	)	 	 	(7	)	
Lower other income, net of expense, primarily due to lower interest income as a result of lower investment balances and miscellaneous asset sales in prior year	 	 	(7	)	 	 	(4	)	
Income tax benefits resolved in 2007 related to prior years	 	 	—	 	 	 	11	 	
Income tax credits resolved in 2006 related to prior years	 	 	—	 	 	 	(11	)	
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates	 	 	(7	)	 	 	(4	)	
Lower marketing and trading contribution primarily due to lower mark-to-market gains because of changes in forward prices	 	 	(7	)	 	 	(4	)	
Other miscellaneous items, net	 	 	2	 	 	 	(4	)	
 	 	 	 	 	 	 	
Increase in net income	 	$	26	 	 	$	14	 	
 	 	 	 	 	 	 	
          Electric operating revenues were $278 million higher for the year ended December 31, 2007 compared with the prior year primarily because of:

 	•	 	a $191 million increase in retail revenues due to a rate increase effective July 1, 2007;	
 		
 	•	 	a $60 million increase in retail revenues primarily related to customer growth, excluding weather effects;	
 		
 	•	 	a $50 million increase in retail revenues due to the effects of weather;	
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 	•	 	a $3 million increase in revenues from Off-System Sales due to higher prices and volumes;	
 		
 	•	 	a $35 million decrease in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see Note 3); and	
 		
 	•	 	a $9 million net increase due to miscellaneous factors.	
2006 Compared with 2005
          APS’ net income for 2006 was $270 million compared with $170 million for the comparable prior year. The $100 million increase was primarily due to an $84 million after-tax regulatory disallowance of plant costs recorded in 2005. Income also increased due to higher retail sales volumes due to customer growth; higher marketing and trading gross margin primarily due to higher mark-to-market gains; income tax credits related to prior years resolved in 2006; and increased other income due to higher interest income on higher investment balances. These positive factors were partially offset by higher operations and maintenance expense related to generation and customer service; higher depreciation and amortization primarily due to increased plant asset balances, partially offset by lower depreciation rates; and higher interest expense. In addition, higher fuel and purchased power costs of $74 million after-tax were partially offset by the deferral of $45 million after-tax costs in accordance with the PSA.
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          Additional details on the major factors that increased (decreased) net income for the year ended December 31, 2006 compared with the year ended December 31, 2005 are contained in the following table (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Increase (Decrease)	 	
 	 	Pretax	 	 	After Tax	 	
Higher fuel and purchased power costs (see Note 3)	 	$	(121	)	 	$	(74	)	
Higher retail sales volumes due to customer growth, excluding weather effects	 	 	87	 	 	 	53	 	
Increased deferred fuel and purchased power costs (deferrals began April 1, 2005)	 	 	73	 	 	 	45	 	
Absence of prior-year cost-based contract for PWEC Dedicated Assets (see Note 3)	 	 	56	 	 	 	34	 	
Higher marketing and trading gross margin primarily related to higher mark-to-market gains	 	 	20	 	 	 	12	 	
Regulatory disallowance of plant costs in 2005, in accordance with APS’ 2003 general retail rate case settlement	 	 	139	 	 	 	84	 	
Operations and maintenance increases primarily due to:	 	 	 	 	 	 	 	 	
Generation costs, including increased maintenance and overhauls	 	 	(41	)	 	 	(25	)	
Costs of PWEC Dedicated Assets not included in prior year	 	 	(18	)	 	 	(11	)	
Customer service costs, including regulatory demand-side management programs and planned maintenance	 	 	(16	)	 	 	(10	)	
Miscellaneous items, net	 	 	1	 	 	 	1	 	
Depreciation and amortization increases primarily due to:	 	 	 	 	 	 	 	 	
Higher depreciable assets due to transfer of PWEC Dedicated Assets (see Note 3)	 	 	(14	)	 	 	(8	)	
Higher other depreciable assets partially offset by lower depreciation rates	 	 	(14	)	 	 	(8	)	
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates	 	 	(14	)	 	 	(8	)	
Higher other income, net of expense, primarily due to miscellaneous asset sales and increased interest income on higher investment balances	 	 	9	 	 	 	5	 	
Income tax credits related to prior years resolved in 2006	 	 	—	 	 	 	11	 	
Miscellaneous items, net	 	 	(7	)	 	 	(1	)	
 	 	 	 	 	 	 	
Increase in net income	 	$	140	 	 	$	100	 	
 	 	 	 	 	 	 	
          Electric operating revenues were $388 million higher for 2006 compared with the prior year 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;	
 		
 	•	 	a $124 million increase in retail revenues related to customer growth, excluding weather effects; and	
 		
 	•	 	a $1 million decrease due to miscellaneous factors.	
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LIQUIDITY AND CAPITAL RESOURCES – ARIZONA PUBLIC SERVICE COMPANY
           Operating Cash Flows
          Net cash provided by operating activities was $766 million for 2007, compared with $394 million for 2006, an increase in net cash flow of $372 million. This change was primarily due to a decrease in 2007 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
          Net cash provided by operating activities was $394 million for 2006, compared with $722 million for 2005, a decrease in net cash flow of $328 million. This change was primarily due to an increase in 2006 in the amount of cash collateral and margin cash returned to counterparties as a result of changes in commodity prices.
          Investing Cash Flows
          Net cash used for investing activities was $881 million for 2007, compared with $714 million for 2006, a decrease in net cash flow of $167 million.
          This cash flow decrease was primarily due to:

 	•	 	An increase of $239 million in cash used for capital expenditures and allowance for borrowed funds used during construction (see table and discussion above).	
          The cash flow decrease was partially offset by:

 	•	 	A decrease of $65 million in cash invested in securities; and	

 	•	 	A net increase of $7 million due to miscellaneous factors.	
          Net cash used for investing activities was $714 million for 2006, compared with $645 million for 2005, a decrease in net cash flow of $69 million.
           This cash flow decrease was primarily due to:

 	•	 	A decrease of $500 million related to repayment in 2005 by PWEC of a loan;	

 	•	 	An increase of $214 million in cash invested in securities; and	

 	•	 	A net decrease of $1 million due to miscellaneous factors.	
          The cash flow decreases were partially offset by:

 	•	 	Less cash used for capital expenditures (including, in 2005, the acquisition of the PWEC Dedicated Assets and the Sundance Plant) and allowance for borrowed funds used during construction of $646 million (see table and discussion above).	
           Financing Cash Flows
          Net cash provided by financing activities was $86 million for 2007, compared with $352 million for 2006, a decrease in net cash flow of $266 million.
          The cash flow decrease was primarily due to:

 	•	 	A decrease of $311 million in net new long-term debt (issuances net of redemptions and refinancing) to fund APS’ construction program and for general corporate purposes; and	
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 	•	 	A decrease of $173 million due to decreased equity infusions from Pinnacle West.	
          The cash flow decreases were partially offset by:

 	•	 	A net increase of $218 million in short-term borrowings to fund day-to-day operations and liquidity needs.	
          Net cash provided by financing activities was $352 million for 2006, compared with net cash used for financing activities in 2005 of $76 million, an increase in net cash flow of $428 million.
          This cash flow increase was primarily due to:

 	•	 	An increase of $466 million in net new long-term debt issuances net of redemptions and refinancings in order to fund our construction program and for other general corporate purposes.	
          This cash flow increase was partially offset by:

 	•	 	A decrease of $37 million due to decreased equity infusions from Pinnacle West; and	

 	•	 	A net decrease of $1 million due to miscellaneous factors.	
           Liquidity
          For additional discussion see “Liquidity and Capital Resources – Pinnacle West Consolidated.”
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           Contractual Obligations
          The following table summarizes contractual requirements for APS as of December 31, 2007 (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	2009-	 	 	2011-	 	 	There-	 	 	 	 	
 	 	2008	 	 	2010	 	 	2012	 	 	after	 	 	Total	 	
Long-term debt payments, including interest (a)	 	$	158	 	 	$	537	 	 	$	1,038	 	 	$	3,135	 	 	$	4,868	 	
Short-term debt payments, including interest	 	 	219	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	219	 	
Purchased power and fuel commitments (b)	 	 	375	 	 	 	651	 	 	 	422	 	 	 	1,584	 	 	 	3,032	 	
Operating lease payments	 	 	72	 	 	 	136	 	 	 	124	 	 	 	177	 	 	 	509	 	
Nuclear decommissioning funding requirements	 	 	21	 	 	 	46	 	 	 	49	 	 	 	210	 	 	 	326	 	
Purchase obligations (c)	 	 	99	 	 	 	29	 	 	 	2	 	 	 	91	 	 	 	221	 	
Uncertain tax positions	 	 	198	 	 	 	12	 	 	 	—	 	 	 	—	 	 	 	210	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total contractual commitments	 	$	1,142	 	 	$	1,411	 	 	$	1,635	 	 	$	5,197	 	 	$	9,385	 	

			
(a)	 	The long-term debt matures at various dates through 2036 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by the rates at December 31, 2007 (see Note 6).	
 		
(b)	 	APS’ purchased power and fuel commitments include purchases of coal, electricity, natural gas, and nuclear fuel (see Note 11).	
 		
(c)	 	These contractual obligations include commitments for capital expenditures and other obligations.	

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ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
          See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risk.
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Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE
 	 	 	 	 	
 	 	Page	 	
Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)	 	 	74	 	
Report of Independent Registered Public Accounting Firm	 	 	75	 	
Pinnacle West Consolidated Statements of Income for 2007, 2006 and 2005	 	 	77	 	
Pinnacle West Consolidated Balance Sheets as of December 31, 2007 and 2006	 	 	78	 	
Pinnacle West Consolidated Statements of Cash Flows for 2007, 2006 and 2005	 	 	80	 	
Pinnacle West Consolidated Statements of Changes in Common Stock Equity for 2007, 2006 and 2005	 	 	81	 	
Notes to Pinnacle West’s Consolidated Financial Statements	 	 	82	 	
 	 	 	 	 	
Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)	 	 	129	 	
Report of Independent Registered Public Accounting Firm	 	 	130	 	
APS Statements of Income for 2007, 2006 and 2005	 	 	132	 	
APS Balance Sheets as of December 31, 2007 and 2006	 	 	133	 	
APS Statements of Cash Flows for 2007, 2006 and 2005	 	 	135	 	
APS Statements of Changes in Common Stock Equity for 2007, 2006 and 2005	 	 	136	 	
Supplemental Notes to APS’ Financial Statements	 	 	138	 	
 	 	 	 	 	
Financial Statement Schedules for 2007, 2006 and 2005	 	 	 	 	
Pinnacle West Schedule I – Condensed Statements of Income for 2007, 2006 and 2005	 	 	146	 	
Pinnacle West Schedule I – Condensed Balance Sheets as of December 31, 2007 and 2006	 	 	147	 	
Pinnacle West Schedule I – Condensed Statements of Cash Flows for 2007, 2006 and 2005	 	 	148	 	
Pinnacle West Schedule II – Reserve for Uncollectibles for 2007, 2006 and 2005	 	 	149	 	
APS Schedule II – Reserve for Uncollectibles for 2007, 2006 and 2005	 	 	150	 	
See Note 13 and S-2 for the selected quarterly financial data (unaudited) required to be presented in this Item.
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MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(PINNACLE WEST CAPITAL CORPORATION)
          Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2007. The effectiveness of our internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s consolidated financial statements.
February 27, 2008
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona
We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedules listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedules and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded
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as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As reflected in the consolidated statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’s Accounting for Defined Benefit Pension and Other Postretirement Plans” effective December 31, 2006.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 27, 2008
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
OPERATING REVENUES	 	 	 	 	 	 	 	 	 	 	 	 	
Regulated electricity segment	 	$	2,918,163	 	 	$	2,635,036	 	 	$	2,237,145	 	
Real estate segment	 	 	215,068	 	 	 	399,798	 	 	 	338,031	 	
Marketing and trading	 	 	342,371	 	 	 	330,742	 	 	 	351,558	 	
Other revenues	 	 	48,018	 	 	 	36,172	 	 	 	61,221	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	3,523,620	 	 	 	3,401,748	 	 	 	2,987,955	 	
 	 	 	 	 	 	 	 	 	 	
OPERATING EXPENSES	 	 	 	 	 	 	 	 	 	 	 	 	
Regulated electricity segment fuel and purchased power	 	 	1,140,923	 	 	 	960,649	 	 	 	595,141	 	
Real estate segment operations	 	 	193,926	 	 	 	324,861	 	 	 	278,366	 	
Marketing and trading fuel and purchased power	 	 	294,236	 	 	 	290,637	 	 	 	293,091	 	
Operations and maintenance	 	 	734,705	 	 	 	691,277	 	 	 	635,827	 	
Depreciation and amortization	 	 	373,436	 	 	 	358,644	 	 	 	347,652	 	
Taxes other than income taxes	 	 	128,218	 	 	 	128,395	 	 	 	132,040	 	
Other expenses	 	 	38,925	 	 	 	28,415	 	 	 	51,987	 	
Regulatory disallowance (Note 3)	 	 	—	 	 	 	—	 	 	 	138,562	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	2,904,369	 	 	 	2,782,878	 	 	 	2,472,666	 	
 	 	 	 	 	 	 	 	 	 	
OPERATING INCOME	 	 	619,251	 	 	 	618,870	 	 	 	515,289	 	
 	 	 	 	 	 	 	 	 	 	
OTHER	 	 	 	 	 	 	 	 	 	 	 	 	
Allowance for equity funds used during construction	 	 	21,195	 	 	 	14,312	 	 	 	11,191	 	
Other income (Note 19)	 	 	24,694	 	 	 	44,016	 	 	 	23,360	 	
Other expense (Note 19)	 	 	(25,883	)	 	 	(27,800	)	 	 	(26,716	)	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	20,006	 	 	 	30,528	 	 	 	7,835	 	
 	 	 	 	 	 	 	 	 	 	
INTEREST EXPENSE	 	 	 	 	 	 	 	 	 	 	 	 	
Interest charges	 	 	212,620	 	 	 	196,826	 	 	 	185,087	 	
Capitalized interest	 	 	(23,063	)	 	 	(20,989	)	 	 	(12,018	)	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	189,557	 	 	 	175,837	 	 	 	173,069	 	
 	 	 	 	 	 	 	 	 	 	
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	 	 	449,700	 	 	 	473,561	 	 	 	350,055	 	
INCOME TAXES (Note 4)	 	 	150,920	 	 	 	156,418	 	 	 	126,892	 	
 	 	 	 	 	 	 	 	 	 	
INCOME FROM CONTINUING OPERATIONS	 	 	298,780	 	 	 	317,143	 	 	 	223,163	 	
INCOME (LOSS) FROM DISCONTINUED OPERATIONS	 	 	 	 	 	 	 	 	 	 	 	 	
Net of income tax expense (benefit) of $5,572, $6,570 and ($29,797)	 	 	8,363	 	 	 	10,112	 	 	 	(46,896	)	
 	 	 	 	 	 	 	 	 	 	
NET INCOME	 	$	307,143	 	 	$	327,255	 	 	$	176,267	 	
 	 	 	 	 	 	 	 	 	 	
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC	 	 	100,256	 	 	 	99,417	 	 	 	96,484	 	
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED	 	 	100,835	 	 	 	100,010	 	 	 	96,590	 	
EARNINGS PER WEIGHTED – AVERAGE COMMON SHARE OUTSTANDING	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations – basic	 	$	2.98	 	 	$	3.19	 	 	$	2.31	 	
Net income – basic	 		3.06	 	 	 	3.29	 	 	 	1.83	 	
Income from continuing operations – diluted	 		2.96	 	 	 	3.17	 	 	 	2.31	 	
Net income – diluted	 		3.05	 	 	 	3.27	 	 	 	1.82	 	
DIVIDENDS DECLARED PER SHARE	 	$	2.10	 	 	$	2.025	 	 	$	1.925	 	
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2007	 	 	2006	 	
ASSETS	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
CURRENT ASSETS	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	56,321	 	 	$	87,210	 	
Investment in debt securities	 	 	—	 	 	 	32,700	 	
Customer and other receivables	 	 	456,007	 	 	 	501,628	 	
Allowance for doubtful accounts	 	 	(4,782	)	 	 	(5,597	)	
Materials and supplies (at average cost)	 	 	149,759	 	 	 	125,802	 	
Fossil fuel (at average cost)	 	 	27,792	 	 	 	21,973	 	
Deferred income taxes (Note 4)	 	 	31,510	 	 	 	982	 	
Assets from risk management and trading activities (Note 18)	 	 	97,373	 	 	 	641,040	 	
Home inventory (Note 1)	 	 	98,729	 	 	 	41,846	 	
Other current assets	 	 	34,738	 	 	 	27,078	 	
 	 	 	 	 	 	 	
Total current assets	 	 	947,447	 	 	 	1,474,662	 	

INVESTMENTS AND OTHER ASSETS	 	 	 	 	 	 	 	 	
Real estate investments – net (Notes 1 and 6)	 	 	532,600	 	 	 	526,008	 	
Assets from long-term risk management and trading activities (Note 18)	 	 	89,913	 	 	 	167,211	 	
Decommissioning trust accounts (Note 12)	 	 	379,347	 	 	 	343,771	 	
Other assets	 	 	117,941	 	 	 	111,388	 	
 	 	 	 	 	 	 	
Total investments and other assets	 	 	1,119,801	 	 	 	1,148,378	 	

PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)	 	 	 	 	 	 	 	 	
Plant in service and held for future use	 	 	11,640,739	 	 	 	11,154,919	 	
Less accumulated depreciation and amortization	 	 	4,004,944	 	 	 	3,797,475	 	
 	 	 	 	 	 	 	
Net	 	 	7,635,795	 	 	 	7,357,444	 	
Construction work in progress	 	 	625,577	 	 	 	368,284	 	
Intangible assets, net of accumulated amortization of $252,122 and $218,836	 	 	105,746	 	 	 	96,100	 	
Nuclear fuel, net of accumulated amortization of $68,375 and $50,741	 	 	69,271	 	 	 	60,100	 	
 	 	 	 	 	 	 	
Total property, plant and equipment	 	 	8,436,389	 	 	 	7,881,928	 	

DEFERRED DEBITS	 	 	 	 	 	 	 	 	
Deferred fuel and purchased power regulatory asset (Notes 1, 3 and 4)	 	 	110,928	 	 	 	160,268	 	
Other regulatory assets (Notes 1, 3 and 4)	 	 	514,353	 	 	 	686,016	 	
Other deferred debits	 	 	114,794	 	 	 	104,691	 	
 	 	 	 	 	 	 	
Total deferred debits	 	 	740,075	 	 	 	950,975	 	

TOTAL ASSETS	 	$	11,243,712	 	 	$	11,455,943	 	
 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2007	 	 	2006	 	
LIABILITIES AND COMMON STOCK EQUITY	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
CURRENT LIABILITIES	 	 	 	 	 	 	 	 	
Accounts payable	 	$	323,346	 	 	$	346,047	 	
Accrued taxes	 	 	269,628	 	 	 	263,935	 	
Accrued interest	 	 	39,836	 	 	 	48,746	 	
Short-term borrowings (Note 5)	 	 	340,661	 	 	 	35,750	 	
Current maturities of long-term debt (Note 6)	 	 	163,773	 	 	 	1,596	 	
Customer deposits	 	 	80,010	 	 	 	70,168	 	
Liabilities from risk management and trading activities (Note 18)	 	 	65,028	 	 	 	558,195	 	
Other current liabilities	 	 	102,685	 	 	 	134,123	 	
 	 	 	 	 	 	 	
Total current liabilities	 	 	1,384,967	 	 	 	1,458,560	 	

LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	 	 	3,127,125	 	 	 	3,232,633	 	

DEFERRED CREDITS AND OTHER	 	 	 	 	 	 	 	 	
Deferred income taxes (Note 4)	 	 	1,243,743	 	 	 	1,225,798	 	
Regulatory liabilities (Notes 1, 3 and 4)	 	 	642,564	 	 	 	635,431	 	
Liability for asset retirements (Note 12)	 	 	281,903	 	 	 	268,389	 	
Liabilities for pension and other postretirement benefits (Note 8)	 	 	504,603	 	 	 	588,852	 	
Liabilities from risk management and trading activities (Note 18)	 	 	45,686	 	 	 	171,170	 	
Unamortized gain – sale of utility plant (Note 9)	 	 	36,606	 	 	 	41,182	 	
Other	 	 	444,904	 	 	 	387,812	 	
 	 	 	 	 	 	 	
Total deferred credits and other	 	 	3,200,009	 	 	 	3,318,634	 	

COMMITMENTS AND CONTINGENCIES (SEE NOTES)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
COMMON STOCK EQUITY (Note 7)	 	 	 	 	 	 	 	 	
Common stock, no par value; authorized 150,000,000 shares; issued 100,525,470 at end of 2007 and 99,961,066 at end of 2006	 	 	2,135,787	 	 	 	2,114,550	 	
Treasury stock at cost; 39,505 shares at end of 2007 and 2,419 shares at end of 2006	 	 	(2,054	)	 	 	(449	)	
 	 	 	 	 	 	 	
Total common stock	 	 	2,133,733	 	 	 	2,114,101	 	
 	 	 	 	 	 	 	
Accumulated other comprehensive income (loss):	 	 	 	 	 	 	 	 	
Pension and other postretirement benefits (Note 8)	 	 	(39,336	)	 	 	(19,263	)	
Derivative instruments	 	 	23,473	 	 	 	31,531	 	
 	 	 	 	 	 	 	
Total accumulated other comprehensive income	 	 	(15,863	)	 	 	12,268	 	
 	 	 	 	 	 	 	
Retained earnings	 	 	1,413,741	 	 	 	1,319,747	 	
 	 	 	 	 	 	 	
Total common stock equity	 	 	3,531,611	 	 	 	3,446,116	 	

TOTAL LIABILITIES AND COMMON STOCK EQUITY	 	$	11,243,712	 	 	$	11,455,943	 	
 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
CASH FLOWS FROM OPERATING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	307,143	 	 	$	327,255	 	 	$	176,267	 	
Adjustments to reconcile net income to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Silverhawk impairment loss	 	 	—	 	 	 	—	 	 	 	91,025	 	
Regulatory disallowance	 	 	—	 	 	 	—	 	 	 	138,562	 	
Depreciation and amortization including nuclear fuel	 	 	403,896	 	 	 	386,760	 	 	 	381,604	 	
Deferred fuel and purchased power	 	 	(196,136	)	 	 	(252,849	)	 	 	(172,756	)	
Deferred fuel and purchased power amortization	 	 	231,106	 	 	 	265,337	 	 	 	—	 	
Deferred fuel and purchased power disallowance	 	 	14,370	 	 	 	—	 	 	 	—	 	
Allowance for equity funds used during construction	 	 	(21,195	)	 	 	(14,312	)	 	 	(11,191	)	
Deferred income taxes	 	 	(58,027	)	 	 	27,738	 	 	 	(23,806	)	
Change in mark-to-market valuations	 	 	17,579	 	 	 	28,464	 	 	 	(11,670	)	
Changes in current assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	
Customer and other receivables	 	 	62,850	 	 	 	9,189	 	 	 	(38,763	)	
Materials, supplies and fossil fuel	 	 	(29,776	)	 	 	(9,094	)	 	 	(16,836	)	
Other current assets	 	 	(10,040	)	 	 	(890	)	 	 	(6,815	)	
Accounts payable	 	 	(42,004	)	 	 	(46,055	)	 	 	(6,392	)	
Collateral	 	 	(44,853	)	 	 	(165,828	)	 	 	192,040	 	
Home inventory	 	 	(56,883	)	 	 	11,563	 	 	 	(21,400	)	
Accrued taxes	 	 	20,764	 	 	 	(22,329	)	 	 	43,624	 	
Other current liabilities	 	 	22,657	 	 	 	21,763	 	 	 	1,567	 	
Proceeds from the sale of real estate assets	 	 	82,521	 	 	 	34,990	 	 	 	16,218	 	
Real estate investments	 	 	(121,316	)	 	 	(126,229	)	 	 	(88,055	)	
Change in risk management and trading – liabilities	 	 	(14,450	)	 	 	(133,197	)	 	 	110,393	 	
Changes in unrecognized tax benefits	 	 	25,178	 	 	 	—	 	 	 	—	 	
Change in other long-term assets	 	 	17,390	 	 	 	20,330	 	 	 	(97,893	)	
Change in other long-term liabilities	 	 	47,162	 	 	 	30,896	 	 	 	74,573	 	
 	 	 	 	 	 	 	 	 	 	
Net cash flow provided by operating activities	 	 	657,936	 	 	 	393,502	 	 	 	730,296	 	

CASH FLOWS FROM INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(918,581	)	 	 	(737,779	)	 	 	(633,532	)	
Capitalized interest	 	 	(23,063	)	 	 	(20,990	)	 	 	(12,018	)	
Purchase of Sundance Plant	 	 	—	 	 	 	—	 	 	 	(185,046	)	
Proceeds from the sale of Silverhawk	 	 	—	 	 	 	207,620	 	 	 	—	 	
Purchases of investment securities	 	 	(36,525	)	 	 	(1,439,404	)	 	 	(2,962,278	)	
Proceeds from sale of investment securities	 	 	69,225	 	 	 	1,406,704	 	 	 	3,143,481	 	
Proceeds from nuclear decommissioning trust sales	 	 	259,026	 	 	 	254,651	 	 	 	186,215	 	
Investment in nuclear decommissioning trust	 	 	(279,768	)	 	 	(275,393	)	 	 	(204,633	)	
Proceeds from sale of real estate investments	 	 	58,139	 	 	 	39,621	 	 	 	82,719	 	
Other	 	 	(1,807	)	 	 	(3,763	)	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Net cash flow used for investing activities	 	 	(873,354	)	 	 	(568,733	)	 	 	(585,092	)	

CASH FLOWS FROM FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	 	 	
Issuance of long-term debt	 	 	230,571	 	 	 	757,636	 	 	 	1,088,815	 	
Repayment of long-term debt	 	 	(162,060	)	 	 	(527,864	)	 	 	(1,288,034	)	
Short-term borrowings and payments – net	 	 	304,911	 	 	 	9,911	 	 	 	(46,413	)	
Dividends paid on common stock	 	 	(210,473	)	 	 	(201,220	)	 	 	(186,677	)	
Common stock equity issuance	 	 	24,089	 	 	 	39,548	 	 	 	298,168	 	
Other	 	 	(2,509	)	 	 	30,427	 	 	 	(20,426	)	
 	 	 	 	 	 	 	 	 	 	
Net cash flow provided by (used for) financing activities	 	 	184,529	 	 	 	108,438	 	 	 	(154,567	)	

NET DECREASE IN CASH AND CASH EQUIVALENTS	 	 	(30,889	)	 	 	(66,793	)	 	 	(9,363	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	 	 	87,210	 	 	 	154,003	 	 	 	163,366	 	

CASH AND CASH EQUIVALENTS AT END OF YEAR	 	$	56,321	 	 	$	87,210	 	 	$	154,003	 	

Supplemental disclosure of cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	
Cash paid during the period for:	 	 	 	 	 	 	 	 	 	 	 	 	
Income taxes paid, net of refunds	 	$	204,643	 	 	$	157,245	 	 	$	86,711	 	
Interest paid, net of amounts capitalized	 	$	193,533	 	 	$	153,503	 	 	$	181,975	 	
See Notes to Pinnacle West’s Consolidated Financial Statements.
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PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
COMMON STOCK (Note 7)	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	$	2,114,550	 	 	$	2,067,377	 	 	$	1,769,047	 	
Issuance of common stock	 	 	24,089	 	 	 	39,420	 	 	 	298,330	 	
Other	 	 	(2,852	)	 	 	7,753	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Balance at end of year	 	 	2,135,787	 	 	 	2,114,550	 	 	 	2,067,377	 	

TREASURY STOCK (Note 7)	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	 	(449	)	 	 	(1,245	)	 	 	(428	)	
Purchase of treasury stock	 	 	(1,964	)	 	 	(229	)	 	 	(1,601	)	
Reissuance of treasury stock used for stock compensation, net	 	 	359	 	 	 	1,025	 	 	 	784	 	
 	 	 	 	 	 	 	 	 	 	
Balance at end of year	 	 	(2,054	)	 	 	(449	)	 	 	(1,245	)	

RETAINED EARNINGS	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	 	1,319,747	 	 	 	1,193,712	 	 	 	1,204,122	 	
Net income	 	 	307,143	 	 	 	327,255	 	 	 	176,267	 	
Common stock dividends	 	 	(210,473	)	 	 	(201,220	)	 	 	(186,677	)	
Cumulative effect of change in accounting for income taxes (Note 4)	 	 	(2,676	)	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Balance at end of year	 	 	1,413,741	 	 	 	1,319,747	 	 	 	1,193,712	 	

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	 	12,268	 	 	 	165,120	 	 	 	(22,545	)	
Pension and other postretirement benefits (Note 8):	 	 	 	 	 	 	 	 	 	 	 	 	
Unrealized actuarial loss, net of tax benefit of ($13,573)	 	 	(21,976	)	 	 	—	 	 	 	—	 	
Prior service cost, net of tax benefit of ($495)	 	 	(769	)	 	 	—	 	 	 	—	 	
Amortization to income:	 	 	 	 	 	 	 	 	 	 	 	 	
Actuarial loss, net of tax expense of $1,670	 	 	2,214	 	 	 	—	 	 	 	—	 	
Prior service cost, net of tax expense of $252	 	 	391	 	 	 	—	 	 	 	—	 	
Transition obligation, net of tax expense of $43	 	 	67	 	 	 	—	 	 	 	—	 	
Minimum pension liability adjustment, net of tax expense (benefit) of $28,425 and ($9,526)	 	 	—	 	 	 	44,086	 	 	 	(15,489	)	
Adjustment to reflect a change in accounting, net of tax expense of $22,412	 	 	—	 	 	 	33,928	 	 	 	—	 	
Derivative instruments:	 	 	 	 	 	 	 	 	 	 	 	 	
Net unrealized gain (loss), net of tax expense (benefit) of ($414), ($137,606) and $179,927	 	 	(785	)	 	 	(214,777	)	 	 	281,019	 	
Reclassification of net realized gain to income, net of tax benefit of ($4,679), ($10,308) and ($50,056)	 	 	(7,273	)	 	 	(16,089	)	 	 	(77,865	)	
 	 	 	 	 	 	 	 	 	 	
Balance at end of year	 	 	(15,863	)	 	 	12,268	 	 	 	165,120	 	

TOTAL COMMON STOCK EQUITY	 	$	3,531,611	 	 	$	3,446,116	 	 	$	3,424,964	 	

COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	307,143	 	 	$	327,255	 	 	$	176,267	 	
Other comprehensive income (loss)	 	 	(28,131	)	 	 	(186,780	)	 	 	187,665	 	
 	 	 	 	 	 	 	 	 	 	
Comprehensive income	 	$	279,012	 	 	$	140,475	 	 	$	363,932	 	
 	 	 	 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Consolidated Financial Statements.
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1. Summary of Significant Accounting Policies
Consolidation and Nature of Operations
     Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado, Pinnacle West Marketing & Trading, and Pinnacle West Energy (dissolved as of August 31, 2006). Significant intercompany accounts and transactions between the consolidated companies have been eliminated.
     APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. APSES provides energy-related projects and competitive commodity energy to commercial and industrial retail customers in competitive markets in the western United States. Recently, APSES has de-emphasized its commodity-related energy services. El Dorado is an investment firm. Pinnacle West Marketing & Trading began operations in early 2007. These operations were previously conducted by a division of Pinnacle West through the end of 2006.
Accounting Records and Use of Estimates
     Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Derivative Accounting
     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas and emissions allowances. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.
     We account for our derivative contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative instruments are either recognized periodically in income or, if certain hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). To the extent the amounts that would otherwise be recognized in income are eligible to be recovered through the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings. SFAS No. 133 provides a scope
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exception for contracts that meet the normal purchases and sales criteria specified in the standard. Contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. 
     Under fair value (mark-to-market) accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, as current or long-term assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets.
     We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted.
     When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers, which we convert into monthly prices using historical relationships.
     For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.
     For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks based on the financial condition of counterparties. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed-out or hedged.
     The credit valuation adjustment represents estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, local distribution companies and financial institutions. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty.
     The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio includes structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the ERMC.
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     See Note 2 for information about a new accounting standard on fair value measurements.
     See Note 18 for additional information about our derivative and energy trading accounting policies.
Regulatory Accounting
     APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers.
     Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings.
     A major component of our regulatory assets is the retail fuel and power costs deferred under the PSA. APS defers for future rate recovery or refund 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates, subject to specified parameters.
     The detail of regulatory assets is as follows (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2007	 	 	2006	 	
Pension and other postretirement benefits	 	$	338	 	 	$	473	 	
Deferred fuel and purchased power (a) (Note 3)	 	 	111	 	 	 	160	 	
Regulatory asset for deferred income taxes	 	 	40	 	 	 	27	 	
Deferred compensation	 	 	30	 	 	 	28	 	
Competition rules compliance charge (a)	 	 	25	 	 	 	34	 	
Loss on reacquired debt (b)	 	 	16	 	 	 	17	 	
Deferred fuel and purchased power – mark-to-market	 	 	7	 	 	 	62	 	
Other	 	 	58	 	 	 	45	 	
 	 	 	 	 	 	 	
Total regulatory assets (c)	 	$	625	 	 	$	846	 	

			
(a)	 	Subject to a carrying charge.	
 		
(b)	 	See “Reacquired Debt Costs” below.	
 		
(c)	 	There are no regulatory assets for which regulators have allowed recovery of costs but not allowed a return by exclusion from rate base.	
     The detail of regulatory liabilities is as follows (dollars in millions):
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 	 	December 31,	 	
 	 	2007	 	 	2006	 	
Removal costs (a)	 	$	392	 	 	$	387	 	
Regulatory liability related to asset retirement obligations	 	 	153	 	 	 	133	 	
Tax benefit of Medicare subsidy	 	 	35	 	 	 	50	 	
Deferred gains on utility property	 	 	20	 	 	 	20	 	
Deferred interest income (b)	 	 	13	 	 	 	18	 	
Regulatory liability for deferred income taxes	 	 	6	 	 	 	11	 	
Other	 	 	24	 	 	 	16	 	
 	 	 	 	 	 	 	
Total regulatory liabilities	 	$	643	 	 	$	635	 	

			
(a)	 	In accordance with SFAS No. 71, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.	
 		
(b)	 	Subject to a carrying charge.	
Utility Plant and Depreciation
     Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:

 	•	 	material and labor;	
 		
 	•	 	contractor costs;	
 		
 	•	 	capitalized leases;	
 		
 	•	 	construction overhead costs (where applicable); and	
 		
 	•	 	capitalized interest or an allowance for funds used during construction.	
     We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. See Note 12.
     APS records a regulatory liability for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount that has been recovered in regulated rates and the amount calculated under SFAS No. 143 “Accounting for Asset Obligations,” as interpreted by FIN 47. APS believes it can recover in regulated rates the costs calculated in accordance with SFAS No. 143.
     We record depreciation on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2007 were as follows:
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 	•	 	Fossil plant – 17 years;	
 		
 	•	 	Nuclear plant – 17 years;	
 		
 	•	 	Other generation – 29 years;	
 		
 	•	 	Transmission – 43 years;	
 		
 	•	 	Distribution – 33 years; and	
 		
 	•	 	Other – 6 years.	
     For the years 2005 through 2007, the depreciation rates ranged from a low of 1.11% to a high of 12.46%. The weighted-average rate was 3.11% for 2007, 3.14 % for 2006 and 3.0% for 2005. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 34 years.
Investments
     El Dorado accounts for its investments using either the equity method (if significant influence) or the cost method (if less than 20% ownership).
     Our investments in the nuclear decommissioning trust fund are accounted for in accordance with EITF 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments.” See Note 12 for more information on these investments.
Capitalized Interest
     Capitalized interest represents the cost of debt funds used to finance non-regulated construction projects. The rate used to calculate capitalized interest was a composite rate of 5.8% for 2007, 6.8% for 2006 and 5.7% for 2005. Capitalized interest ceases when construction is complete.
Allowance for Funds Used During Construction
     AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. APS’ allowance for borrowed funds is included in capitalized interest on the Consolidated Financial Statements. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
     AFUDC was calculated by using a composite rate of 8.2% for 2007, 8.0% for 2006 and 7.7% for 2005. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
Electric Revenues
     We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We
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exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Beginning April 2005, in accordance with a 2005 ACC order, we also exclude city franchise fees from both electric revenues and operating expenses.
     Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and purchased power and fuel costs.
     All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis.
Real Estate Revenues
     SunCor recognizes revenue from land, home and qualifying commercial operating assets sales in full, provided (a) the income is determinable, that is, the collectibility of the sales price is reasonably assured or the amount that will not be collectible can be estimated, and (b) the earnings process is virtually complete, that is, SunCor is not obligated to perform significant activities after the sale to earn the income. Unless both conditions exist, recognition of all or part of the income is postponed under the percentage of completion method per SFAS No. 66, “Accounting for Sales of Real Estate.” SunCor recognizes income only after the asset title has passed. Commercial property and management revenues are recorded over the term of the lease or period in which services are provided. In addition, see Note 22 – Discontinued Operations.
Real Estate Investments
     Real estate investments primarily include SunCor’s land, home inventory, commercial property and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except that, to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes and condos under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Homes under construction classified as “real estate investments” on the Consolidated Balance Sheets are transferred to “home inventory” upon completion of construction with the expectation that they will be sold in a timely manner. In previous years, “home inventory” was classified as “other current assets” on the Consolidated Balance Sheets. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting. In addition, see Note 22 – Discontinued Operations.
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Cash and Cash Equivalents
     We consider all highly liquid investments with a maturity of three months or less at acquisition to be cash equivalents.
     Investments in auction rate securities have interest rates that are reset on a short-term basis; however, the underlying contract maturity dates extend beyond three months. We classify the investments in auction rate securities as investment in debt securities on our Consolidated Balance Sheets.
Nuclear Fuel
     APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
     APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charges APS $0.001 per kWh of nuclear generation. See Note 11 for information on spent nuclear fuel disposal and Note 12 for information on nuclear decommissioning costs.
Income Taxes
     Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes” and FIN 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109.” We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax liability accounts reflect the tax and interest associated with management’s estimate of the most probable resolution of all known and measurable tax exposures. See Note 4.
Reacquired Debt Costs
     APS defers gains and losses incurred upon early retirement of debt. These costs are amortized equally on a monthly basis over the remaining life of the original debt consistent with its ratemaking treatment.
Stock-based Compensation
     Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and some of our subsidiaries. Effective January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment,” using the modified prospective application method. Because the fair value recognition provisions of both
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SFAS No. 123 and SFAS No. 123(R) are materially consistent with respect to our stock-based compensation plans, the adoption of SFAS No. 123(R) did not have a material impact on our financial statements. See Note 16.
Intangible Assets
     We have no goodwill recorded and have separately disclosed other intangible assets, primarily software, on Pinnacle West’s Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. Amortization expense was $37 million in 2007, $39 million in 2006 and $33 million in 2005. Estimated amortization expense on existing intangible assets over the next five years is $29 million in 2008, $20 million in 2009, $19 million in 2010, $12 million in 2011 and $10 million in 2012. At December 31, 2007, the weighted average remaining amortization period for intangible assets was 5 years.
2. New Accounting Standards
     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 us on January 1, 2008. We are currently evaluating this new guidance but do not expect it to have a material impact on our financial statements.
     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 this new guidance but do not expect it to have a material impact on our financial statements.
     In April 2007, the FASB issued FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FSP FIN 39-1). Under FSP FIN 39-1, a reporting entity is permitted to offset the fair value amounts recognized for cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. This new guidance is effective for us on January 1, 2008, with early application permitted. We are currently evaluating the impacts of FSP FIN 39-1 on our balance sheet. We do not expect the guidance to have an impact on our results of operations or cash flows.
     See Note 4 for a discussion of FIN 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007.
3. Regulatory Matters
      Retail Rate Order
      Retail Rate Increase On June 28, 2007, the ACC issued an order (the “Retail Rate Order”) in a general retail rate case that APS filed in late 2005. The Retail Rate Order approved a $322 million increase in APS’ annual retail base revenues, effective July 1, 2007, which included a $315
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million fuel-related increase and a $7 million non-fuel related increase. The Retail Rate Order also authorized APS’ recovery of approximately $34 million of 2005 Deferrals through a temporary PSA surcharge over a twelve-month period beginning July 1, 2007. The ACC disallowed approximately $14 million of 2005 Deferrals because it found the Palo Verde outage costs giving rise to those amounts resulted from APS’ imprudence.
      PSA Modifications The Retail Rate Order modified the PSA in various respects, effective July 1, 2007. The PSA, which the ACC initially approved in 2005 as a part of APS’ 2003 rate case, provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs. As modified by the Retail Rate Order, the PSA is subject to specified parameters and procedures, including the following:

 	•	 	APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate (currently $0.0325 per kWh);	
 		
 	•	 	under a 90/10 sharing arrangement, APS defers 90% of the difference between retail fuel and purchased power costs (excluding certain costs, such as renewable energy resources and the capacity components of long-term purchase power agreements acquired through competitive procurement) and the Base Fuel Rate; APS absorbs 10% of the retail fuel and purchased power costs above the Base Fuel Rate and retains 10% of the benefit from the retail fuel and purchased power costs that are below the Base Fuel Rate;	
 		
 	•	 	an adjustment is made annually each February 1 st and goes into effect automatically unless suspended by the ACC;	
 		
 	•	 	the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which will be reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);	
 		
 	•	 	the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) an “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component;	
 		
 	•	 	amounts to be recovered or refunded through the sum of the PSA components discussed in the preceding bullet point are limited to a maximum plus or minus $0.004 per kWh change in the PSA rate in any PSA Year; and	
 		
 	•	 	the PSA adjustor that took effect on February 1, 2007 ($0.004 per kWh), and that was scheduled to expire on January 31, 2008, will remain in effect as long as necessary after January 31, 2008 to collect $46 million of 2007 fuel and purchased power costs deferred as a result of the mid-2007 implementation of the new Base Fuel Rate.	
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      PSA Balance
     The following table shows the changes in the deferred fuel and purchased power regulatory asset for the years ended December 31, 2007 and 2006 (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	
Beginning balance	 	$	160	 	 	$	173	 	
Deferred fuel and purchased power costs-current period	 	 	189	 	 	 	244	 	
Regulatory disallowance	 	 	(14	)	 	 	—	 	
Interest on deferred fuel and purchased power	 	 	7	 	 	 	8	 	
Amounts recovered through revenues	 	 	(231	)	 	 	(265	)	
 	 	 	 	 	 	 	
Ending balance	 	$	111	 	 	$	160	 	
 	 	 	 	 	 	 	
     The PSA rate for the PSA Year beginning February 1, 2008 was set at the maximum $0.004 per kWh. Any uncollected deferrals during the 2008 PSA Year resulting from this limit will be included in the Historical Component of the PSA rate for the PSA Year beginning February 1, 2009.
      2006 Deferrals
     In May 2006, the ACC directed the ACC staff to conduct a “prudence audit” of 2006 Palo Verde outage costs. APS recorded approximately $79 million of 2006 Deferrals, virtually all of which were associated with a Unit 1 vibration issue. On October 4, 2007, the ACC staff filed a report with the ACC that concluded that APS’ response to the Unit 1 vibration issue was “reasonable and prudent.” APS continues to believe that these costs, which have been fully recovered, were prudently incurred.
      Line Extension Schedule
     The Retail Rate Order required APS to file a revised line extension schedule for ACC approval that would eliminate certain footage and equipment allowances for new or expanded electric service and remove any requirement for economic feasibility analyses used to determine whether or how much of an allowance should be granted. These changes would permit APS to collect, on a current basis, costs related to line extensions.
     On October 24, 2007, APS filed a proposed amendment to its line extension schedule, including a proposal to treat line extension payments received as non-refundable other electric revenues. APS proposed to “grandfather” applicants that have executed line extension agreements prior to the effective date of its amended line extension schedule. The ACC Staff issued a recommended order that was consistent with APS’ proposed line extension amendments in all significant respects except for the authorized accounting treatment. The ACC staff proposed that payments received for new or upgraded service be treated as contributions in aid of construction (“CIAC”), rather than as non-refundable other electric revenues as APS requested. CIAC treatment would result in a positive cash flow that will partially offset capital expenditures, but without any revenue impact. On February 13, 2008, the ACC voted to approve the ACC staff recommended order, with minor modifications.
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      Rate Requests for Transmission and Ancillary Services
     On July 10, 2007, APS submitted a revised Open Access Transmission Tariff filing with the FERC to move from a fixed rate to a formula rate in order to more accurately reflect the costs that APS incurs in providing transmission and ancillary services. The requested formula rate would have resulted in an estimated $37 million increase in annual transmission revenues, effective October 1, 2007. The proposed formula rate would be updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year, and projected capital expenditures. Approximately $30 million of the requested increase represents charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”).
     On September 21, 2007, the FERC issued an order on these proposed revisions to APS’ transmission rates in which it accepted APS’ proposed formula rates and ordered settlement judge procedures, which are underway. The proposed rates become effective March 1, 2008, subject to refund based upon the ultimate outcome of proceedings at the FERC on this matter.
     On December 31, 2007, APS filed with the ACC an application to increase annual pretax retail revenues by approximately $30 million, effective March 1, 2008, to cover the Retail Transmission Charges authorized by the FERC. This retail rate increase implements an ACC-approved mechanism by which changes in Retail Transmission Charges can be reflected in APS’ retail rates. On February 13, 2008, the ACC voted to approve APS’ request, subject to refund pending final outcome of FERC proceedings on this matter.
      Other
     On April 7, 2005, the ACC issued an order in the rate case that APS filed on June 27, 2003. As part of this order, APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and to rate base the PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base disallowance of approximately $150 million. Due to depreciation and other miscellaneous factors, the actual disallowance was $139 million at December 31, 2005. This transfer was completed on July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of approximately $84 million in 2005.
Federal
      FERC Order
     On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APSES (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.
     On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ authority to make sales at market-based rates in the APS control area (the “April 17 Order”). The
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FERC found that the Pinnacle West Companies failed to provide the necessary information about the calculation of transmission imports into the APS control area to allow the FERC to make a determination regarding FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.
     On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on October 12, 2007. This compliance filing was conditionally accepted by FERC in an order issued January 17, 2008, requiring an additional compliance filing by the Pinnacle West Companies by February 19, 2008.
     Based upon an analysis of this matter and preliminary calculations of the refund obligations, at this time neither Pinnacle West nor APS believes that this proceeding will have a material adverse effect on its financial position, results of operations or cash flows.
4. Income Taxes
     Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.
     APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.
     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next six months, we expect that the IRS will finalize its examination of the 2001 return, which will include a settlement on the tax accounting method change. Although the ultimate outcome of this matter cannot currently be predicted, the current status of the examination has resulted in changes in our judgment, which are reflected in the reconciliation of the total amounts of unrecognized tax benefits presented below. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows. We do not expect that there will be any other significant increases or decreases in our unrecognized tax benefits within the next 12 months.
     We adopted FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109,” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the
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guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.
     Following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period that are included in accrued taxes and other deferred credits on the Consolidated Balance Sheets (dollars in thousands):
 	 	 	 	 	
Total unrecognized tax benefits, January 1, 2007	 	$	132,691	 	
Additions for tax positions of the current year	 	 	—	 	
Additions for tax positions of prior years	 	 	65,022	 	
Reductions for tax positions of prior years for:	 	 	 	 	
Changes in judgment	 	 	(37,419	)	
Settlements with taxing authorities	 	 	(2,425	)	
Lapses of applicable statute of limitations	 	 	—	 	
 	 	 	 	
Total unrecognized tax benefits, December 31, 2007	 	$	157,869	 	
 	 	 	 	
     Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately $5 million of tax positions that, if recognized, would decrease our effective tax rate.
     We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of operations as income tax expense. For 2007, the amount of interest recognized in the statement of operations related to unrecognized tax benefits was $3 million.
     As of December 31, 2007, the total amount of interest expense recognized in the statement of financial position related to unrecognized tax benefits was $57 million. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
     As of December 31, 2007, the tax year ended December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ended prior to December 31, 1999 may remain subject to examination by state taxing authorities.
     The components of income tax expense are as follows (dollars in thousands):
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 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
Current:	 	 	 	 	 	 	 	 	 	 	 	 	
Federal	 	$	183,547	 	 	$	110,029	 	 	$	107,837	 	
State	 	 	30,972	 	 	 	21,507	 	 	 	13,064	 	
 	 	 	 	 	 	 	 	 	 	
Total current	 	 	214,519	 	 	 	131,536	 	 	 	120,901	 	
 	 	 	 	 	 	 	 	 	 	
Deferred:	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	 	(56,147	)	 	 	31,452	 	 	 	11,930	 	
Discontinued operations	 	 	(1,880	)	 	 	—	 	 	 	(35,736	)	
 	 	 	 	 	 	 	 	 	 	
Total deferred	 	 	(58,027	)	 	 	31,452	 	 	 	(23,806	)	
 	 	 	 	 	 	 	 	 	 	
Total income tax expense	 	 	156,492	 	 	 	162,988	 	 	 	97,095	 	
Less: income tax expense (benefit) on discontinued operations	 	 	5,572	 	 	 	6,570	 	 	 	(29,797	)	
 	 	 	 	 	 	 	 	 	 	
Income tax expense — continuing operations	 	$	150,920	 	 	$	156,418	 	 	$	126,892	 	
 	 	 	 	 	 	 	 	 	 	
     The following chart compares pretax income from continuing operations at the 35% federal income tax rate to income tax expense — continuing operations (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
Federal income tax expense at 35% statutory rate	 	$	157,395	 	 	$	165,746	 	 	$	122,519	 	
Increases (reductions) in tax expense resulting from:	 	 	 	 	 	 	 	 	 	 	 	 	
State income tax net of federal income tax benefit	 	 	16,964	 	 	 	17,309	 	 	 	11,981	 	
Credits and favorable adjustments related to prior years resolved in current year	 	 	(13,205	)	 	 	(14,028	)	 	 	—	 	
Medicare Subsidy Part-D	 	 	(3,236	)	 	 	(3,156	)	 	 	(2,733	)	
Allowance for equity funds used during construction (see Note 1)	 	 	(6,899	)	 	 	(4,679	)	 	 	(3,694	)	
Other	 	 	(99	)	 	 	(4,774	)	 	 	(1,181	)	
 	 	 	 	 	 	 	 	 	 	
Income tax expense — continuing operations	 	$	150,920	 	 	$	156,418	 	 	$	126,892	 	
 	 	 	 	 	 	 	 	 	 	
     The following table shows the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2007	 	 	2006	 	
Current asset	 	$	31,510	 	 	$	982	 	
Long-term liability	 	 	(1,243,743	)	 	 	(1,225,798	)	
 	 	 	 	 	 	 	
Accumulated deferred income taxes — net	 	$	(1,212,233	)	 	$	(1,224,816	)	
 	 	 	 	 	 	 	
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     The components of the net deferred income tax liability were as follows (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2007	 	 	2006	 	
DEFERRED TAX ASSETS	 	 	 	 	 	 	 	 	
Risk management and trading activities	 	$	43,358	 	 	$	280,152	 	
Regulatory liabilities:	 	 	 	 	 	 	 	 	
Asset retirement obligation	 	 	214,607	 	 	 	203,846	 	
Federal excess deferred income taxes	 	 	11,091	 	 	 	12,714	 	
Tax benefit of Medicare subsidy	 	 	11,727	 	 	 	18,214	 	
Other	 	 	26,579	 	 	 	27,283	 	
Pension and other postretirement liabilities	 	 	211,192	 	 	 	272,484	 	
Deferred gain on Palo Verde Unit 2 sale leaseback	 	 	14,408	 	 	 	16,160	 	
Other	 	 	112,209	 	 	 	73,811	 	
 	 	 	 	 	 	 	
Total deferred tax assets	 	 	645,171	 	 	 	904,664	 	
 	 	 	 	 	 	 	
DEFERRED TAX LIABILITIES	 	 	 	 	 	 	 	 	
Plant-related	 	 	(1,538,183	)	 	 	(1,509,812	)	
Risk management and trading activities	 	 	(58,931	)	 	 	(285,961	)	
Regulatory assets:	 	 	 	 	 	 	 	 	
Deferred fuel and purchased power	 	 	(43,661	)	 	 	(62,889	)	
Deferred fuel and purchased power -mark-to-market	 	 	(2,782	)	 	 	(24,427	)	
Pension and other postretirement benefits	 	 	(133,120	)	 	 	(185,602	)	
Other	 	 	(80,727	)	 	 	(60,789	)	
 	 	 	 	 	 	 	
Total deferred tax liabilities	 	 	(1,857,404	)	 	 	(2,129,480	)	
 	 	 	 	 	 	 	
Accumulated deferred income taxes — net	 	$	(1,212,233	)	 	$	(1,224,816	)	
 	 	 	 	 	 	 	
5. Lines of Credit and Short-Term Borrowings
     Pinnacle West had a committed line of credit with various banks totaling $300 million at December 31, 2007 and December 31, 2006, which was available either to support the issuance of up to $250 million in commercial paper or to be used for bank borrowings, including issuance of letters of credit. The current line terminates in December 2010. Pinnacle West had no outstanding borrowings under the lines of credit at December 31, 2007 and December 31, 2006. Pinnacle West had approximately $5 million of letters of credit issued under the line at December 31, 2007 and approximately $4 million of letters of credit issued under the line at December 31, 2006. The commitment fees were 0.15% in 2007 and 2006. Pinnacle West had commercial paper borrowings of $115 million outstanding at December 31, 2007 and $28 million outstanding at December 31, 2006. The weighted average interest rates were 5.73% at December 31, 2007 and 5.625% at December 31, 2006. All Pinnacle West and APS bank lines of credit and commercial paper agreements are unsecured.
     APS had two committed lines of credit with various banks totaling $900 million at December 2007 and 2006, all of which were available either to support the issuance of up to $250 million in
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commercial paper or to be used for bank borrowings, including the issuance of letters of credit. The $400 million line terminates in December 2010 and the $500 million line terminates in September 2011. APS may increase the $500 million line to $600 million if certain conditions are met. The commitment fees for these lines of credit were 0.10% and 0.11% at December 31, 2007 and December 31, 2006. APS had bank borrowings outstanding of $218 million under the $500 million line of credit at December 31, 2007 and no borrowings outstanding at December 31, 2006. The weighted average interest rate was 5.361% at December 31, 2007. APS had approximately $4 million of letters of credit issued under the $400 million line at December 31, 2007 and 2006.
     Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On October 30, 2007, the ACC issued a financing order in which it approved APS’ request, subject to specified parameters and procedures, to increase (a) APS’ short-term debt authorization from 7% of APS’ capitalization to (i) 7% of APS’ capitalization plus (ii) $500 million and (b) APS’ long-term debt authorization from approximately $3.2 billion to $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs.
     SunCor had two revolving lines of credit totaling $170 million at December 31, 2007, and December 31, 2006 maturing in October 2008 and December 2008. The commitment fees were 0.125% in 2007 and 2006 for the $150 million line of credit. The commitment fees for the $20 million line of credit were 0.50% in 2007 and 2006. SunCor had $94 million outstanding at December 31, 2007 and $118 million outstanding at December 31, 2006. The weighted-average interest rate was 7.27% at December 31, 2007 and 7.09% at December 31, 2006. Interest was based on LIBOR plus 2.0% for 2007 and 2006. The balance is included in current maturities of long-term debt on the Consolidated Balance Sheets at December 31, 2007 and 2006. SunCor had other short-term loans in the amount of $8 million at December 31, 2007 and $8 million at December 31, 2006. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2007 and 2006.
6. Long-Term Debt
     Substantially all of APS’ debt is unsecured. SunCor’s short and long-term debt is collateralized by interests in certain real property and Pinnacle West’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2007 and 2006 (dollars in thousands):
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 	 	 	 	 	 	 	 	 	 	December 31,	 	
 	 	Maturity	 	 	Interest	 	 	 	 	 	 	 	
 	 	Dates (a)	 	 	Rates	 	 	2007	 	 	2006	 	
APS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pollution control bonds	 	 	2024-2034	 	 	 	(b	)	 	$	565,855	 	 	$	565,855	 	
Pollution control bonds with senior notes	 	 	2029	 	 	 	5.05	%	 	 	90,000	 	 	 	90,000	 	
Unsecured notes	 	 	2011	 	 	 	6.375	%	 	 	400,000	 	 	 	400,000	 	
Unsecured notes	 	 	2012	 	 	 	6.50	%	 	 	375,000	 	 	 	375,000	 	
Unsecured notes	 	 	2033	 	 	 	5.625	%	 	 	200,000	 	 	 	200,000	 	
Unsecured notes	 	 	2015	 	 	 	4.650	%	 	 	300,000	 	 	 	300,000	 	
Unsecured notes	 	 	2014	 	 	 	5.80	%	 	 	300,000	 	 	 	300,000	 	
Secured note	 	 	2014	 	 	 	6.00	%	 	 	1,430	 	 	 	1,592	 	
Senior notes	 	 	2035	 	 	 	5.50	%	 	 	250,000	 	 	 	250,000	 	
Senior notes (c)	 	 	2016	 	 	 	6.25	%	 	 	250,000	 	 	 	250,000	 	
Senior notes (c)	 	 	2036	 	 	 	6.875	%	 	 	150,000	 	 	 	150,000	 	
Unamortized discount and premium	 	 	 	 	 	 	 	 	 	 	(8,883	)	 	 	(9,857	)	
Capitalized lease obligations	 	 	2007-2012	 	 	 	(d	)	 	 	4,457	 	 	 	5,880	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Subtotal (e)	 	 	 	 	 	 	 	 	 	 	2,877,859	 	 	 	2,878,470	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
SUNCOR	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes payable	 	 	2008-2013	 	 	 	(f	)	 	 	237,671	 	 	 	180,316	 	
Capitalized lease obligations	 	 	2007-2010	 	 	 	(g	)	 	 	368	 	 	 	328	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Subtotal	 	 	 	 	 	 	 	 	 	 	238,039	 	 	 	180,644	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
PINNACLE WEST	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior notes (h)	 	 	2011	 	 	 	5.91	%	 	 	175,000	 	 	 	175,000	 	
Capitalized lease obligations	 	 	2007	 	 	 	5.45	%	 	 	—	 	 	 	115	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Subtotal	 	 	 	 	 	 	 	 	 	 	175,000	 	 	 	175,115	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total long-term debt	 	 	 	 	 	 	 	 	 	 	3,290,898	 	 	 	3,234,229	 	
Less current maturities	 	 	 	 	 	 	 	 	 	 	163,773	 	 	 	1,596	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES	 	 	 	 	 	 	 	 	 	$	3,127,125	 	 	$	3,232,633	 	

			
(a)	 	This schedule does not reflect the timing of redemptions that may occur prior to maturity.	
 		
(b)	 	The weighted-average rate was 3.76% at December 31, 2007 and 3.77% at December 31, 2006. Changes in short-term interest rates would affect the costs associated with this debt. In addition, these amounts include $343 million of auction rate debt securities backed by insurance at December 31, 2007 and 2006.	
 		
(c)	 	On August 3, 2006, APS issued $250 million 6.25% notes due 2016 and $150 million 6.875% notes due 2036. A portion of the proceeds was used to repay outstanding commercial paper balances and $84 million of its 6.75% senior note that matured November 15, 2006. The remainder has been used to fund its construction program and other general corporate purposes.	
 		
(d)	 	The weighted-average interest rate was 5.51% at December 31, 2007 and 6.20% at December 31, 2006.	
 		
(e)	 	APS’ long-term debt less current maturities was $2.877 billion at December 31, 2007 and $2.878 billion at December 31, 2006. APS’ current maturities of long-term debt were $1 million at December 31, 2007 and 2006.	
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(f)	 	SunCor had $94 million outstanding at December 31, 2007 under its revolving lines of credit. The weighted-average interest rate was 7.27% at December 31, 2007. The remaining amount of approximately $143 million at December 31, 2007 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 1.7%, 2.0% and 2.25%. SunCor had $118 million outstanding at December 31, 2006 under its revolving line of credit. The weighted-average interest rate was 7.08% at December 31, 2006. The remaining amount of approximately $62 million at December 31, 2006 was made up of multiple notes with variable interest rates based on the lenders’ prime rates plus 1.75% and 2.0% or LIBOR plus 2.25%. There is also a note at a fixed rate of 4.25% at December 31, 2007 and 2006	
 		
(g)	 	The weighted-average interest rate was 7.0% at December 31, 2007 and 6.25% at December 31, 2006.	
 		
(h)	 	On February 28, 2006, Pinnacle West entered into a $200 million Senior Notes Uncommitted Master Shelf Agreement with Prudential Investment Management Inc. (“Prudential”). Under the terms of the agreement, Pinnacle West may offer up to $200 million of its senior notes for purchase by Prudential at any time prior to December 31, 2007. The maturity of the notes cannot exceed five years. On February 28, 2006, Pinnacle West issued $175 million of its 5.91% senior notes, series A, to Prudential.	
     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization cannot exceed 65%. At December 31, 2007, the ratio was approximately 50% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 4.7 times under APS’ bank financing agreements as of December 31, 2007. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.
     Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank financing agreements contain a pricing grid in which interest costs we pay are determined by our current credit ratings.
     All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.
     An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At December 31, 2007, APS’ common equity ratio, as defined, was 54%, its total common equity was approximately $3.4
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billion, and total capitalization was approximately $6.2 billion. APS would be prohibited from paying dividends if the payment would reduce its common equity below approximately $2.5 billion, assuming APS’ total capitalization remains the same.
     SunCor has a $150 million loan facility secured primarily by an interest in land, commercial properties, land contracts and homes under construction. The loan facility requires compliance with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow coverage and restrictions on debt. As of December 31, 2007, the amount of SunCor’s net assets that could not be transferred to Pinnacle West in the form of cash dividends as a result of these covenants was approximately $217 million.
     As a result of the restrictions in the preceding two paragraphs, as of December 31, 2007, the restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at December 31, 2007, our consolidated net assets were approximately $3.5 billion). These restrictions do not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.
     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions):
 	 	 	 	 	 	 	 	 	
Year	 	Pinnacle West	 	 	APS	 	
2008	 	$	164	 	 	$	1	 	
2009	 	 	72	 	 	 	1	 	
2010	 	 	224	 	 	 	224	 	
2011	 	 	578	 	 	 	401	 	
2012	 	 	376	 	 	 	376	 	
Thereafter	 	 	1,886	 	 	 	1,884	 	
 	 	 	 	 	 	 	
Total	 	$	3,300	 	 	$	2,887	 	
 	 	 	 	 	 	 	
7. Common Stock and Treasury Stock
     Our common stock and treasury stock activity during each of the three years 2007, 2006 and 2005 is as follows (dollars in thousands):
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 	 	Common Stock	 	 	Treasury Stock	 	
 	 	Shares	 	 	Amount	 	 	Shares	 	 	Amount	 	
Balance at December 31, 2004	 	 	91,802,861	 	 	$	1,769,047	 	 	 	(9,522	)	 	$	(428	)	
Common stock issuance (a)	 	 	7,274,272	 	 	 	298,330	 	 	 	—	 	 	 	—	 	
Purchase of treasury stock (b)	 	 	—	 	 	 	—	 	 	 	(28,124	)	 	 	(1,601	)	
Reissuance of treasury stock for stock compensation (net)	 	 	—	 	 	 	—	 	 	 	17,588	 	 	 	784	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2005	 	 	99,077,133	 	 	 	2,067,377	 	 	 	(20,058	)	 	 	(1,245	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common stock issuance	 	 	883,933	 	 	 	39,420	 	 	 	—	 	 	 	—	 	
Purchase of treasury stock (b)	 	 	—	 	 	 	—	 	 	 	(5,505	)	 	 	(229	)	
Reissuance of treasury stock for stock compensation (net)	 	 	—	 	 	 	—	 	 	 	23,144	 	 	 	1,025	 	
Other	 	 	—	 	 	 	7,753	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2006	 	 	99,961,066	 	 	 	2,114,550	 	 	 	(2,419	)	 	 	(449	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common stock issuance	 	 	564,404	 	 	 	24,089	 	 	 	—	 	 	 	—	 	
Purchase of treasury stock (b)	 	 	—	 	 	 	—	 	 	 	(47,218	)	 	 	(1,964	)	
Reissuance of treasury stock for stock compensation (net)	 	 	—	 	 	 	—	 	 	 	10,132	 	 	 	359	 	
Other	 	 	—	 	 	 	(2,852	)	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at December 31, 2007	 	 	100,525,470	 	 	$	2,135,787	 	 	 	(39,505	)	 	$	(2,054	)	

			
(a)	 	On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the net proceeds for general corporate purposes, including making capital contributions to APS, which, in turn, used such funds to pay a portion of the approximately $190 million purchase price to acquire the Sundance Plant and for other capital expenditures incurred to meet the growing needs of APS’ service territory.	
 		
(b)	 	Represents shares of common stock withheld from certain stock awards for tax purposes.	
8. Retirement Plans and Other Benefits
     Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.
     We also sponsor other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age.
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For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.
     Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. The fair market value of investments in our retirement and postretirement plans is determined using actively-quoted prices when available. When actively-quoted prices are not available, we use prices provided by external sources, models or other valuation methods. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through the application of these methods.
     A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans are attributable to APS and therefore are recoverable in rates. Accordingly these changes are recorded as a regulatory asset.
     The following table provides details of the plans’ benefit costs. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension	 	 	Other Benefits	 	
 	 	2007	 	 	2006	 	 	2005	 	 	2007	 	 	2006	 	 	2005	 	
Service cost-benefits earned during the period	 	$	51,803	 	 	$	47,287	 	 	$	45,027	 	 	$	18,491	 	 	$	19,968	 	 	$	20,913	 	
Interest cost on benefit obligation	 	 	100,736	 	 	 	92,196	 	 	 	87,189	 	 	 	35,284	 	 	 	34,653	 	 	 	34,223	 	
Expected return on plan assets	 	 	(107,165	)	 	 	(95,912	)	 	 	(88,403	)	 	 	(42,177	)	 	 	(36,930	)	 	 	(30,471	)	
Amortization of:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Transition (asset) obligation	 	 	—	 	 	 	(645	)	 	 	(3,227	)	 	 	3,005	 	 	 	3,005	 	 	 	3,005	 	
Prior service cost (credit)	 	 	2,957	 	 	 	2,401	 	 	 	2,401	 	 	 	(125	)	 	 	(125	)	 	 	(125	)	
Net actuarial loss	 	 	16,331	 	 	 	23,366	 	 	 	19,810	 	 	 	3,929	 	 	 	8,662	 	 	 	9,243	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net periodic benefit cost	 	$	64,662	 	 	$	68,693	 	 	$	62,797	 	 	$	18,407	 	 	$	29,233	 	 	$	36,788	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Portion of cost charged to expense	 	$	28,063	 	 	$	30,912	 	 	$	26,375	 	 	$	7,989	 	 	$	13,155	 	 	$	15,451	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
APS share of costs charged to expense	 	$	26,548	 	 	$	29,203	 	 	$	24,169	 	 	$	7,557	 	 	$	12,428	 	 	$	14,159	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     The following table shows the plans’ changes in the benefit obligations and funded status for the years 2007 and 2006 (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension	 	 	Other Benefits	 	
 	 	2007	 	 	2006	 	 	2007	 	 	2006	 	
Change in Benefit Obligation	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Benefit obligation at January 1	 	$	1,670,274	 	 	$	1,596,068	 	 	$	616,985	 	 	$	585,678	 	
Service cost	 	 	51,803	 	 	 	47,287	 	 	 	18,491	 	 	 	19,968	 	
Interest cost	 	 	100,736	 	 	 	92,196	 	 	 	35,284	 	 	 	34,653	 	
Benefit payments	 	 	(52,168	)	 	 	(49,189	)	 	 	(17,763	)	 	 	(16,439	)	
Actuarial gains	 	 	(52,227	)	 	 	(19,588	)	 	 	(47,872	)	 	 	(6,875	)	
Plan amendments	 	 	2,426	 	 	 	3,500	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Benefit obligation at December 31	 	 	1,720,844	 	 	 	1,670,274	 	 	 	605,125	 	 	 	616,985	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in Plan Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at January 1	 	$	1,214,229	 	 	$	1,064,848	 	 	$	480,638	 	 	$	416,174	 	
Actual return on plan assets	 	 	101,138	 	 	 	148,895	 	 	 	26,952	 	 	 	47,988	 	
Employer contributions	 	 	52,000	 	 	 	46,500	 	 	 	18,407	 	 	 	29,233	 	
Benefit payments	 	 	(48,428	)	 	 	(46,014	)	 	 	(26,233	)	 	 	(12,757	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at December 31	 	 	1,318,939	 	 	 	1,214,229	 	 	 	499,764	 	 	 	480,638	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded Status at December 31	 	$	(401,905	)	 	$	(456,045	)	 	$	(105,361	)	 	$	(136,347	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
     The following table shows the projected benefit obligation and the accumulated benefit obligation for the pension plan in excess of plan assets as of December 31, 2007 and 2006 (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	2007	 	2006	
Projected benefit obligation	 	$	1,720,844	 	 	$	1,670,274	 	
Accumulated benefit obligation	 	 	1,484,444	 	 	 	1,426,492	 	
Fair value of plan assets	 	 	1,318,939	 	 	 	1,214,229	 	
     The following table shows the amounts recognized on the Consolidated Balance Sheets as of December 31, 2007 and 2006 (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension	 	 	Other Benefits	 	
 	 	2007	 	 	2006	 	 	2007	 	 	2006	 	
Current asset	 	$	—	 	 	$	—	 	 	$	1,321	 	 	$	—	 	
Current liability	 	 	(3,984	)	 	 	(3,540	)	 	 	—	 	 	 	—	 	
Noncurrent liability	 	 	(397,921	)	 	 	(452,505	)	 	 	(106,682	)	 	 	(136,347	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net amount recognized	 	$	(401,905	)	 	$	(456,045	)	 	$	(105,361	)	 	$	(136,347	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
     The following table shows the details related to accumulated other comprehensive loss before income taxes as of December 31, 2007 and 2006 (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension	 	 	Other Benefits	 	
 	 	2007	 	 	2006	 	 	2007	 	 	2006	 	
Net actuarial loss	 	$	268,532	 	 	$	331,054	 	 	$	106,407	 	 	$	143,079	 	
Prior service cost (credit)	 	 	12,401	 	 	 	12,932	 	 	 	(1,045	)	 	 	(1,171	)	
Transition obligation	 	 	—	 	 	 	—	 	 	 	15,024	 	 	 	18,029	 	
APS’ portion recorded as a regulatory asset	 	 	(221,787	)	 	 	(318,461	)	 	 	(116,425	)	 	 	(154,531	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Accumulated other comprehensive loss	 	$	59,146	 	 	$	25,525	 	 	$	3,961	 	 	$	5,406	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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     The following table shows the estimated amounts that will be amortized from accumulated other comprehensive loss and regulatory assets into net periodic benefit cost in 2008 (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Other	 	
 	 	Pension	 	 	Benefits	 	
Net actuarial loss	 	$	9,048	 	 	$	4,042	 	
Prior service cost (credit)	 	 	2,455	 	 	 	(125	)	
Transition obligation	 	 	—	 	 	 	3,005	 	
 	 	 	 	 	 	 	
Total amounts estimated to be amortized from accumulated other comprehensive income and regulatory assets in 2008	 	$	11,503	 	 	$	6,922	 	
 	 	 	 	 	 	 	
     The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Benefit Costs	
 	 	Benefit Obligations	 	For the Years Ended	
 	 	As of December 31,	 	December 31,	
 	 	2007	 	2006	 	2007	 	2006	
Discount rate-pension	 	 	6.25	%	 	 	5.90	%	 	 	5.90	%	 	 	5.66	%	
Discount rate-other benefits	 	 	6.31	%	 	 	5.93	%	 	 	5.93	%	 	 	5.68	%	
Rate of compensation increase	 	 	4.00	%	 	 	4.00	%	 	 	4.00	%	 	 	4.00	%	
Expected long-term return on plan assets	 	 	N/A	 	 	 	N/A	 	 	 	9.00	%	 	 	9.00	%	
Initial health care cost trend rate	 	 	8.00	%	 	 	8.00	%	 	 	8.00	%	 	 	8.00	%	
Ultimate health care cost trend rate	 	 	5.00	%	 	 	5.00	%	 	 	5.00	%	 	 	5.00	%	
Year ultimate health care trend rate is reached	 	 	2012	 	 	 	2011	 	 	 	2011	 	 	 	2010	 	
     In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2008, we are assuming a 9% long-term rate of return on plan assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.
     Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one percentage point change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions):
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 	 	1% Increase	 	1% Decrease	
Effect on other postretirement benefits expense, after consideration of amounts capitalized or billed to electric plant participants	 	$	7	 	 	$	(5	)	
Effect on service and interest cost components of net periodic other postretirement benefit costs	 	 	10	 	 	 	(8	)	
Effect on the accumulated other postretirement benefit obligation	 	 	94	 	 	 	(76	)	
Plan Assets
     Pinnacle West’s qualified pension plan and other postretirement benefit plans’ asset allocation at December 31, 2007 and 2006 is as follows:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension	 	Other Benefits	
Asset Category:	 	2007	 	2006	 	Target	 	2007	 	2006	 	Target	
Equity securities	 	 	68	%	 	 	69	%	 	 	68	%	 	 	70	%	 	 	74	%	 	 	70	%	
Fixed income	 	 	25	 	 	 	25	 	 	 	25	 	 	 	28	 	 	 	25	 	 	 	27	 	
Other	 	 	7	 	 	 	6	 	 	 	7	 	 	 	2	 	 	 	1	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	 	100	%	 	 	100	%	 	 	100	%	 	 	100	%	 	 	100	%	 	 	100	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     The Board of Directors has delegated oversight of the plan assets to an Investment Management Committee. The investment policy sets forth the objective of providing for future pension benefits by maximizing return consistent with acceptable levels of risk. The primary investment strategies are diversification of assets, stated asset allocation targets and ranges, prohibition of investments in Pinnacle West securities, and external management of plan assets.
     The Investment Management Committee, described above, has also been delegated oversight of the plan assets for the other postretirement benefit plans. The investment policy for other postretirement benefit plans’ assets is similar to that of the pension plan assets described above.
Contributions
     The contribution to our pension plan in 2008 is estimated to be approximately $50 million. The contribution to our other postretirement benefit plans in 2008 is estimated to be approximately $20 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.
Estimated Future Benefit Payments
     Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter are estimated to be as follows (dollars in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	
Year	 	Pension	 	Other Benefits (a)	
2008	 	$	60,536	 	 	$	19,315	 	
2009	 	 	66,799	 	 	 	21,246	 	
2010	 	 	73,624	 	 	 	23,846	 	
2011	 	 	82,764	 	 	 	26,579	 	
2012	 	 	93,371	 	 	 	29,293	 	
Years 2013-2017	 	 	639,326	 	 	 	194,680	 	

(a)	 	The expected future other benefit payments take into account the Medicare Part D subsidy.	
Employee Savings Plan Benefits
     Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2007, costs related to APS’ employees represented 97% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. At December 31, 2007, approximately 15% of total plan assets were in Pinnacle West stock. Pinnacle West recorded expenses for this plan of approximately $7 million for 2007, $6 million for 2006 and $6 million for 2005. APS recorded expenses for this plan of approximately $6 million in 2007, $6 million in 2006 and $6 million in 2005.
9. Leases
     In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The gain resulting from the transaction of approximately $140 million was deferred and is being amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases and to purchase the property for fair market value at the end of the lease terms. Rent expense is calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the VIE’s involved in the Palo Verde sale leaseback transactions.
     In addition, we lease certain land, buildings, equipment, vehicles and miscellaneous other items through operating rental agreements with varying terms, provisions and expiration dates.
     Total lease expense recognized in the Consolidated Statements of Income was $73 million in 2007, $72 million in 2006 and $71 million in 2005. APS’ lease expense was $66 million in 2007, $64 million in 2006 and $58 million in 2005.
     The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2008 to 2015.
     Estimated future minimum lease payments for Pinnacle West’s and APS’ operating leases, excluding purchase power agreements, are approximately as follows (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	
 	 	Pinnacle West	 	 	 	 	
Year	 	Consolidated	 	 	APS	 	
2008	 	$	79	 	 	$	72	 	
2009	 	 	75	 	 	 	69	 	
2010	 	 	73	 	 	 	67	 	
2011	 	 	68	 	 	 	63	 	
2012	 	 	65	 	 	 	61	 	
Thereafter	 	 	195	 	 	 	177	 	
 	 	 	 	 	 	 	
Total future lease commitments	 	$	555	 	 	$	509	 	
 	 	 	 	 	 	 	
10. Jointly-Owned Facilities
     APS shares ownership of some of its generating and transmission facilities with other companies. Our share of operations and maintenance expense and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’ interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2007 (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Construction	
 	 	Percent	 	Plant in	 	Accumulated	 	Work in	
 	 	Owned	 	Service	 	Depreciation	 	Progress	
Generating facilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Palo Verde Units 1 and 3	 	 	29.1	%	 	$	1,939,389	 	 	$	1,038,432	 	 	$	132,618	 	
Palo Verde Unit 2 (see Note 9)	 	 	17.0	%	 	 	672,564	 	 	 	303,638	 	 	 	16,630	 	
Four Corners Units 4 and 5	 	 	15.0	%	 	 	182,052	 	 	 	99,127	 	 	 	12,345	 	
Navajo Generating Station Units 1, 2 and 3	 	 	14.0	%	 	 	255,592	 	 	 	142,144	 	 	 	1,855	 	
Cholla common facilities (a)	 	 	63.9	%(b)	 	 	91,636	 	 	 	49,741	 	 	 	31,692	 	
Transmission facilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
ANPP500KV System	 	 	35.8	%(b)	 	 	79,515	 	 	 	24,001	 	 	 	4,399	 	
Navajo Southern System	 	 	31.4	%(b)	 	 	38,935	 	 	 	12,665	 	 	 	5,575	 	
Palo Verde — Yuma 500KV System	 	 	23.9	%(b)	 	 	9,230	 	 	 	3,857	 	 	 	3,427	 	
Four Corners Switchyards	 	 	27.5	%(b)	 	 	3,198	 	 	 	1,304	 	 	 	—	 	
Phoenix — Mead System	 	 	17.1	%(b)	 	 	36,032	 	 	 	4,823	 	 	 	—	 	
Palo Verde — Estrella 500KV System	 	 	55.5	%(b)	 	 	74,318	 	 	 	3,990	 	 	 	—	 	
Harquahala	 	 	80.0	%(b)	 	 	—	 	 	 	—	 	 	 	6,418	 	

(a)	 	PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned.	
 		
(b)	 	Weighted average of interests.	
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11. Commitments and Contingencies
Palo Verde Nuclear Generating Station
      Spent Nuclear Fuel and Waste Disposal
     Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim.
     APS currently estimates it will incur $147 million (in 2007 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At December 31, 2007, APS had a regulatory liability of $11 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.
      Nuclear Insurance
     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $15 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $13 million.
     The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $21.1 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
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Fuel and Purchased Power Commitments
     Pinnacle West and APS are parties to various fuel and purchased power contracts with terms expiring between 2008 and 2025 that include required purchase provisions. Pinnacle West estimates the contract requirements to be approximately $418 million in 2008; $358 million in 2009; $293 million in 2010; $218 million in 2011; $216 million in 2012; and $1.6 billion thereafter. APS estimates the contract requirements to be approximately $375 million in 2008; $358 million in 2009; $293 million in 2010; $212 million in 2011; $210 million in 2012; and $1.6 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
     Of the various fuel and purchased power contracts mentioned above some of those contracts have take-or-pay provisions. The contracts APS has for its coal supply include take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2024.
     The following table summarizes our actual and estimated take-or-pay commitments (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Actual	 	Estimated (a)	
 	 	2005	 	2006	 	2007	 	2008	 	2009	 	2010	 	2011	 	2012	 	Thereafter	
Coal take-or-pay commitments	 	$	48	 	 	$	67	 	 	$	70	 	 	$	81	 	 	$	97	 	 	$	75	 	 	$	77	 	 	$	78	 	 	$	476	 	

(a)	 	Total take-or-pay commitments are approximately $884 million. The total net present value of these commitments is approximately $588 million.	
Coal Mine Reclamation Obligations
     APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. APS’ coal mine reclamation obligation was approximately $91 million at December 31, 2007 and $75 million at December 31, 2006 and is included in Deferred Credits and Other on the Consolidated Balance Sheets.
California Energy Market Issues and Refunds in the Pacific Northwest
      FERC
     In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue and, to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006,
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the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope and the type of transactions that are properly subject to the refund orders. In the decision, the Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it potentially to include additional transactions, remanding the orders to the FERC for further proceedings. Various parties filed petitions for rehearing on this order. In addition, on December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings, specifically addressing the application of the so-called “just and reasonable” standard as opposed to the “public interest” standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement that the FERC review the refund matter using the appropriate standard of review. Several parties sought rehearing of this decision at the Ninth Circuit. Like the August 2, 2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the existing FERC refund proceedings. We currently believe the refund claims at the FERC will have no material adverse impact on our financial position, results of operations or cash flows.
     On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC, and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31, 2006. On December 28, 2006, certain parties petitioned the Supreme Court for a writ of certiorari. This petition was denied on June 18, 2007. The Ninth Circuit issued the mandate for this proceeding on December 4, 2007. The outcome of the further proceedings cannot be predicted at this time.
     On July 25, 2001, the FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Petitions for rehearing of this opinion were filed on December 17, 2007. Although the FERC ruling in this matter is being appealed and the FERC has not yet calculated the specific refund amounts at issue, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.
     On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing
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the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.
Navajo Nation Litigation
     In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.
     In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. APS cannot currently predict the outcome of this matter.
Superfund
     Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.
Salt River Project
     Salt River Project has notified APS that Salt River Project allegedly failed to bill APS for (a) energy losses under certain service schedules of a power contract between the parties and (b) certain other charges under the contract. Salt River Project asserts that certain of these failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims that APS owes it approximately $29 million. APS disputes that it is required to pay these amounts. No lawsuit or litigation has been initiated in the matter at this time. We do not expect that resolution of this matter will have a material adverse impact on our financial position, results of operations, or cash flows.
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Litigation
     We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial position, results of operations or cash flows.
12. Asset Retirement Obligations
     APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term.
     Some of APS’ transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.
     Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites. The generation sites are strategically located to serve APS Native Load customers. Management expects to continuously use the sites and, thus, cannot estimate a potential closure date. The asset retirement obligations associated with our non-regulated assets are immaterial.
     The following schedule shows the change in our asset retirement obligations for 2007 and 2006 (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	
Asset retirement obligations at the beginning of year	 	$	268	 	 	$	269	 	
Changes attributable to:	 	 	 	 	 	 	 	 	
Liabilities settled	 	 	(2	)	 	 	(2	)	
Accretion expense	 	 	20	 	 	 	19	 	
Estimated cash flow revisions	 	 	(4	)	 	 	(18	)	
 	 	 	 	 	 	 	
Asset retirement obligations at the end of year	 	$	282	 	 	$	268	 	
 	 	 	 	 	 	 	
     In accordance with SFAS No. 71, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 1.
     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in
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fixed income securities and domestic equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we record the decommissioning trust funds at their fair value on our Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, we have recorded the offsetting amount of gains on investment securities in other regulatory liabilities or assets . The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at December 31, 2007 and December 31, 2006 (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Total	 	
 	 	 	 	 	 	Unrealized	 	
 	 	Fair Value	 	 	Gains	 	
2007	 	 	 	 	 	 	 	 	
Equity securities	 	$	175	 	 	$	68	 	
Fixed income securities	 	 	204	 	 	 	5	 	
 	 	 	 	 	 	 	
Total	 	$	379	 	 	$	73	 	

2006	 	 	 	 	 	 	 	 	
Equity securities	 	$	164	 	 	$	63	 	
Fixed income securities	 	 	180	 	 	 	3	 	
 	 	 	 	 	 	 	
Total	 	$	344	 	 	$	66	 	
 	 	 	 	 	 	 	
     The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	
 	 	2007	 	2006	 	2005	
Realized gains	 	$	3	 	 	$	9	 	 	$	6	 	
Realized losses	 	 	(4	)	 	 	—	 	 	 	(6	)	
Proceeds from the sale of securities	 	 	259	 	 	 	255	 	 	 	186	 	
     The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2007 is as follows (dollars in millions):
 	 	 	 	 	
 	 	Fair Value	 	
Less than one year	 	$	10	 	
1 year - 5 years	 	 	42	 	
5 years - 10 years	 	 	38	 	
Greater than 10 years	 	 	114	 	
 	 	 	 	
Total	 	$	204	 	
 	 	 	 	
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13. Selected Quarterly Financial Data (Unaudited)
     Consolidated quarterly financial information for 2007 and 2006 is as follows (dollars in thousands, except per share amounts):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007 Quarter Ended	 	2007	
 	 	March 31,	 	June 30,	 	September 30,	 	December 31,	 	Total	
Operating revenues	 	$	695,135	 	 	$	863,435	 	 	$	1,205,934	 	 	$	759,116	 	 	$	3,523,620	 	
Operations and maintenance	 	 	171,578	 	 	 	177,310	 	 	 	178,419	 	 	 	207,398	 	 	 	734,705	 	
Operating income	 	 	67,989	 	 	 	158,686	 	 	 	338,777	 	 	 	53,799	 	 	 	619,251	 	
Income taxes	 	 	8,609	 	 	 	40,231	 	 	 	91,588	 	 	 	10,492	 	 	 	150,920	 	
Income from continuing operations	 	 	15,798	 	 	 	78,496	 	 	 	200,998	 	 	 	3,488	 	 	 	298,780	 	
Net income	 	 	16,530	 	 	 	78,994	 	 	 	208,708	 	 	 	2,911	 	 	 	307,143	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2006 Quarter Ended	 	2006	
 	 	March 31,	 	June 30,	 	September 30,	 	December 31,	 	Total	
Operating revenues	 	$	670,206	 	 	$	925,028	 	 	$	1,076,442	 	 	$	730,072	 	 	$	3,401,748	 	
Operations and maintenance	 	 	178,427	 	 	 	168,332	 	 	 	164,396	 	 	 	180,122	 	 	 	691,277	 	
Operating income	 	 	57,163	 	 	 	191,197	 	 	 	310,440	 	 	 	60,070	 	 	 	618,870	 	
Income taxes	 	 	6,793	 	 	 	49,271	 	 	 	98,836	 	 	 	1,518	 	 	 	156,418	 	
Income from continuing operations	 	 	11,595	 	 	 	110,843	 	 	 	184,179	 	 	 	10,526	 	 	 	317,143	 	
Net income	 	 	12,455	 	 	 	112,154	 	 	 	184,167	 	 	 	18,479	 	 	 	327,255	 	
Earnings per share:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007 Quarter Ended	
 	 	March 31,	 	June 30,	 	September 30,	 	December 31,	
Basic earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	0.16	 	 	$	0.78	 	 	$	2.00	 	 	$	0.03	 	
Net income	 	 	0.17	 	 	 	0.79	 	 	 	2.08	 	 	 	0.03	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	0.16	 	 	$	0.78	 	 	$	1.99	 	 	$	0.03	 	
Net income	 	 	0.16	 	 	 	0.78	 	 	 	2.07	 	 	 	0.03	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2006 Quarter Ended	
 	 	March 31,	 	June 30,	 	September 30,	 	December 31,	
Basic earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	0.12	 	 	$	1.12	 	 	$	1.85	 	 	$	0.11	 	
Net income	 	 	0.13	 	 	 	1.13	 	 	 	1.85	 	 	 	0.19	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	0.12	 	 	$	1.11	 	 	$	1.84	 	 	$	0.10	 	
Net income	 	 	0.13	 	 	 	1.13	 	 	 	1.84	 	 	 	0.18	 	
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14. Fair Value of Financial Instruments
     We believe that the carrying amounts of our cash equivalents are reasonable estimates of their fair values at December 31, 2007 and 2006 due to their short maturities.
     We hold short-term investments in fixed income securities for purposes other than trading. We believe that the carrying amounts of these investments represent reasonable estimates of their fair values at December 31, 2007 and 2006 due to the short-term reset of interest rates.
     APS also holds investments in fixed income and domestic equity securities for purposes other than trading in its nuclear decommissioning trust. The December 31, 2007 and 2006 fair values of such investments, which we determine by using quoted market prices, approximate their carrying amount. For further information, see disclosure of cost and fair value of APS’ nuclear decommissioning trust fund assets in Note 12.
     On December 31, 2007, the carrying value of our long-term debt for Pinnacle West, excluding capitalized lease obligations was $3.29 billion, with an estimated fair value of $3.20 billion. The carrying value of our long-term debt for Pinnacle West excluding capitalized lease obligations was $3.23 billion on December 31, 2006, with an estimated fair value of $3.19 billion. On December 31, 2007, the carrying value of APS’ long-term debt, excluding capitalized lease obligations, was $2.87 billion, with an estimated fair value of $2.79 billion. The carrying value of APS’ long-term debt excluding capital lease obligations was $2.87 billion on December 31, 2006, with an estimated fair value of $2.84 billion. The fair value estimates are based on quoted market prices of the same or similar issues.
15. Earnings Per Share
     The following table presents earnings per weighted-average common share outstanding for the years ended December 31, 2007, 2006 and 2005:
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	
Basic earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	2.98	 	 	$	3.19	 	 	$	2.31	 	
Income (loss) from discontinued operations	 	 	0.08	 	 	 	0.10	 	 	 	(0.48	)	
 	 	 	 	 	 	 	 	 	 	
Earnings per share — basic	 	$	3.06	 	 	$	3.29	 	 	$	1.83	 	
 	 	 	 	 	 	 	 	 	 	
Diluted earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	2.96	 	 	$	3.17	 	 	$	2.31	 	
Income (loss) from discontinued operations	 	 	0.09	 	 	 	0.10	 	 	 	(0.49	)	
 	 	 	 	 	 	 	 	 	 	
Earnings per share — diluted	 	$	3.05	 	 	$	3.27	 	 	$	1.82	 	
 	 	 	 	 	 	 	 	 	 	
     Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 579,000 shares in 2007, 593,000 shares in 2006 and 106,000 shares in 2005. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 100,834,871 shares in 2007, 100,010,108 shares in 2006 and 96,589,949 shares in 2005.
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     Options to purchase 114,213 shares of common stock were outstanding at December 31, 2007 but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 437,401 at December 31, 2006 and 495,367 at December 31, 2005.
16. Stock-Based Compensation
     Pinnacle West offers stock-based compensation plans for officers and key employees of Pinnacle West and some of our subsidiaries.
     The 2007 Long-Term Incentive Plan (“2007 Plan”) allows Pinnacle West to grant incentive and nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, performance cash awards, dividend equivalents and stock to eligible individuals. We have reserved 8 million shares of common stock for issuance under the 2007 plan plus additional shares that become available for issuance under prior stock plans (“Prior Plans”). Under the 2007 Plan, any shares of stock that are potentially deliverable under any award granted under a Prior Plan will be added to the number of shares of stock available for grant under the 2007 Plan if the award expires or is cancelled or terminated without a delivery of such shares to the participant. In addition, any shares of stock that have been issued in connection with any award granted under a Prior Plan will be added to the number of shares available for grant under the 2007 Plan if the award is cancelled, forfeited, or terminated such that those shares are returned to the Company. No more than 500,000 shares of stock may be granted to any one participant during a calendar year. The maximum performance-based award (other than a performance cash award) payable to any one participant during a performance period is 500,000 shares of stock or the cash equivalent. The plan also provides for the granting of new incentive and non-qualified stock options at a price per share equal to at least 100% of the fair market value of the common stock at the time of grant. The terms of the options cannot be longer than 10 years and the options cannot be repriced during their terms.
     The 2002 Long-Term Incentive Plan (“2002 Plan”) relates to outstanding performance shares but no new awards may be granted under the plan. Performance share awards under the 2002 Plan contain performance criteria that affect the number of shares that ultimately vest. Generally, each recipient of performance shares is entitled to receive shares of common stock at the end of a three-year performance period. The number of shares each recipient ultimately receives, if any, is based upon the percentile ranking of Pinnacle West’s earnings per share growth rate at the end of the three-year period as compared with the earnings per share growth rate of all relevant companies in a specified utilities index. The fair value of the grant is estimated on the date of the grant using the Company’s closing stock price on the date of grant. Management evaluates the probability of meeting the performance criteria at each balance sheet date and related compensation cost is amortized over the performance period on a straight-line basis. If the goals are not achieved, no compensation cost is recognized and any previously recognized compensation cost is reversed.
     The 1994 Long-Term Incentive Plan (“1994 Plan”) relates to outstanding options but no new awards may be granted under the plan. Options vest by thirds over a three-year period beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 Plan also includes outstanding shares of restricted stock.
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     In 2006, Retention Unit Awards (“Retention Units”) were granted to key employees. Each Retention Unit represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Retention Units will be redeemed the first business day of calendar years 2007, 2008, 2009 and 2010. In addition, the employee will receive the amount of dividends that the employee would have received if the employee had owned the stock from the date of grant to the date of payment plus interest. The Retention Units vest over a four-year period from 2006 through 2009, unless the employee is eligible to retire, in which case the employee’s Retention Units are immediately vested and the compensation expense is immediately recognized. As this award is accounted for as a liability award, compensation costs, initially measured based on the Company’s stock price on the grant date, are remeasured at each balance sheet date, using Pinnacle West’s closing stock price. The amount of cash to settle the payment on the first business day of 2007 was $1.6 million.
     In 2007 under the 2007 Plan, Restricted Stock Unit Awards (“Restricted Stock Units”) were granted to officers and key employees. Each officer and key employee had to elect to receive payment for the vested Restricted Stock Units in cash or in fully transferable shares of stock. The fair value of the stock election is estimated on the date of the grant using the Company’s closing stock price on the date of grant. Each Restricted Stock Unit cash election represents the right to receive a cash payment equal to the fair market value of one share of Pinnacle West’s common stock, determined on pre-established valuation dates. One-fourth of the Restricted Stock Units will be redeemed February 20th of calendar years 2008, 2009, 2010 and 2011. In addition, the employee will receive the amount of dividends that the employee would have received if the employee had owned the Restricted Stock Unit from the date of grant to the date of payment plus interest. Restricted Stock Units vest over a four-year period from 2007 through 2010, unless the employee is eligible to retire, in which case the employee’s Restricted Stock Units are immediately vested (with the same redemption dates) and the compensation expense is immediately recognized; however, the Restricted Stock Units will be redeemed on the pre-established valuation dates. As the Restricted Stock Unit cash election award is accounted for as a liability award, the fair market value of the outstanding Restricted Stock Unit cash election is measured at each balance sheet date, using Pinnacle West’s closing stock price.
     The compensation cost that has been charged against Pinnacle West’s income for share-based compensation plans was $6 million in 2007, $13 million in 2006 and $6 million in 2005. The compensation cost that Pinnacle West has capitalized was immaterial in 2007, 2006 and 2005. Pinnacle West’s total income tax benefit recognized in the Consolidated Statements of Income for share-based compensation arrangements was $2 million in 2007, $5 million in 2006 and $2 million in 2005. APS’ share of compensation cost that has been charged against income was $6 million in 2007, $12 million in 2006 and $5 million in 2005.
     The following table is a summary of option activity under our equity incentive plans as of December 31, 2007 and changes during the year:
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 	 	 	 	 	 	 	 	 	 	Weighted-	 	 	
 	 	 	 	 	 	 	 	 	 	Average	 	Aggregate	
 	 	 	 	 	 	Weighted-	 	Remaining	 	Intrinsic Value	
 	 	Shares	 	Average Exercise	 	Contractual Term	 	(dollars in	
Options	 	(in thousands)	 	Price	 	(Years)	 	thousands)	
Outstanding at January 1, 2007	 	 	1,088	 	 	$	40.64	 	 	 	 	 	 	 	 	 	
Exercised	 	 	207	 	 	 	39.48	 	 	 	 	 	 	 	 	 	
Forfeited or expired	 	 	20	 	 	 	43.64	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Outstanding at December 31, 2007	 	 	861	 	 	 	40.84	 	 	 	3.0	 	 	$	2,187	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Exercisable at December 31, 2007	 	 	861	 	 	 	40.84	 	 	 	3.0	 	 	$	2,187	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     There were no options granted during the years 2005 through 2007. The intrinsic value of options exercised was $2 million for 2007, $5 million for 2006 and $4 million for 2005.
     The following table is a summary of the status of stock compensation awards, other than options, as of December 31, 2007 and changes during the year:
 	 	 	 	 	 	 	 	 	
 	 	Shares	 	Weighted-Average Grant-Date	
Nonvested shares	 	(in thousands)	 	Fair Value	
Nonvested at January 1, 2007	 	 	429	 	 	$	41.45	 	
Granted	 	 	164	 	 	 	48.02	 	
Vested	 	 	147	 	 	 	41.38	 	
Forfeited	 	 	67	 	 	 	42.40	 	
 	 	 	 	 	 	 	 	 	
Nonvested at December 31, 2007	 	 	379	 	 	 	43.64	 	
 	 	 	 	 	 	 	 	 	
     As of December 31, 2007, there was $7 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the plans. That cost is expected to be recognized over a weighted-average period of 1.3 years. The total fair value of shares vested during 2007 was $6 million, $10 million for 2006 and $3 million for 2005.
     The following table is a summary of the amount and weighted-average grant date fair value of stock compensation awards granted, other than options, during the years ended December 31, 2007, 2006 and 2005:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	2007 Grant	 	2006	 	2006 Grant	 	 	 	 	 	2005 Grant	
 	 	Shares/	 	Date Fair	 	Shares/	 	Date Fair	 	2005	 	Date Fair	
 	 	Units	 	Value (a)	 	Units	 	Value (a)	 	Shares	 	Value (a)	
Restricted stock award units	 	 	27,026	 	 	$	46.58	 	 	 	—	 	 	$	—	 	 	 	—	 	 	$	—	 	
Restricted cash award units	 	 	107,891	 	 	 	46.58	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Performance share awards	 	 	134,917	 	 	 	48.42	 	 	 	274,070	 	 	 	41.50	 	 	 	215,300	 	 	 	41.36	 	
Stock ownership incentive awards	 	 	—	 	 	 	—	 	 	 	12,526	 	 	 	41.50	 	 	 	13,114	 	 	 	44.13	 	
Retention unit awards	 	 	—	 	 	 	—	 	 	 	123,197	 	 	 	49.92	 	 	 	—	 	 	 	—	 	
Special grant	 	 	2,000	 	 	 	41.88	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

(a)	 	Restricted stock units, performance shares, special grant and stock ownership incentive awards priced at the closing market price on the grant date.	
     Cash received from options exercised under our share-based payment arrangements was $8 million for 2007, $22 million for 2006 and $17 million for 2005. The tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements was $1 million for 2007, $2 million for 2006 and $1 million for 2005.
     Pinnacle West’s current policy is to issue new shares to satisfy share requirements for stock compensation plans and it does not expect to repurchase any shares during 2008.
17. Business Segments
     Pinnacle West’s two reportable business segments are:

 	•	 	our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and	
 		
 	•	 	our real estate segment, which consists of SunCor’s real estate development and investment activities.	
Financial data for 2007, 2006 and 2005 is provided as follows (dollars in millions):
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 	 	Business Segments for the Year Ended December 31, 2007	 	
 	 	Regulated	 	 	 	 	 	 	 	 	 	 	
 	 	Electricity	 	 	Real Estate	 	 	 	 	 	 	 	
 	 	Segment	 	 	Segment	 	 	All other (a)	 	 	Total	 	
Operating revenues	 	$	2,918	 	 	$	215	 	 	$	391	 	 	$	3,524	 	
Purchased power and fuel costs	 	 	1,141	 	 	 	—	 	 	 	294	 	 	 	1,435	 	
Other operating expenses	 	 	836	 	 	 	194	 	 	 	66	 	 	 	1,096	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating margin	 	 	941	 	 	 	21	 	 	 	31	 	 	 	993	 	
Depreciation and amortization	 	 	366	 	 	 	5	 	 	 	2	 	 	 	373	 	
Interest expense	 	 	180	 	 	 	8	 	 	 	2	 	 	 	190	 	
Other expense (income)	 	 	(18	)	 	 	(10	)	 	 	8	 	 	 	(20	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations before income taxes	 	 	413	 	 	 	18	 	 	 	19	 	 	 	450	 	
Income taxes	 	 	139	 	 	 	6	 	 	 	6	 	 	 	151	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	 	274	 	 	 	12	 	 	 	13	 	 	 	299	 	
Income from discontinued operations — net of income tax expense of $6 million (see Note 22)	 	 	—	 	 	 	11	 	 	 	(3	)	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	274	 	 	$	23	 	 	$	10	 	 	$	307	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets	 	$	10,438	 	 	$	661	 	 	$	145	 	 	$	11,244	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	$	900	 	 	$	161	 	 	$	3	 	 	$	1,064	 	

 	 	Business Segments for the Year Ended December 31, 2006	 	
 	 	Regulated	 	 	 	 	 	 	 	 	 	 	
 	 	Electricity	 	 	Real Estate	 	 	 	 	 	 	 	
 	 	Segment	 	 	Segment	 	 	All other (a)	 	 	Total	 	
Operating revenues	 	$	2,635	 	 	$	400	 	 	$	367	 	 	$	3,402	 	
Purchased power and fuel costs	 	 	960	 	 	 	—	 	 	 	291	 	 	 	1,251	 	
Other operating expenses	 	 	791	 	 	 	325	 	 	 	57	 	 	 	1,173	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating margin	 	 	884	 	 	 	75	 	 	 	19	 	 	 	978	 	
Depreciation and amortization	 	 	354	 	 	 	3	 	 	 	2	 	 	 	359	 	
Interest expense	 	 	173	 	 	 	1	 	 	 	2	 	 	 	176	 	
Other expense (income)	 	 	(22	)	 	 	(11	)	 	 	2	 	 	 	(31	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations before income taxes	 	 	379	 	 	 	82	 	 	 	13	 	 	 	474	 	
Income taxes	 	 	120	 	 	 	32	 	 	 	5	 	 	 	157	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	 	259	 	 	 	50	 	 	 	8	 	 	 	317	 	
Income from discontinued operations — net of income tax expense of $7 million (see Note 22)	 	 	—	 	 	 	10	 	 	 	—	 	 	 	10	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	259	 	 	$	60	 	 	$	8	 	 	$	327	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets	 	$	10,566	 	 	$	591	 	 	$	299	 	 	$	11,456	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	$	662	 	 	$	201	 	 	$	7	 	 	$	870	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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 	 	Business Segments for the Year Ended December 31, 2005	 	
 	 	Regulated	 	 	 	 	 	 	 	 	 	 	
 	 	Electricity	 	 	Real Estate	 	 	 	 	 	 	 	
 	 	Segment	 	 	Segment	 	 	All other (a)	 	 	Total	 	
Operating revenues (b)	 	$	2,237	 	 	$	338	 	 	$	413	 	 	$	2,988	 	
Purchased power and fuel costs	 	 	595	 	 	 	—	 	 	 	293	 	 	 	888	 	
Other operating expenses	 	 	740	 	 	 	278	 	 	 	80	 	 	 	1,098	 	
Regulatory disallowance (see Note 3)	 	 	139	 	 	 	—	 	 	 	—	 	 	 	139	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating margin	 	 	763	 	 	 	60	 	 	 	40	 	 	 	863	 	
Depreciation and amortization	 	 	343	 	 	 	3	 	 	 	2	 	 	 	348	 	
Interest expense	 	 	169	 	 	 	2	 	 	 	2	 	 	 	173	 	
Other expense (income)	 	 	(6	)	 	 	(3	)	 	 	1	 	 	 	(8	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations before income taxes	 	 	257	 	 	 	58	 	 	 	35	 	 	 	350	 	
Income taxes	 	 	90	 	 	 	23	 	 	 	14	 	 	 	127	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	 	167	 	 	 	35	 	 	 	21	 	 	 	223	 	
Income (loss) from discontinued operations — net of income tax benefit of $(30) (see Note 22) (c)	 	 	—	 	 	 	17	 	 	 	(64	)	 	 	(47	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	167	 	 	$	52	 	 	$	(43	)	 	$	176	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	$	811	 	 	$	106	 	 	$	11	 	 	$	928	 	

			
(a)	 	All other activities relate to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.	
 		
(b)	 	Effective April 1, 2005, revenues of approximately $40 million from Off-System Sales, which were previously reported in the other segment, began being reported in the regulated electricity segment in accordance with the retail rate case settlement.	
 		
(c)	 	The other segment primarily relates to the sale and operations of Silverhawk. See Note 22.	
18. Derivative and Energy Trading Accounting
     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and in interest rates. We manage risks associated with these market fluctuations by utilizing various instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. As of December 31, 2007, we hedged certain exposures to the price variability of commodities for a maximum of 39 months. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.
     We recognize all derivatives, except those which qualify for a scope exception, as either assets or liabilities on the balance sheet and measure those instruments at fair value in accordance
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with SFAS No. 133, as amended by SFAS No. 149. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business qualify for the normal purchase and sales exception and are accounted for under the accrual method of accounting. Changes in the fair value of derivative instruments are recognized periodically in income unless certain hedge criteria are met. For cash flow hedges, the effective portion of changes in the fair value of the derivative is recognized in common stock equity (as a component of other comprehensive income (loss)). For fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item associated with the hedged risk are recognized in earnings. We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. We use fair value hedges to limit our exposure to changes in fair value of an asset or liability.
     For its regulated operations, APS defers for future rate recovery 90% of gains and losses on derivatives that would otherwise be recognized in income. In the following discussion, amounts that would otherwise be recognized in income will be recorded as either a regulatory asset or liability and have no effect on earnings to the extent these amounts are eligible to be recovered through the PSA.
     We assess hedge effectiveness both at inception and on a continuing basis. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated and is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.
     Both non-trading and trading derivatives that do not qualify for a scope exception are classified as assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets. Certain of our non-trading derivatives qualify for cash flow hedge accounting treatment. Non-trading derivatives, or any portion thereof that are not effective hedges, are adjusted to fair value through income. Realized gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss), and are recognized in income when the underlying transaction impacts earnings.
     All gains and losses (realized and unrealized) on trading contracts that qualify as derivatives are included in marketing and trading revenues on the Consolidated Statements of Income on a net basis. Trading contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
     In the electricity business, some contracts to purchase energy are netted against other contracts to sell energy. This is called “book-out” and usually occurs in contracts that have the same terms (quantities and delivery points) and for which power does not flow. We net these book-outs, which reduces both revenues and fuel and purchased power costs in our Consolidated Statement of Income, but this does not impact our financial condition, net income or cash flows.
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Cash Flow Hedges
     The changes in the fair value of our hedged positions included in the Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2007, 2006 and 2005 are comprised of the following (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	2006	 	2005	
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	 	$	1,430	 	 	$	(5,666	)	 	$	14,289	 	
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness	 	 	—	 	 	 	(10	)	 	 	620	 	
Gains from the discontinuance of cash flow hedges	 	 	320	 	 	 	453	 	 	 	556	 	
     During 2008, we estimate that a net gain of $18 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).
     The following table summarizes our assets and liabilities from risk management and trading activities at December 31, 2007 and 2006 (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Investments	 	 	 	 	 	 	Deferred	 	 	 	 	
 	 	 	 	 	 	and Other	 	 	Current	 	 	Credits and	 	 	Net Asset	 	
December 31, 2007	 	Current Assets	 	 	Assets	 	 	Liabilities	 	 	Other	 	 	(Liability)	 	
Mark-to-market	 	$	60,044	 	 	$	89,913	 	 	$	(64,497	)	 	$	(45,686	)	 	$	39,774	 	
Margin account and options — at cost	 	 	37,329	 	 	 	—	 	 	 	(531	)	 	 	—	 	 	 	36,798	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	97,373	 	 	$	89,913	 	 	$	(65,028	)	 	$	(45,686	)	 	$	76,572	 	

 	 	 	 	 	 	Investments	 	 	 	 	 	 	Deferred	 	 	 	 	
 	 	 	 	 	 	and Other	 	 	 	 	 	 	Credits and	 	 	Net Asset	 	
December 31, 2006	 	Current Assets	 	 	Assets	 	 	Current Liabilities	 	 	Other	 	 	(Liability)	 	
Mark-to-market	 	$	563,335	 	 	$	166,372	 	 	$	(543,214	)	 	$	(171,170	)	 	$	15,323	 	
Margin account, options and emission allowances - at cost	 	 	77,705	 	 	 	839	 	 	 	(14,981	)	 	 	—	 	 	 	63,563	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	641,040	 	 	$	167,211	 	 	$	(558,195	)	 	$	(171,170	)	 	$	78,886	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps. We historically presented the buy side and the sell side of such swaps at fair value gross on our Consolidated Balance Sheets, which resulted in mark-to-market
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset or liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on results of operations, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $31 million at December 31, 2007 and an asset of $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.
     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $1 million at December 31, 2007 and $10 million at December 31, 2006, and is included in other current assets on the Consolidated Balance Sheets. There was no collateral provided to us by counterparties at December 31, 2007 and $54 million was provided at December 31, 2006, and is included in other current liabilities on the Consolidated Balance Sheets.
Credit Risk
     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of trading counterparties’ securities is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated net income for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 “Derivative Accounting” for a discussion of our credit valuation adjustment policy.
19. Other Income and Other Expense
     The following table provides detail of other income and other expense for 2007, 2006 and 2005 (dollars in thousands):
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	
Other income:	 	 	 	 	 	 	 	 	 	 	 	 	
Interest income	 	$	11,656	 	 	$	18,867	 	 	$	14,793	 	
SunCor other income (a)	 	 	10,702	 	 	 	10,881	 	 	 	2,623	 	
SO2 emission allowance sales and other (b)	 	 	—	 	 	 	10,782	 	 	 	3,187	 	
Investment gains — net	 	 	—	 	 	 	2,537	 	 	 	752	 	
Miscellaneous	 	 	2,336	 	 	 	949	 	 	 	2,005	 	
 	 	 	 	 	 	 	 	 	 	
Total other income	 	$	24,694	 	 	$	44,016	 	 	$	23,360	 	
 	 	 	 	 	 	 	 	 	 	
Other expense:	 	 	 	 	 	 	 	 	 	 	 	 	
Non-operating costs (b)	 	$	(14,021	)	 	$	(16,223	)	 	$	(13,589	)	
Asset dispositions	 	 	—	 	 	 	(2,056	)	 	 	(9,759	)	
Investment losses — net	 	 	(2,339	)	 	 	—	 	 	 	—	 	
Miscellaneous	 	 	(9,523	)	 	 	(9,521	)	 	 	(3,368	)	
 	 	 	 	 	 	 	 	 	 	
Total other expense	 	$	(25,883	)	 	$	(27,800	)	 	$	(26,716	)	

			
(a)	 	Includes equity earnings from a real estate joint venture that is a pass-through entity for tax purposes.	
 		
(b)	 	As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).	
20. Variable-Interest Entities
     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them (see Note 9).
     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2007, APS would have been required to assume approximately $194 million of debt and pay the equity participants approximately $170 million.
     SunCor has certain land development arrangements that are required to be consolidated under FIN 46R, “Consolidation of Variable Interest Entities.” The assets and non-controlling interests reflected in our Consolidated Balance Sheets related to these arrangements were approximately $38 million at December 31, 2007 and $39 million at December 31, 2006.
21. Guarantees
     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading and APS relate to commodity energy products. Our credit support instruments enable APSES to offer energy-related
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
products and commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2007 are as follows (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantees	 	 	Surety Bonds	 	
 	 	 	 	 	 	Term	 	 	 	 	 	 	Term	 	
 	 	Amount	 	 	(in years)	 	 	Amount	 	 	(in years)	 	
Parental:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pinnacle West Marketing & Trading	 	$	25	 	 	 	1	 	 	$	—	 	 	 	—	 	
APSES	 	 	18	 	 	 	1	 	 	 	20	 	 	 	1	 	
APS	 	 	4	 	 	 	1	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	47	 	 	 	 	 	 	$	20	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     At December 31, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in 2009. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
     APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2007, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $83 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, at December 31, 2007, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2008. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
     We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
22. Discontinued Operations
      SunCor (real estate segment) - In 2007, 2006 and 2005, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Consolidated Statements of Income in accordance with SFAS No. 144. As a result of the sales, we recorded a gain
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
from discontinued operations of approximately $10 million ($17 million pretax) in 2007; $9 million ($15 million pretax) in 2006; and $15 million ($25 million pretax) in 2005.
      Silverhawk (other) - In June 2005, we entered into an agreement to sell our 75% interest in the Silverhawk Power Station to NPC. The sale was completed on January 10, 2006. As a result of this sale, we recorded a loss from discontinued operations of approximately $56 million ($91 million pretax) in the second quarter of 2005. The chart below includes the revenues and expenses related to the operations of Silverhawk.
      Other — Includes activities related to APSES in 2007 and to El Dorado in 2006 and 2005.
     The following table provides revenue, income (loss) before income taxes and income (loss) after taxes classified as discontinued operations in Pinnacle West’s Consolidated Statements of Income for the years ended December 31, 2007, 2006 and 2005 (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	
Revenue:	 	 	 	 	 	 	 	 	 	 	 	 	
SunCor — commercial operations	 	$	4	 	 	$	3	 	 	$	9	 	
Silverhawk	 	 	—	 	 	 	1	 	 	 	95	 	
 	 	 	 	 	 	 	 	 	 	
Total revenue	 	$	4	 	 	$	4	 	 	$	104	 	

Income (loss) before taxes:	 	 	 	 	 	 	 	 	 	 	 	 	
SunCor — commercial operations	 	$	19	 	 	$	17	 	 	$	28	 	
Silverhawk (a)	 	 	—	 	 	 	1	 	 	 	(111	)	
Other	 	 	(5	)	 	 	(1	)	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	
Total income (loss) before taxes	 	$	14	 	 	$	17	 	 	$	(77	)	

Income (loss) after taxes:	 	 	 	 	 	 	 	 	 	 	 	 	
SunCor — commercial operations	 	$	11	 	 	$	10	 	 	$	17	 	
Silverhawk	 	 	—	 	 	 	1	 	 	 	(67	)	
Other	 	 	(3	)	 	 	(1	)	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	
Total income (loss) after taxes	 	$	8	 	 	$	10	 	 	$	(47	)	

			
(a)	 	Income before income taxes includes an interest expense allocation, net of capitalized amounts, of $13 million in 2005. The allocation was based on Pinnacle West’s weighted-average interest rate applied to the net property, plant and equipment.	
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MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(ARIZONA PUBLIC SERVICE COMPANY)
     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2007. The effectiveness of our internal control over financial reporting as of December 31, 2007 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and relates also to the Company’s financial statements.
February 27, 2008
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholder of
Arizona Public Service Company
Phoenix, Arizona
We have audited the accompanying balance sheets of Arizona Public Service Company (the “Company”) as of December 31, 2007 and 2006, and the related statements of income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in
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accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As reflected in the statements of changes in common stock equity, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” effective December 31, 2006.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Phoenix, Arizona
February 27, 2008
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ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
Electric Operating Revenues	 	$	2,936,277	 	 	$	2,658,513	 	 	$	2,270,793	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	
Fuel and purchased power	 	 	1,151,392	 	 	 	969,767	 	 	 	688,982	 	
Operations and maintenance	 	 	710,077	 	 	 	665,631	 	 	 	591,941	 	
Depreciation and amortization	 	 	365,430	 	 	 	353,057	 	 	 	325,174	 	
Income taxes (Notes 4 and S-1)	 	 	155,735	 	 	 	144,127	 	 	 	157,273	 	
Other taxes	 	 	127,648	 	 	 	127,989	 	 	 	125,810	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	2,510,282	 	 	 	2,260,571	 	 	 	1,889,180	 	

Operating Income	 	 	425,995	 	 	 	397,942	 	 	 	381,613	 	

Other Income (Deductions):	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory disallowance (Note 3)	 	 	—	 	 	 	—	 	 	 	(138,562	)	
Income taxes (Notes 4 and S-1)	 	 	4,578	 	 	 	5,200	 	 	 	59,263	 	
Allowance for equity funds used during construction	 	 	21,195	 	 	 	14,312	 	 	 	11,191	 	
Other income (Note S-4)	 	 	16,727	 	 	 	31,902	 	 	 	22,141	 	
Other expense (Note S-4)	 	 	(21,630	)	 	 	(23,830	)	 	 	(23,204	)	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	20,870	 	 	 	27,584	 	 	 	(69,171	)	

Interest Deductions:	 	 	 	 	 	 	 	 	 	 	 	 	
Interest on long-term debt	 	 	161,030	 	 	 	149,240	 	 	 	138,476	 	
Interest on short-term borrowings	 	 	9,564	 	 	 	9,529	 	 	 	7,026	 	
Debt discount, premium and expense	 	 	4,639	 	 	 	4,363	 	 	 	4,085	 	
Allowance for borrowed funds used during construction	 	 	(12,308	)	 	 	(7,336	)	 	 	(7,624	)	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	162,925	 	 	 	155,796	 	 	 	141,963	 	

Net Income	 	$	283,940	 	 	$	269,730	 	 	$	170,479	 	
 	 	 	 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2007	 	 	2006	 	
ASSETS	 	 	 	 	 	 	 	 	
Utility Plant (Notes 1, 6, 9 and 10)	 	 	 	 	 	 	 	 	
Electric plant in service and held for future use	 	$	11,582,862	 	 	$	11,094,868	 	
Less accumulated depreciation and amortization	 	 	3,994,777	 	 	 	3,789,534	 	
 	 	 	 	 	 	 	
Net	 	 	7,588,085	 	 	 	7,305,334	 	
 	 	 	 	 	 	 	 	 	
Construction work in progress	 	 	622,693	 	 	 	365,704	 	
Intangible assets, net of accumulated amortization of $250,268 and $217,099	 	 	105,225	 	 	 	95,601	 	
Nuclear fuel, net of accumulated amortization of $68,375 and $50,741	 	 	69,271	 	 	 	60,100	 	
 	 	 	 	 	 	 	
Total utility plant	 	 	8,385,274	 	 	 	7,826,739	 	

Investments and Other Assets	 	 	 	 	 	 	 	 	
Decommissioning trust accounts (Note 12)	 	 	379,347	 	 	 	343,771	 	
Assets from risk management and trading activities (Note S-3)	 	 	82,588	 	 	 	96,892	 	
Other assets	 	 	69,570	 	 	 	67,763	 	
 	 	 	 	 	 	 	
Total investments and other assets	 	 	531,505	 	 	 	508,426	 	

Current Assets:	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	 	52,151	 	 	 	81,870	 	
Investment in debt securities	 	 	—	 	 	 	32,700	 	
Customer and other receivables	 	 	402,244	 	 	 	410,436	 	
Allowance for doubtful accounts	 	 	(4,265	)	 	 	(4,223	)	
Materials and supplies (at average cost)	 	 	149,759	 	 	 	125,802	 	
Fossil fuel (at average cost)	 	 	27,792	 	 	 	21,973	 	
Assets from risk management and trading activities (Note S-3)	 	 	73,854	 	 	 	539,308	 	
Deferred income taxes (Notes 4 and S-1)	 	 	38,707	 	 	 	19,220	 	
Other	 	 	17,296	 	 	 	13,367	 	
 	 	 	 	 	 	 	
Total current assets	 	 	757,538	 	 	 	1,240,453	 	

Deferred Debits:	 	 	 	 	 	 	 	 	
Deferred fuel and purchased power regulatory asset (Notes 1, 3, 4 and S-1)	 	 	110,928	 	 	 	160,268	 	
Other regulatory assets (Notes 1, 3, 4 and S-1)	 	 	514,353	 	 	 	686,016	 	
Unamortized debt issue costs	 	 	24,373	 	 	 	26,393	 	
Other	 	 	78,934	 	 	 	65,397	 	

Total deferred debits	 	 	728,588	 	 	 	938,074	 	

Total Assets	 	$	10,402,905	 	 	$	10,513,692	 	
 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2007	 	 	2006	 	
LIABILITIES AND EQUITY	 	 	 	 	 	 	 	 	
Capitalization:	 	 	 	 	 	 	 	 	
Common stock	 	$	178,162	 	 	$	178,162	 	
Additional paid-in capital (Note 3)	 	 	2,105,466	 	 	 	2,065,918	 	
Retained earnings	 	 	1,076,557	 	 	 	960,405	 	
Accumulated other comprehensive income (loss):	 	 	 	 	 	 	 	 	
Pension and other postretirement benefits (Note 8)	 	 	(21,782	)	 	 	—	 	
Derivative instruments	 	 	13,038	 	 	 	2,988	 	
 	 	 	 	 	 	 	
Common stock equity	 	 	3,351,441	 	 	 	3,207,473	 	
Long-term debt less current maturities (Note 6)	 	 	2,876,881	 	 	 	2,877,502	 	
 	 	 	 	 	 	 	
Total capitalization	 	 	6,228,322	 	 	 	6,084,975	 	

Current Liabilities:	 	 	 	 	 	 	 	 	
Short-term debt	 	 	218,000	 	 	 	—	 	
Current maturities of long-term debt (Note 6)	 	 	978	 	 	 	968	 	
Accounts payable	 	 	239,923	 	 	 	223,417	 	
Accrued taxes	 	 	374,444	 	 	 	381,444	 	
Accrued interest	 	 	38,262	 	 	 	45,254	 	
Customer deposits	 	 	71,376	 	 	 	61,900	 	
Liabilities from risk management and trading activities (Note S-3)	 	 	60,439	 	 	 	490,855	 	
Other	 	 	92,802	 	 	 	74,728	 	
 	 	 	 	 	 	 	
Total current liabilities	 	 	1,096,224	 	 	 	1,278,566	 	

Deferred Credits and Other:	 	 	 	 	 	 	 	 	
Deferred income taxes (Notes 4 and S-1)	 	 	1,250,028	 	 	 	1,215,862	 	
Regulatory liabilities (Notes 1, 3, 4, and S-1)	 	 	642,564	 	 	 	635,431	 	
Liability for asset retirements (Note 12)	 	 	281,903	 	 	 	268,389	 	
Pension and other postretirement liabilities (Note 8)	 	 	469,945	 	 	 	551,531	 	
Customer advances for construction	 	 	94,801	 	 	 	71,211	 	
Unamortized gain — sale of utility plant (Note 9)	 	 	36,606	 	 	 	41,182	 	
Liabilities from risk management and trading activities (Note S-3)	 	 	45,558	 	 	 	135,056	 	
Other	 	 	256,954	 	 	 	231,489	 	
 	 	 	 	 	 	 	
Total deferred credits and other	 	 	3,078,359	 	 	 	3,150,151	 	

Commitments and Contingencies (See Notes)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Total Liabilities and Equity	 	$	10,402,905	 	 	$	10,513,692	 	
 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
Cash Flows from Operating Activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	283,940	 	 	$	269,730	 	 	$	170,479	 	
Adjustments to reconcile net income to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory disallowance	 	 	—	 	 	 	—	 	 	 	138,562	 	
Depreciation and amortization including nuclear fuel	 	 	395,890	 	 	 	381,173	 	 	 	353,082	 	
Deferred fuel and purchased power	 	 	(196,136	)	 	 	(252,849	)	 	 	(172,756	)	
Deferred fuel and purchased power amortization	 	 	231,106	 	 	 	265,337	 	 	 	—	 	
Deferred fuel and purchased power disallowance	 	 	14,370	 	 	 	—	 	 	 	—	 	
Allowance for equity funds used during construction	 	 	(21,195	)	 	 	(14,312	)	 	 	(11,191	)	
Deferred income taxes	 	 	(44,478	)	 	 	(305	)	 	 	9,659	 	
Change in derivative mark-to-market valuations	 	 	(6,758	)	 	 	6,893	 	 	 	3,492	 	
Changes in current assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	
Customer and other receivables	 	 	23,882	 	 	 	20,970	 	 	 	(56,152	)	
Materials, supplies and fossil fuel	 	 	(29,776	)	 	 	(14,381	)	 	 	(12,268	)	
Other current assets	 	 	(8,056	)	 	 	3,666	 	 	 	(2,592	)	
Accounts payable	 	 	(2,797	)	 	 	5,825	 	 	 	(12,372	)	
Accrued taxes	 	 	13,802	 	 	 	23,678	 	 	 	67,454	 	
Collateral	 	 	509	 	 	 	(175,799	)	 	 	169,080	 	
Other current liabilities	 	 	20,231	 	 	 	45,125	 	 	 	(37,781	)	
Change in risk management and trading — liabilities	 	 	(2,009	)	 	 	(121,833	)	 	 	115,495	 	
Change in risk management and trading — assets	 	 	40,376	 	 	 	(74,208	)	 	 	15,449	 	
Changes in unrecognized tax benefits	 	 	27,773	 	 	 	—	 	 	 	—	 	
Change in other long-term assets	 	 	(23,577	)	 	 	2,828	 	 	 	(24,752	)	
Change in other long-term liabilities	 	 	48,718	 	 	 	22,175	 	 	 	9,002	 	
 	 	 	 	 	 	 	 	 	 	
Net cash flow provided by operating activities	 	 	765,815	 	 	 	393,713	 	 	 	721,890	 	
 	 	 	 	 	 	 	 	 	 	
Cash Flows from Investing Activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(882,357	)	 	 	(648,743	)	 	 	(609,857	)	
Transfer of PWEC Dedicated Assets to APS	 	 	—	 	 	 	—	 	 	 	(500,000	)	
Purchase of Sundance Plant	 	 	—	 	 	 	—	 	 	 	(185,046	)	
Allowance for borrowed funds used during construction	 	 	(12,308	)	 	 	(7,336	)	 	 	(7,624	)	
Purchases of investment securities	 	 	(36,525	)	 	 	(1,291,903	)	 	 	(1,476,623	)	
Proceeds from sale of investment securities	 	 	69,225	 	 	 	1,259,203	 	 	 	1,657,798	 	
Proceeds from nuclear decommissioning trust sales	 	 	259,026	 	 	 	254,651	 	 	 	186,215	 	
Investment in nuclear decommissioning trust	 	 	(279,768	)	 	 	(275,393	)	 	 	(204,633	)	
Repayment of loan by Pinnacle West Energy	 	 	—	 	 	 	—	 	 	 	500,000	 	
Other	 	 	1,211	 	 	 	(4,470	)	 	 	(5,372	)	
 	 	 	 	 	 	 	 	 	 	
Net cash flow used for investing activities	 	 	(881,496	)	 	 	(713,991	)	 	 	(645,142	)	
 	 	 	 	 	 	 	 	 	 	
Cash Flows from Financing Activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Issuance of long-term debt	 	 	—	 	 	 	395,481	 	 	 	411,787	 	
Short-term borrowings — net	 	 	218,000	 	 	 	—	 	 	 	—	 	
Equity infusion	 	 	39,548	 	 	 	212,820	 	 	 	250,000	 	
Dividends paid on common stock	 	 	(170,000	)	 	 	(170,000	)	 	 	(170,000	)	
Repayment and reacquisition of long-term debt	 	 	(1,586	)	 	 	(86,086	)	 	 	(568,177	)	
 	 	 	 	 	 	 	 	 	 	
Net cash flow (used for) provided by financing activities	 	 	85,962	 	 	 	352,215	 	 	 	(76,390	)	
 	 	 	 	 	 	 	 	 	 	
Net (decrease) increase in cash and cash equivalents	 	 	(29,719	)	 	 	31,937	 	 	 	358	 	
Cash and cash equivalents at beginning of year	 	 	81,870	 	 	 	49,933	 	 	 	49,575	 	
 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of year	 	$	52,151	 	 	$	81,870	 	 	$	49,933	 	
 	 	 	 	 	 	 	 	 	 	
Supplemental disclosure of cash flow information:	 	 	 	 	 	 	 	 	 	 	 	 	
Cash paid during the year for:	 	 	 	 	 	 	 	 	 	 	 	 	
Income taxes, net of refunds	 	$	186,183	 	 	$	117,831	 	 	$	34,252	 	
Interest, net of amounts capitalized	 	$	165,279	 	 	$	131,183	 	 	$	146,207	 	
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
COMMON STOCK	 	$	178,162	 	 	$	178,162	 	 	$	178,162	 	

ADDITIONAL PAID-IN CAPITAL	 	 	2,105,466	 	 	 	2,065,918	 	 	 	1,853,098	 	

RETAINED EARNINGS	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	 	960,405	 	 	 	860,675	 	 	 	860,196	 	
Net income	 	 	283,940	 	 	 	269,730	 	 	 	170,479	 	
Common stock dividends	 	 	(170,000	)	 	 	(170,000	)	 	 	(170,000	)	
Cumulative effect of change in accounting for income taxes (Note S-1)	 	 	2,212	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Balance at end of year	 	 	1,076,557	 	 	 	960,405	 	 	 	860,675	 	

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	 	2,988	 	 	 	93,290	 	 	 	(52,760	)	
Pension and other postretirement benefits (Note 8):	 	 	 	 	 	 	 	 	 	 	 	 	
Unrealized actuarial loss, net of tax benefit of ($15,126)	 	 	(23,304	)	 	 	—	 	 	 	—	 	
Prior service cost, net of tax benefit of ($463)	 	 	(713	)	 	 	—	 	 	 	—	 	
Amortization to income:	 	 	 	 	 	 	 	 	 	 	 	 	
Actuarial loss, net of tax expense of $1,238	 	 	1,908	 	 	 	—	 	 	 	—	 	
Prior service cost, net of tax expense of $212	 	 	327	 	 	 	—	 	 	 	—	 	
Minimum pension liability adjustment, net of tax expense (benefit) of $27,424 and ($9,023)	 	 	—	 	 	 	42,731	 	 	 	(15,045	)	
Adjustment to reflect a change in accounting, net of tax expense of $27,760	 	 	—	 	 	 	43,401	 	 	 	—	 	
Derivative instruments:	 	 	 	 	 	 	 	 	 	 	 	 	
Net unrealized gain (loss), net of tax expense (benefit) of $1,369, ($111,367) and $140,135	 	 	2,040	 	 	 	(173,872	)	 	 	218,656	 	
Reclassification of net realized (gains) losses to income, net of tax expense (benefit) of $5,164, ($1,657) and ($37,082)	 	 	8,010	 	 	 	(2,562	)	 	 	(57,561	)	
 	 	 	 	 	 	 	 	 	 	
Balance at end of year	 	 	(8,744	)	 	 	2,988	 	 	 	93,290	 	

TOTAL COMMON STOCK EQUITY	 	$	3,351,441	 	 	$	3,207,473	 	 	$	2,985,225	 	

COMPREHENSIVE INCOME	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	283,940	 	 	$	269,730	 	 	$	170,479	 	
Other comprehensive income (loss)	 	 	(11,732	)	 	 	(133,703	)	 	 	146,050	 	
 	 	 	 	 	 	 	 	 	 	
Total comprehensive income	 	$	272,208	 	 	$	136,027	 	 	$	316,529	 	
 	 	 	 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Financial Statements.
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     Certain notes to Arizona Public Service Company’s financial statements are combined with the notes to Pinnacle West Capital Corporation’s consolidated financial statements. Listed below are the consolidated notes to Pinnacle West Capital Corporation’s consolidated financial statements, the majority of which also relate to Arizona Public Service Company’s financial statements. In addition, listed below are the supplemental notes which are required disclosures for Arizona Public Service Company and should be read in conjunction with Pinnacle West Capital Corporation’s Consolidated Notes.
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	APS’	
 	 	Consolidated	 	Supplemental	
 	 	Footnote	 	Footnote	
 	 	Reference	 	Reference	
Summary of Significant Accounting Policies	 	Note 1	 	 	—	 	
New Accounting Standards	 	Note 2	 	 	—	 	
Regulatory Matters	 	Note 3	 	 	—	 	
Income Taxes	 	Note 4	 	Note S-1	
Lines of Credit and Short-Term Borrowings	 	Note 5	 	 	—	 	
Long-Term Debt	 	Note 6	 	 	—	 	
Common Stock and Treasury Stock	 	Note 7	 	 	—	 	
Retirement Plans and Other Benefits	 	Note 8	 	 	—	 	
Leases	 	Note 9	 	 	—	 	
Jointly-Owned Facilities	 	Note 10	 	 	—	 	
Commitments and Contingencies	 	Note 11	 	 	—	 	
Asset Retirement Obligations	 	Note 12	 	 	—	 	
Selected Quarterly Financial Data (Unaudited)	 	Note 13	 	Note S-2	
Fair Value of Financial Instruments	 	Note 14	 	 	—	 	
Earnings Per Share	 	Note 15	 	 	—	 	
Stock-Based Compensation	 	Note 16	 	 	—	 	
Business Segments	 	Note 17	 	 	—	 	
Derivative and Energy Trading Accounting	 	Note 18	 	Note S-3	
Other Income and Other Expense	 	Note 19	 	Note S-4	
Variable Interest Entities	 	Note 20	 	 	—	 	
Guarantees	 	Note 21	 	 	—	 	
Discontinued Operations	 	Note 22	 	 	—	 	
Related Party Transactions	 	 	—	 	 	Note S-5	
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NOTES TO ARIZONA PUBLIC SERVICE COMPANY
S-1. Income Taxes
     APS is included in Pinnacle West’s consolidated tax return. However, when Pinnacle West allocates income taxes to APS, it is done based upon APS’ taxable income computed on a stand-alone basis, in accordance with the tax sharing agreement.
     Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates.
     APS has recorded a regulatory asset and a regulatory liability related to income taxes on its Balance Sheets in accordance with SFAS No. 71. The regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. The regulatory liability relates to excess deferred taxes resulting primarily from pension and other postretirement benefits. APS amortizes these amounts as the differences reverse.
     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on our 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. Our 2001 federal consolidated income tax return is currently under examination by the IRS. As part of its ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. Within the next six months, we expect that the IRS will finalize its examination of the 2001 return, which will include a settlement on the tax accounting method change. Although the ultimate outcome of this matter cannot currently be predicted, the current status of the examination has resulted in changes in our judgement which are reflected in the reconciliation of the total amounts of unrecognized tax benefits presented below. We do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows. We do not expect that there will be any other significant increases or decreases in our unrecognized tax benefits within the next 12 months.
     We adopted FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.
     Following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the period that are included in accrued taxes and other deferred credits on the Balance Sheets (dollars in thousands):
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NOTES TO ARIZONA PUBLIC SERVICE COMPANY
 	 	 	 	 	
Total unrecognized tax benefits, January 1, 2007	 	$	126,700	 	
Additions for tax positions of the current year	 	 	—	 	
Additions for tax positions of prior years	 	 	66,610	 	
Reductions for tax positions of prior years for:	 	 	 	 	
Changes in judgment	 	 	(37,419	)	
Settlements with taxing authorities	 	 	(1,418	)	
Lapses of applicable statute of limitations	 	 	—	 	
 	 	 	 	
Total unrecognized tax benefits, December 31, 2007	 	$	154,473	 	
 	 	 	 	
     Included in the balance of unrecognized tax benefits at December 31, 2007 are approximately $4 million of tax positions that, if recognized, would decrease our effective tax rate.
     We reflect interest and penalties, if any, on unrecognized tax benefits in the statement of operations as income tax expense. For 2007, the amount of interest recognized in the statement of operations related to unrecognized tax benefits was $3 million.
     As of December 31, 2007, the total amount of interest expense recognized in the statement of financial position related to unrecognized tax benefits was $56 million. To the extent that matters are settled favorably, this amount could reverse and decrease our effective tax rate. Additionally, we have recognized $5 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
     The components of APS’ income tax expense are as follows (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
Current:	 	 	 	 	 	 	 	 	 	 	 	 	
Federal	 	$	168,607	 	 	$	114,971	 	 	$	79,917	 	
State	 	 	27,028	 	 	 	21,442	 	 	 	8,434	 	
 	 	 	 	 	 	 	 	 	 	
Total current	 	 	195,635	 	 	 	136,413	 	 	 	88,351	 	
Deferred	 	 	(44,478	)	 	 	2,514	 	 	 	9,659	 	
 	 	 	 	 	 	 	 	 	 	
Total income tax expense	 	$	151,157	 	 	$	138,927	 	 	$	98,010	 	
 	 	 	 	 	 	 	 	 	 	
     On the APS Statements of Income, federal and state income taxes are allocated between operating income and other income.
     The following chart compares APS’ pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands):
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NOTES TO ARIZONA PUBLIC SERVICE COMPANY
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
Federal income tax expense at 35% statutory rate	 	$	152,284	 	 	$	143,030	 	 	$	93,971	 	
Increases (reductions) in tax expense resulting from:	 	 	 	 	 	 	 	 	 	 	 	 	
State income tax net of federal income tax benefit	 	 	17,540	 	 	 	15,684	 	 	 	8,986	 	
Credits and favorable adjustments related to prior years resolved in current year	 	 	(11,432	)	 	 	(10,518	)	 	 	—	 	
Medicare Subsidy Part-D	 	 	(3,100	)	 	 	(3,036	)	 	 	(2,465	)	
Allowance for equity funds used during construction (see Note 1)	 	 	(6,900	)	 	 	(4,656	)	 	 	(3,694	)	
Other	 	 	2,765	 	 	 	(1,577	)	 	 	1,212	 	
 	 	 	 	 	 	 	 	 	 	
Income tax expense	 	$	151,157	 	 	$	138,927	 	 	$	98,010	 	
 	 	 	 	 	 	 	 	 	 	
     The following table shows the net deferred income tax liability recognized on the APS Balance Sheets (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2007	 	 	2006	 	
Current asset	 	$	38,707	 	 	$	19,220	 	
Long-term liability	 	 	(1,250,028	)	 	 	(1,215,862	)	
 	 	 	 	 	 	 	
Accumulated deferred income taxes — net	 	$	(1,211,321	)	 	$	(1,196,642	)	
 	 	 	 	 	 	 	
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NOTES TO ARIZONA PUBLIC SERVICE COMPANY
     The components of the net deferred income tax liability were as follows (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	December 31,	 	
 	 	2007	 	 	2006	 	
DEFERRED TAX ASSETS	 	 	 	 	 	 	 	 	
Regulatory liabilities:	 	 	 	 	 	 	 	 	
Asset retirement obligation	 	$	214,607	 	 	$	203,846	 	
Federal excess deferred income tax	 	 	11,091	 	 	 	12,714	 	
Tax benefit of Medicare subsidy	 	 	11,727	 	 	 	18,214	 	
Other	 	 	26,579	 	 	 	27,283	 	
Risk management and trading activities	 	 	41,512	 	 	 	244,611	 	
Pension and other postretirement liabilities	 	 	197,620	 	 	 	257,910	 	
Deferred gain on Palo Verde Unit 2 sale-leaseback	 	 	14,408	 	 	 	16,160	 	
Other	 	 	116,491	 	 	 	86,442	 	
 	 	 	 	 	 	 	
Total deferred tax assets	 	 	634,035	 	 	 	867,180	 	
 	 	 	 	 	 	 	
DEFERRED TAX LIABILITIES	 	 	 	 	 	 	 	 	
Plant-related	 	 	(1,538,183	)	 	 	(1,509,812	)	
Risk management and trading activities	 	 	(46,883	)	 	 	(220,303	)	
Regulatory assets:	 	 	 	 	 	 	 	 	
Deferred fuel and purchased power	 	 	(43,661	)	 	 	(62,889	)	
Deferred fuel and purchased power - mark-to-market	 	 	(2,782	)	 	 	(24,427	)	
Pension and other postretirement benefits	 	 	(133,120	)	 	 	(185,602	)	
Other	 	 	(80,727	)	 	 	(60,789	)	
 	 	 	 	 	 	 	
Total deferred tax liabilities	 	 	(1,845,356	)	 	 	(2,063,822	)	
 	 	 	 	 	 	 	
Accumulated deferred income taxes — net	 	$	(1,211,321	)	 	$	(1,196,642	)	
 	 	 	 	 	 	 	
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NOTES TO ARIZONA PUBLIC SERVICE COMPANY
S-2. Selected Quarterly Financial Data (Unaudited)
     Quarterly financial information for 2007 and 2006 is as follows (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007 Quarter Ended,	 	2007	
 	 	March 31,	 	June 30,	 	September 30,	 	December 31,	 	Total	
Operating revenues	 	$	538,260	 	 	$	721,759	 	 	$	1,047,062	 	 	$	629,196	 	 	$	2,936,277	 	
Operations and maintenance	 	 	165,934	 	 	 	170,631	 	 	 	171,963	 	 	 	201,549	 	 	 	710,077	 	
Operating income	 	 	40,589	 	 	 	109,643	 	 	 	238,144	 	 	 	37,619	 	 	 	425,995	 	
Net income	 	 	4,317	 	 	 	75,090	 	 	 	204,257	 	 	 	276	 	 	 	283,940	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2006 Quarter Ended,	 	2006	
 	 	March 31,	 	June 30,	 	September 30,	 	December 31,	 	Total	
Operating revenues	 	$	476,869	 	 	$	718,850	 	 	$	886,686	 	 	$	576,108	 	 	$	2,658,513	 	
Operations and maintenance	 	 	173,353	 	 	 	164,373	 	 	 	156,170	 	 	 	171,735	 	 	 	665,631	 	
Operating income	 	 	25,044	 	 	 	119,967	 	 	 	200,580	 	 	 	52,351	 	 	 	397,942	 	
Net income (loss)	 	 	(5,521	)	 	 	93,757	 	 	 	168,634	 	 	 	12,860	 	 	 	269,730	 	
S-3. Derivative and Energy Trading Accounting
     APS is exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels and emissions allowances and credits. As of December 31, 2007, APS hedged certain exposures to these risks for a maximum of 39 months.
Cash Flow Hedges
     The changes in the fair value of APS’ hedged positions included in the APS Statements of Income, after consideration of amounts deferred under the PSA, for the years ended December 31, 2007, 2006 and 2005 are comprised of the following (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	2006	 	2005	
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	 	$	1,430	 	 	$	(5,666	)	 	$	14,452	 	
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness	 	 	—	 	 	 	(10	)	 	 	620	 	
Gains from the discontinuance of cash flow hedges	 	 	150	 	 	 	178	 	 	 	473	 	
     During 2008, APS estimates that a net gain of $1 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 3).
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NOTES TO ARIZONA PUBLIC SERVICE COMPANY
     The following table summarizes APS’ assets and liabilities from risk management and trading activities at December 31, 2007 and 2006 (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Investments	 	 	 	 	 	Deferred	 	 	
 	 	 	 	 	 	and Other	 	Current	 	Credits and	 	 	
December 31, 2007	 	Current Assets	 	Assets	 	Liabilities	 	Other	 	Net Asset	
Mark-to-market	 	$	36,525	 	 	$	82,588	 	 	$	(59,908	)	 	$	(45,558	)	 	$	13,647	 	
Margin account and options — at cost	 	 	37,329	 	 	 	—	 	 	 	(531	)	 	 	—	 	 	 	36,798	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	73,854	 	 	$	82,588	 	 	$	(60,439	)	 	$	(45,558	)	 	$	50,445	 	

 	 	 	 	 	 	Investments	 	 	 	 	 	Deferred	 	 	
 	 	Current	 	and Other	 	Current	 	Credits and	 	Net Asset	
December 31, 2006	 	Assets	 	Assets	 	Liabilities	 	Other	 	(Liability)	
Mark-to-market	 	$	461,603	 	 	$	96,892	 	 	$	(488,315	)	 	$	(135,056	)	 	$	(64,876	)	
Margin account and options — at cost	 	 	77,705	 	 	 	—	 	 	 	(2,540	)	 	 	—	 	 	 	75,165	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	539,308	 	 	$	96,892	 	 	$	(490,855	)	 	$	(135,056	)	 	$	10,289	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps. We historically presented the buy side and the sell side of such swaps at fair value gross on our Balance Sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset or liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on income, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $31 million at December 31, 2007 and an asset of $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.
     Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. Collateral provided to counterparties was $1 million at December 31, 2007 and was $2 million at December 31, 2006 and is included in other current assets on the balance sheet. There was no cash collateral provided to us by counterparties at December 31, 2007 and $1 million was provided at December 31, 2006, and is included in other current liabilities on the Balance Sheets.
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NOTES TO ARIZONA PUBLIC SERVICE COMPANY
S-4. Other Income and Other Expense
     The following table provides detail of APS’ other income and other expense for 2007, 2006 and 2005 (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	
Other income:	 	 	 	 	 	 	 	 	 	 	 	 	
Interest income	 	$	10,961	 	 	$	16,526	 	 	$	14,513	 	
SO2 emission allowance sales and other (a)	 	 	1,001	 	 	 	10,782	 	 	 	3,187	 	
Investment gains — net	 	 	2,429	 	 	 	3,645	 	 	 	1,705	 	
Miscellaneous	 	 	2,336	 	 	 	949	 	 	 	2,736	 	
 	 	 	 	 	 	 	 	 	 	
Total other income	 	$	16,727	 	 	$	31,902	 	 	$	22,141	 	

Other expense:	 	 	 	 	 	 	 	 	 	 	 	 	
Non-operating costs (a)	 	$	(12,712	)	 	$	(15,415	)	 	$	(11,706	)	
Asset dispositions	 	 	(1,981	)	 	 	(1,851	)	 	 	(9,759	)	
Miscellaneous	 	 	(6,937	)	 	 	(6,564	)	 	 	(1,739	)	
 	 	 	 	 	 	 	 	 	 	
Total other expense	 	$	(21,630	)	 	$	(23,830	)	 	$	(23,204	)	

			
(a)	 	As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).	
S-5. Related Party Transactions
     From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s other subsidiaries. The following table summarizes the amounts included in the APS Statements of Income and Balance Sheets related to transactions with affiliated companies (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	
Electric operating revenues:	 	 	 	 	 	 	 	 	 	 	 	 	
Pinnacle West Marketing & Trading (a)	 	$	4	 	 	$	6	 	 	$	6	 	
Pinnacle West Energy	 	 	—	 	 	 	—	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	$	4	 	 	$	6	 	 	$	8	 	

Fuel and purchased power costs:	 	 	 	 	 	 	 	 	 	 	 	 	
Pinnacle West Energy	 	$	—	 	 	$	—	 	 	$	61	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Other:	 	 	 	 	 	 	 	 	 	 	 	 	
Pinnacle West Energy interest income	 	$	—	 	 	$	—	 	 	$	7	 	
Equity infusion from Pinnacle West	 	$	40	 	 	$	210	 	 	$	250	 	

(a)	 	Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.	
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NOTES TO ARIZONA PUBLIC SERVICE COMPANY
 	 	 	 	 	 	 	 	 	
 	 	As of December 31,	 	
 	 	2007	 	 	2006	 	
Net affiliate receivables (payables):	 	 	 	 	 	 	 	 	
Pinnacle West Marketing & Trading (a)	 	$	11	 	 	$	2	 	
APSES	 	 	—	 	 	 	1	 	
Pinnacle West	 	 	(9	)	 	 	(20	)	
 	 	 	 	 	 	 	
Total	 	$	2	 	 	$	(17	)	

			
(a)	 	Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.	
     Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. However, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 02-3.”
     On November 8, 2005, the ACC approved Pinnacle West’s request to infuse more than $450 million of equity into APS during 2005 or 2006. These infusions consisted of about $250 million of the proceeds of Pinnacle West’s common equity issuance on May 2, 2005 and about $210 million of the proceeds from the sale of Silverhawk in January 2006. In May 2007, Pinnacle West infused approximately $40 million of equity into APS, consisting of proceeds of stock issuances in 2006 under Pinnacle West’s Investors Advantage Plan (direct stock purchase and dividend reinvestment plan) and employee stock plans.
     Intercompany receivables primarily include amounts related to the intercompany sales of electricity. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.
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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME
(in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31,	 	
 	 	2007 (a)	 	 	2006	 	 	2005	 	
Operating revenues	 	$	6,708	 	 	$	119,224	 	 	$	154,053	 	

Operating expenses	 	 	 	 	 	 	 	 	 	 	 	 	
Fuel and purchased power	 	 	(35,541	)	 	 	101,360	 	 	 	95,223	 	
Other operating expenses	 	 	5,659	 	 	 	9,607	 	 	 	3,268	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	(29,882	)	 	 	110,967	 	 	 	98,491	 	

Operating income	 	 	36,590	 	 	 	8,257	 	 	 	55,562	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Other	 	 	 	 	 	 	 	 	 	 	 	 	
Equity in earnings of subsidiaries	 	 	287,078	 	 	 	324,504	 	 	 	58,759	 	
Other income	 	 	225	 	 	 	2,208	 	 	 	5,337	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	287,303	 	 	 	326,712	 	 	 	64,096	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	 	17,190	 	 	 	20,522	 	 	 	16,472	 	

Income from continuing operations	 	 	306,703	 	 	 	314,447	 	 	 	103,186	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income tax benefit	 	 	(440	)	 	 	(12,898	)	 	 	(62,761	)	

Income from continuing operations — net of income taxes	 	 	307,143	 	 	 	327,345	 	 	 	165,947	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Income (loss) from discontinued operations	 	 	—	 	 	 	(90	)	 	 	10,320	 	

Net income	 	$	307,143	 	 	$	327,255	 	 	$	176,267	 	

			
(a)	 	Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.	
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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(in thousands)
 	 	 	 	 	 	 	 	 	
 	 	Balance at December 31,	 	
 	 	2007 (a)	 	 	2006	 	
Assets	 	 	 	 	 	 	 	 	
Current assets	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	137	 	 	$	11	 	
Customer and other receivables	 	 	82,003	 	 	 	174,583	 	
Allowance for doubtful accounts	 	 	—	 	 	 	(1,200	)	
Assets from risk management and trading activities	 	 	—	 	 	 	101,604	 	
Other current assets	 	 	1,262	 	 	 	10,810	 	
 	 	 	 	 	 	 	
Total current assets	 	 	83,402	 	 	 	285,808	 	

Investments and other assets	 	 	 	 	 	 	 	 	
Assets from long-term risk management and trading activities	 	 	—	 	 	 	70,319	 	
Investments in subsidiaries	 	 	3,711,737	 	 	 	3,545,329	 	
Deferred income taxes	 	 	11,806	 	 	 	—	 	
Other assets	 	 	23,591	 	 	 	73,300	 	
 	 	 	 	 	 	 	
Total investments and other assets	 	 	3,747,134	 	 	 	3,688,948	 	

Total Assets	 	$	3,830,536	 	 	$	3,974,756	 	

Liabilities and Common Stock Equity	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
Current liabilities	 	 	 	 	 	 	 	 	
Accounts payable	 	$	22,177	 	 	$	80,903	 	
Accrued taxes	 	 	(86,081	)	 	 	(118,073	)	
Short-term borrowings	 	 	115,000	 	 	 	27,900	 	
Current maturities of long-term debt	 	 	—	 	 	 	115	 	
Deferred income taxes	 	 	7,682	 	 	 	18,238	 	
Liabilities from risk management and trading activities	 	 	2	 	 	 	67,340	 	
Other current liabilities	 	 	18,019	 	 	 	130,985	 	
 	 	 	 	 	 	 	
Total current liabilities	 	 	76,799	 	 	 	207,408	 	

Long-term debt less current maturities	 	 	175,000	 	 	 	175,000	 	
 	 	 	 	 	 	 	 	 	
Deferred credits and other	 	 	 	 	 	 	 	 	
Deferred income taxes	 	 	—	 	 	 	19,582	 	
Pension and other postretirement liabilities	 	 	22,248	 	 	 	13,437	 	
Liabilities from risk management and trading activities	 	 	—	 	 	 	36,114	 	
Other	 	 	24,878	 	 	 	23,218	 	
 	 	 	 	 	 	 	
Total deferred credits and other	 	 	47,126	 	 	 	92,351	 	

Common stock equity	 	 	 	 	 	 	 	 	
Common stock	 	 	2,133,733	 	 	 	2,587,201	 	
Accumulated other comprehensive income (loss)	 	 	(15,863	)	 	 	17,512	 	
Retained earnings	 	 	1,413,741	 	 	 	895,284	 	
 	 	 	 	 	 	 	
Total common stock equity	 	 	3,531,611	 	 	 	3,499,997	 	

Total Liabilities and Common Stock Equity	 	$	3,830,536	 	 	$	3,974,756	 	

			
(a)	 	Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.	
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PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Year Ended December 31	 	
 	 	2007 (a)	 	 	2006	 	 	2005	 	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	307,143	 	 	$	327,255	 	 	$	176,267	 	
Less: equity in earnings of subsidiaries — net	 	 	(287,078	)	 	 	(324,504	)	 	 	(58,759	)	
 	 	 	 	 	 	 	 	 	 	
Net income attributable to Pinnacle West	 	 	20,065	 	 	 	2,751	 	 	 	117,508	 	
Adjustments to reconcile net income to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	
Depreciation and amortization	 	 	320	 	 	 	470	 	 	 	551	 	
Deferred income taxes	 	 	(24,192	)	 	 	30,384	 	 	 	(19,929	)	
Change in mark-to-market valuations	 	 	53,228	 	 	 	21,698	 	 	 	(15,162	)	
Customer and other receivables	 	 	112,543	 	 	 	2,816	 	 	 	1,730	 	
Accounts payable	 	 	(57,978	)	 	 	(55,675	)	 	 	43,969	 	
Accrued taxes	 	 	25,127	 	 	 	(49,529	)	 	 	(84,758	)	
Change in risk management and trading — net	 	 	(11,602	)	 	 	65,633	 	 	 	(82,650	)	
Other net	 	 	(104,968	)	 	 	(20,746	)	 	 	102,432	 	
 	 	 	 	 	 	 	 	 	 	
Net cash flow (used for) provided by operating activities	 	 	12,543	 	 	 	(2,198	)	 	 	63,691	 	

Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	
Investments in and advances to subsidiaries — net	 	 	(83,993	)	 	 	(4,677	)	 	 	(230,229	)	
Repayments and advances of loans from subsidiaries	 	 	(4,800	)	 	 	2,686	 	 	 	2,402	 	
Dividends received from subsidiaries	 	 	180,000	 	 	 	180,000	 	 	 	220,000	 	
Purchases of investment securities	 	 	—	 	 	 	(147,501	)	 	 	(1,485,655	)	
Proceeds from sale of investment securities	 	 	—	 	 	 	147,501	 	 	 	1,485,683	 	
 	 	 	 	 	 	 	 	 	 	
Net cash flow (used for) provided by investing activities	 	 	91,207	 	 	 	178,009	 	 	 	(7,799	)	

Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	
Issuance of long-term debt	 	 	—	 	 	 	175,000	 	 	 	—	 	
Short-term borrowings and payments — net	 	 	87,371	 	 	 	27,900	 	 	 	—	 	
Dividends paid on common stock	 	 	(210,473	)	 	 	(201,221	)	 	 	(186,677	)	
Repayment of long-term debt	 	 	(115	)	 	 	(298,687	)	 	 	(165,104	)	
Common stock equity issuance	 	 	19,593	 	 	 	35,834	 	 	 	290,542	 	
 	 	 	 	 	 	 	 	 	 	
Net cash flow used for financing activities	 	 	(103,624	)	 	 	(261,174	)	 	 	(61,239	)	

Net increase (decrease) in cash and cash equivalents	 	 	126	 	 	 	(85,363	)	 	 	(5,347	)	

Cash and cash equivalents at beginning of year	 	 	11	 	 	 	85,374	 	 	 	90,721	 	

Cash and cash equivalents at end of year	 	$	137	 	 	$	11	 	 	$	85,374	 	

			
(a)	 	Pinnacle West Marketing & Trading began operations in early 2007. These operations were conducted by a division of Pinnacle West through the end of 2006.	
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PINNACLE WEST CAPITAL CORPORATION
SCHEDULE II — RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Column C	 	 	 	 	 	 	
 	 	Column B	 	Additions	 	 	 	 	 	Column E	
 	 	Balance at	 	Charged to	 	Charged	 	 	 	 	 	Balance	
Column A	 	beginning	 	cost and	 	to other	 	Column D	 	at end of	
Description	 	of period	 	expenses	 	accounts	 	Deductions	 	period	
Reserve for uncollectibles:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2007	 	$	5,597	 	 	$	4,130	 	 	$	—	 	 	$	4,945	 	 	$	4,782	 	
2006	 	 	4,979	 	 	 	4,096	 	 	 	—	 	 	 	3,478	 	 	 	5,597	 	
2005	 	 	4,896	 	 	 	2,638	 	 	 	—	 	 	 	2,555	 	 	 	4,979	 	
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ARIZONA PUBLIC SERVICE COMPANY
SCHEDULE II — RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Column C	 	 	 	 	 	 	
 	 	Column B	 	Additions	 	 	 	 	 	Column E	
 	 	Balance at	 	Charged to	 	Charged	 	 	 	 	 	Balance	
Column A	 	beginning	 	cost and	 	to other	 	Column D	 	at end of	
Description	 	of period	 	expenses	 	accounts	 	Deductions	 	period	
Reserve for uncollectibles:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2007	 	$	4,223	 	 	$	5,059	 	 	$	—	 	 	$	5,018	 	 	$	4,264	 	
2006	 	 	3,568	 	 	 	4,096	 	 	 	—	 	 	 	3,441	 	 	 	4,223	 	
2005	 	 	3,444	 	 	 	2,638	 	 	 	—	 	 	 	2,514	 	 	 	3,568	 	
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
     None.
ITEM 9A. CONTROLS AND PROCEDURES
     (a) Disclosure Controls and Procedures
     The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78a et seq .) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
     Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of December 31, 2007. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.
     APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of December 31, 2007. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.
     (b) Management’s Annual Reports on Internal Control Over Financial Reporting
     Reference is made to “Management’s Report on Internal Control Over Financial Reporting (Pinnacle West Capital Corporation)” on page 74 of this report and “Management’s Report on Internal Control Over Financial Reporting (Arizona Public Service Company)” on page 129 of this report.
     (c) Attestation Reports of the Registered Public Accounting Firm
     Reference is made to “Report of Independent Registered Public Accounting Firm” on page 75 of this report and “Report of Independent Registered Public Accounting Firm” on page 130 of this report on the internal control over financial reporting of Pinnacle West and APS, respectively.
     (d) Changes In Internal Control Over Financial Reporting
     The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of
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financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
     No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended December 31, 2007 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
     None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS
AND CORPORATE GOVERNANCE OF PINNACLE WEST
     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance,” “Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting Compliance” in the Pinnacle West Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 21, 2008 (the “2008 Proxy Statement”) and to the Supplemental Item — “Executive Officers of Pinnacle West” in Part I of this report.
     Pinnacle West has adopted a Code of Ethics for Financial Professionals that applies to professional employees in the areas of finance, accounting, internal audit, energy risk management, marketing and trading financial control, tax, investor relations, and treasury and also includes Pinnacle West’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and officers holding substantially equivalent positions at Pinnacle West’s subsidiaries. The Code of Ethics for Financial Professionals is posted on Pinnacle West’s website at www.pinnaclewest.com . Pinnacle West intends to satisfy the requirements under Item 5.05 of Form 8-K regarding disclosure of amendments to, or waivers from, provisions of the Code of Ethics for Financial Professionals by posting such information on Pinnacle West’s website.
ITEM 11. EXECUTIVE COMPENSATION
     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance — How are directors compensated?” and “Executive Compensation” in the 2008 Proxy Statement.
ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
     Reference is hereby made to “Shares of Pinnacle West Stock Owned by Management and Large Shareholders” in the 2008 Proxy Statement.
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Securities Authorized for Issuance Under Equity Compensation Plans
     The following table sets forth information as of December 31, 2007 with respect to our compensation plans and individual compensation arrangements under which our equity securities are authorized for issuance.
EQUITY COMPENSATION PLAN INFORMATION
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Number of securities	 	
 	 	 	 	 	 	 	 	 	 	remaining available	 	
 	 	 	 	 	 	 	 	 	 	for future issuance	 	
 	 	 	 	 	 	 	 	 	 	under equity	 	
 	 	Number of securities	 	 	Weighted-average	 	 	compensation plans	 	
 	 	to be issued upon	 	 	exercise price of	 	 	(excluding	 	
 	 	exercise of	 	 	outstanding	 	 	securities	 	
 	 	outstanding options,	 	 	options, warrants	 	 	reflected in column	 	
 	 	warrants and rights	 	 	and rights	 	 	(a))	 	
Plan Category	 	(a) 1	 	 	(b) 2	 	 	(c) 3	 	
Equity compensation plans approved by security holders	 	 	2,008,887	 	 	$	40.84	 	 	 	7,950,520	 	
Equity compensation plans not approved by security holders	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	
Total	 	 	2,008,887	 	 	$	40.84	 	 	 	7,950,520	 	

			
1	 	This amount includes shares subject to outstanding options as well as shares subject to outstanding performance share awards and restricted stock unit awards at the maximum amount of shares issuable under such awards. However, payout of the performance share awards is contingent on the Company reaching certain levels of performance during a three-year performance period. If the performance criteria for these awards are not fully satisfied, the award recipient will receive less than the maximum number of shares available under these grants and may receive nothing from these grants.	
 		
2	 	The weighted average exercise price in this column does not take performance share awards or restricted stock unit awards into account, as those awards have no exercise price.	
 		
3	 	Awards can take the form of options, stock appreciation rights, restricted stock, performance shares, performance share units, performance cash, stock grants, dividend equivalents, and restricted stock units. .	
      Equity Compensation Plans Approved By Security Holders
     Amounts in column (a) in the table above include shares subject to awards outstanding under three equity compensation plans that were approved by our shareholders: (a) the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan, under which no new stock awards may be granted; (b) the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan (the “2002 Plan”), under which no new stock awards may be granted; and (c) the Pinnacle West Capital
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Corporation 2007 Long-Term Incentive Plan (the “2007 Plan”), which was approved by our shareholders at our 2007 annual meeting of shareholders. Although we cannot issue additional awards under the 2002 Plan, shares subject to outstanding awards under the 2002 Plan that expire or are cancelled or terminated will be available for issuance under the 2007 Plan. See Note 16 of the Notes to Consolidated Financial Statements for additional information regarding these plans.
      Equity Compensation Plans Not Approved By Security Holders
     The Company does not have any equity compensation plans under which shares can still be issued that have not been approved by shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
     Reference is hereby made to “Information About Our Board, Its Committees and Our Corporate Governance” and to “Related Party Transactions” in the 2008 Proxy Statement.
ITEM 14. PRINCIPAL ACCOUNTANT
FEES AND SERVICES
Pinnacle West
     Reference is hereby made to “Audit Matters — What fees were paid to our independent registered public accountants in 2006 and 2007?” and “What are the Audit Committee’s pre-approval policies?” in the 2008 Proxy Statement.
APS
     The following fees were paid to APS’ independent registered public accountants, Deloitte & Touche LLP, for the last two fiscal years:
 	 	 	 	 	 	 	 	 	
Type of Service	 	2006	 	2007	
Audit Fees (1)	 	$	1,925,550	 	 	$	1,921,601	 	
Audit-Related Fees (2)	 	 	167,912	 	 	 	178,840	 	
Tax Fees (3)	 	 	17,096	 	 	 	7,751	 	

(1)	 	The aggregate fees billed for services rendered for the audit of annual financial statements and for review of financial statements included in Reports on Form 10-Q.	
 		
(2)	 	The aggregate fees billed for assurance services that are reasonably related to the performance of the audit or review of the financial statements that are not included in Audit Fees reported above, which primarily consist of fees for employee benefit plan audits.	
 		
(3)	 	The aggregate fees billed primarily for tax compliance and tax planning.	
     Pinnacle West’s Audit Committee pre-approves each audit service and non-audit service to be provided by APS’ independent public accountants. The Audit Committee has delegated to the Chairman of the Audit Committee the authority to pre-approve audit and non-audit services to be
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performed by the independent public accountants if the services are not expected to cost more than $50,000. The Chairman must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the services performed by Deloitte & Touche LLP for APS were pre-approved by the Audit Committee.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Financial Statements and Financial Statement Schedules
     See the Index to Financial Statements and Financial Statement Schedule in Part II, Item 8.
Exhibits Filed
     The documents listed below are being filed or have previously been filed on behalf of Pinnacle West or APS and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith.
 	 	 	 	 	 	 	 	 	
Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
3.1	 	Pinnacle West	 	Articles of Incorporation, restated as of May 23, 2007	 	4.1 to Pinnacle West/APS May 23, 2007 Form 8-K Report, File Nos. 1-8962 and 1-4473	 	5-25-07	
 	 	 	 	 	 	 	 	 	
3.2	 	Pinnacle West	 	Pinnacle West Capital Corporation Bylaws, amended as of May 23, 2007	 	4.2 to Pinnacle West/APS May 23, 2007 Form 8-K Report, File Nos. 1-8962 and 1-4473	 	5-25-07	
 	 	 	 	 	 	 	 	 	
3.3	 	APS	 	Articles of Incorporation, restated as of May 25, 1988	 	4.2 to APS’ Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	 	9-29-93	
 	 	 	 	 	 	 	 	 	
3.4	 	APS	 	Arizona Public Service Company Bylaws, amended as of June 23, 2004	 	3.1 to APS’ June 30, 2004 Form 10-Q Report, File No. 1-4473	 	8-9-04	
 	 	 	 	 	 	 	 	 	
4.1	 	Pinnacle West	 	Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value	 	4.2 to Pinnacle West’s 1988 Form 10-K Report, File No. 1-8962	 	3-31-89	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
4.2	 	Pinnacle West APS	 	Indenture dated as of January 1, 1995 among APS and The Bank of New York, as Trustee	 	4.6 to APS’ Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473	 	1-11-95	
 	 	 	 	 	 	 	 	 	
4.2a	 	Pinnacle West APS	 	First Supplemental Indenture dated as of January 1, 1995	 	4.4 to APS’ Registration Statement Nos. 33-61228 and 33-55473 by means of January 1, 1995 Form 8-K Report, File No. 1-4473	 	1-11-95	
 	 	 	 	 	 	 	 	 	
4.3	 	Pinnacle West APS	 	Indenture dated as of November 15, 1996 among APS and The Bank of New York, as Trustee	 	4.5 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333- 15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473	 	11-22-96	
 	 	 	 	 	 	 	 	 	
4.3a	 	Pinnacle West APS	 	First Supplemental Indenture dated as of November 15, 1996	 	4.6 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report, File No. 1-4473	 	11-22-96	
 	 	 	 	 	 	 	 	 	
4.3b	 	Pinnacle West APS	 	Second Supplemental Indenture dated as of April 1, 1997	 	4.10 to APS’ Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report, File No. 1-4473	 	4-9-97	
 	 	 	 	 	 	 	 	 	
4.3c	 	Pinnacle West APS	 	Third Supplemental Indenture dated as of November 1, 2002	 	10.2 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962	 	5-15-03	
 	 	 	 	 	 	 	 	 	
4.4	 	Pinnacle West	 	Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to Senior Debt Securities	 	4.1 to Pinnacle West’s Registration Statement No. 333-52476	 	12-21-00	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
4.4a	 	Pinnacle West	 	First Supplemental Indenture dated as of March 15, 2001	 	4.1 to Pinnacle West’s Registration Statement No. 333-52476 by means of March 26, 2001 Form 8-K Report, File No. 1-8962	 	3-26-01	
 	 	 	 	 	 	 	 	 	
4.4b	 	Pinnacle West	 	Second Supplemental Indenture dated as of November 1, 2003	 	4.20 to Pinnacle West’s Registration Statement No. 333-101457 by means of November 6, 2003 Form 8-K Report, File No. 1-8962	 	11-12-03	
 	 	 	 	 	 	 	 	 	
4.5	 	Pinnacle West	 	Indenture dated as of December 1, 2000 between the Company and The Bank of New York, as Trustee, relating to subordinated Debt Securities	 	4.2 to Pinnacle West’s Registration Statement No. 333-52476	 	12-21-00	
 	 	 	 	 	 	 	 	 	
4.6	 	Pinnacle West APS	 	Indenture dated as of January 15, 1998 among APS and The Chase Manhattan Bank, as Trustee	 	4.10 to APS’ Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473	 	1-16-98	
 	 	 	 	 	 	 	 	 	
4.6a	 	Pinnacle West APS	 	First Supplemental Indenture dated as of January 15, 1998	 	4.3 to APS’ Registration Statement Nos. 333-15379 and 333-27551 by means of January 13, 1998 Form 8-K Report, File No. 1-4473	 	1-16-98	
 	 	 	 	 	 	 	 	 	
4.6b	 	Pinnacle West APS	 	Second Supplemental Indenture dated as of February 15, 1999	 	4.3 to APS’ Registration Statement Nos. 333-27551 and 333-58445 by means of February 18, 1999 Form 8-K Report, File No. 1-4473	 	2-22-99	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
4.6c	 	Pinnacle West APS	 	Third Supplemental Indenture dated as of November 1, 1999	 	4.5 to APS’ Registration Statement Nos. 333-58445 by means of November 2, 1999 Form 8-K Report, File No. 1-4473	 	11-5-99	
 	 	 	 	 	 	 	 	 	
4.6d	 	Pinnacle West APS	 	Fourth Supplemental Indenture dated as of August 1, 2000	 	4.1 to APS’ Registration Statement No. 333-58445 and 333-94277 by means of August 2, 2000 Form 8-K Report, File No. 1-4473	 	8-4-00	
 	 	 	 	 	 	 	 	 	
4.6e	 	Pinnacle West APS	 	Fifth Supplemental Indenture dated as of October 1, 2001	 	4.1 to APS’ September 30, 2001 Form 10-Q, File No. 1-4473	 	11-6-01	
 	 	 	 	 	 	 	 	 	
4.6f	 	Pinnacle West APS	 	Sixth Supplemental Indenture dated as of March 1, 2002	 	4.1 to APS’ Registration Statement Nos. 333-63994 and 333-83398 by means of February 26, 2002 Form 8-K Report, File No. 1-4473	 	2-28-02	
 	 	 	 	 	 	 	 	 	
4.6g	 	Pinnacle West APS	 	Seventh Supplemental Indenture dated as of May 1, 2003	 	4.1 to APS’ Registration Statement No. 333-90824 by means of May 7, 2003 Form 8-K Report, File No. 1-4473	 	5-9-03	
 	 	 	 	 	 	 	 	 	
4.6h	 	Pinnacle West APS	 	Eighth Supplemental Indenture dated as of June 15, 2004	 	4.1 to APS’ Registration Statement No. 333-106772 by means of June 24, 2004 Form 8-K Report, File No. 1-4473	 	6-28-04	
 	 	 	 	 	 	 	 	 	
4.6i	 	Pinnacle West APS	 	Ninth Supplemental Indenture dated as of August 15, 2005	 	4.1 to APS’ Registration Statements Nos. 333-106772 and 333-121512 by means of August 17, 2005 Form 8-K Report, File No. 1-4473	 	8-22-05	
 	 	 	 	 	 	 	 	 	
4.6j	 	APS	 	Tenth Supplemental Indenture dated as of August 1, 2006	 	4.1 to APS’ July 31, 2006 Form 8-K Report, File No. 1-4473	 	8-2-06	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
4.7	 	Pinnacle West	 	Amended and Restated Rights Agreement, dated as of March 26, 1999, between Pinnacle West Capital Corporation and BankBoston, N.A., as Rights Agent, including (i) as Exhibit A thereto the form of Amended Certificate of Designation of Series A Participating Preferred Stock of Pinnacle West Capital Corporation, (ii) as Exhibit B thereto the form of Rights Certificate and (iii) as Exhibit C thereto the Summary of Right to Purchase Preferred Shares	 	4.1 to Pinnacle West’s March 22, 1999 Form 8-K Report, File No. 1-8962	 	4-19-99	
 	 	 	 	 	 	 	 	 	
4.7a	 	Pinnacle West	 	Amendment to Rights Agreement, effective as of January 1, 2002	 	4.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
4.8	 	Pinnacle West	 	Second Amended and Restated Investor’s Advantage Plan dated as of June 23, 2004	 	4.4 to Pinnacle West’s June 23, 2004 Form 8-K Report, File No. 1-8962	 	8-9-04	
 	 	 	 	 	 	 	 	 	
4.9	 	Pinnacle West	 	Agreement, dated March 29, 1988, relating to the filing of instruments defining the rights of holders of long-term debt not in excess of 10% of the Company’s total assets	 	4.1 to Pinnacle West’s 1987 Form 10-K Report, File No. 1-8962	 	3-30-88	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
4.9a	 	Pinnacle West APS	 	Agreement, dated March 21, 1994, relating to the filing of instruments defining the rights of holders of APS long-term debt not in excess of 10% of APS’ total assets	 	4.1 to APS’ 1993 Form 10-K Report, File No. 1-4473	 	3-30-94	
 	 	 	 	 	 	 	 	 	
10.1.1	 	Pinnacle West APS	 	Two separate Decommissioning Trust Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee	 	10.2 to APS’ September 30, 1991 Form 10-Q Report, File No. 1-4473	 	11-14-91	
 	 	 	 	 	 	 	 	 	
10.1.1a	 	Pinnacle West APS	 	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 1, 1994	 	10.1 to APS’ 1994 Form 10- K Report, File No. 1-4473	 	3-30-95	
 	 	 	 	 	 	 	 	 	
10.1.1b	 	Pinnacle West APS	 	Amendment No. 1 to Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 1, 1994	 	10.2 to APS’ 1994 Form 10-K Report, File No. 1-4473	 	3-30-95	
 	 	 	 	 	 	 	 	 	
10.1.1c	 	Pinnacle West APS	 	Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 1) dated as of July 1, 1991	 	10.4 to APS’ 1996 Form 10-K Report , File No. 1-4473	 	3-28-97	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.1.1d	 	Pinnacle West APS	 	Amendment No. 2 to APS Decommissioning Trust Agreement (PVNGS Unit 3) dated as of July 1, 1991	 	10.6 to APS’ 1996 Form 10-K Report, File No. 1-4473	 	3-28-97	
 	 	 	 	 	 	 	 	 	
10.1.1e	 	Pinnacle West APS	 	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of March 18, 2002	 	10.2 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
10.1.1f	 	Pinnacle West APS	 	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of March 18, 2002	 	10.4 to Pinnacle West’s March 2002 Form 10-Q Report, File No. 1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
10.1.1g	 	Pinnacle West APS	 	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 19, 2003	 	10.3 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	 	3-15-04	
 	 	 	 	 	 	 	 	 	
10.1.1h	 	Pinnacle West APS	 	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 19, 2003	 	10.5 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	 	3-15-04	
 	 	 	 	 	 	 	 	 	
10.1.1i	 	Pinnacle West APS	 	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of May 1, 2007	 	10.1 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473	 	5-9-07	
 	 	 	 	 	 	 	 	 	
10.1.1j	 	Pinnacle West APS	 	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of May 1, 2007	 	10.2 to Pinnacle West/APS March 31, 2007 Form 10-Q Report, File Nos. 1-8962 and 104473	 	5-9-07	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.1.2	 	Pinnacle West APS	 	Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992, among APS, Mellon Bank, N.A., as Decommissioning Trustee, and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee under two separate Trust Agreements, each with a separate Equity Participant, and as Lessor under two separate Facility Leases, each relating to an undivided interest in PVNGS Unit 2	 	10.1 to Pinnacle West’s 1991 Form 10-K Report, File No. 1-8962	 	3-26-92	
 	 	 	 	 	 	 	 	 	
10.1.2a	 	Pinnacle West APS	 	First Amendment to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1992	 	10.2 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
10.1.2b	 	Pinnacle West APS	 	Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994	 	10.3 to APS’ 1994 Form 10-K Report, File No. 1-4473	 	3-30-95	
 	 	 	 	 	 	 	 	 	
10.1.2c	 	Pinnacle West APS	 	Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of January 31, 1992	 	10.1 to APS’ June 30, 1996 Form 10-Q Report, File No. 1-4473	 	8-9-96	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.1.2d	 	Pinnacle West APS	 	Amendment No. 4 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2) dated as of January 31, 1992	 	APS 10.5 to APS’ 1996 Form 10-K Report, File No. 1-4473	 	3-28-97	
 	 	 	 	 	 	 	 	 	
10.1.2e	 	Pinnacle West APS	 	Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 30, 2000	 	10.1 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
10.1.2f	 	Pinnacle West APS	 	Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of March 18, 2002	 	10.3 to Pinnacle West’s March 31, 2002 Form 10-Q Report, File No. 1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
10.1.2g	 	Pinnacle West APS	 	Amendment No. 7 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of December 19, 2003	 	10.4 to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	 	3-15-04	
 	 	 	 	 	 	 	 	 	
10.1.2h	 	Pinnacle West APS	 	Amendment No. 8 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of April 1, 2007	 	 	 	 	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.2.1 b	 	Pinnacle West APS	 	Arizona Public Service Company Deferred Compensation Plan, as restated, effective January 1, 1984, and the second and third amendments thereto, dated December 22, 1986, and December 23, 1987 respectively	 	10.4 to APS’ 1988 Form 10-K Report, File No. 1-4473	 	3-8-89	
 	 	 	 	 	 	 	 	 	
10.2.1a b	 	Pinnacle West APS	 	Third Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993	 	10.3A to APS’ 1993 Form 10-K Report, File No. 1-4473	 	3-30-94	
 	 	 	 	 	 	 	 	 	
10.2.1b b	 	Pinnacle West APS	 	Fourth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective as of May 1, 1993	 	10.2 to APS’ September 30, 1994 Form 10-Q Report, File No. 1-4473	 	11-10-94	
 	 	 	 	 	 	 	 	 	
10.2.1c b	 	Pinnacle West APS	 	Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 1997	 	10.3A to APS’ 1996 Form 10-K Report, File No. 1-4473	 	3-28-97	
 	 	 	 	 	 	 	 	 	
10.2.1d b	 	Pinnacle West APS	 	Sixth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective January 1, 2001	 	10.8A to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962	 	3-14-01	
 	 	 	 	 	 	 	 	 	
10.2.2 b	 	Pinnacle West APS	 	Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986	 	10.1 to APS’ June 30, 1986 Form 10-Q Report, File No. 1-4473	 	8-13-86	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.2.2a b	 	Pinnacle West APS	 	Second Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of January 1, 1993	 	10.2A to APS’ 1993 Form 10-K Report, File No. 1-4473	 	3-30-94	
 	 	 	 	 	 	 	 	 	
10.2.2b b	 	Pinnacle West APS	 	Third Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of May 1, 1993	 	10.1 to APS’ September 30, 1994 Form 10-Q Report, File No. 1-4473	 	11-10-94	
 	 	 	 	 	 	 	 	 	
10.2.2c b	 	Pinnacle West APS	 	Fourth Amendment to the Arizona Public Service Company Directors Deferred Compensation Plan, effective as of January 1, 1999	 	10.8A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.2.3 b	 	Pinnacle West APS	 	Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996	 	10.14A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.2.3a b	 	Pinnacle West APS	 	First Amendment dated December 7, 1999 to the Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans	 	10.15A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	 	3-30-00	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.2.4 b	 	Pinnacle West APS	 	Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996	 	10.10A to APS’ 1995 Form 10-K Report, File No. 1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.2.4a b	 	Pinnacle West APS	 	First Amendment effective as of January 1, 1999, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	 	10.7A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.2.4b b	 	Pinnacle West APS	 	Second Amendment effective January 1, 2000 to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	 	10.10A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	 	3-30-00	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.2.4c b	 	Pinnacle West APS	 	Third Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective as of January 1, 2002	 	10.3 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962	 	5-15-03	
 	 	 	 	 	 	 	 	 	
10.2.4d b	 	Pinnacle West APS	 	Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan, effective January 1, 2003	 	10.64 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-13-06	
 	 	 	 	 	 	 	 	 	
10.2.5 b	 	Pinnacle West APS	 	Schedules of William J. Post and Jack E. Davis to Arizona Public Service Company Deferred Compensation Plan, as amended	 	10.3A to Pinnacle West 2002 Form 10-K Report, File No. 1-8962	 	3-31-03	
 	 	 	 	 	 	 	 	 	
10.3.1 b	 	Pinnacle West APS	 	Pinnacle West Capital Corporation Supplement Excess Benefit Retirement Plan, amended and restated as of January 1, 2003	 	10.7A to Pinnacle West’s 2003 Form 10-K Report, File No. 1-8962	 	3-15-04	
 	 	 	 	 	 	 	 	 	
10.3.1a b	 	Pinnacle West APS	 	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 18, 2003	 	10.48b to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-13-06	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.4.1 b	 	Pinnacle West APS	 	Letter Agreement dated July 28, 1995 between Arizona Public Service Company and Armando B. Flores	 	10.16A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.4.2 b	 	Pinnacle West APS	 	Letter Agreement dated December 21, 1993, between APS and William L. Stewart	 	10.6A to APS’ 1994 Form 10-K Report, File No. 1-4473	 	3-30-95	
 	 	 	 	 	 	 	 	 	
10.4.3 b	 	Pinnacle West APS	 	Letter Agreement dated August 16, 1996 between APS and William L. Stewart	 	10.8 to APS’ 1996 Form 10-K Report, File No. 1-4473	 	3-28-97	
 	 	 	 	 	 	 	 	 	
10.4.4 b	 	Pinnacle West APS	 	Letter Agreement dated October 3, 1997 between APS and William L. Stewart	 	10.2 to APS’ September 30, 1997 Form 10-Q Report, File No. 1-4473	 	11-12-97	
 	 	 	 	 	 	 	 	 	
10.4.5 b	 	Pinnacle West APS	 	Letter Agreement dated December 13, 1999 between APS and William L. Stewart	 	10.9A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.4.5a b	 	Pinnacle West APS	 	Amendment to Letter Agreement, effective as of January 1, 2002, between APS and William L. Stewart	 	10.1 to Pinnacle West’s June 30, 2002 Form 10-Q Report, File No. 1-8962	 	8-13-02	
 	 	 	 	 	 	 	 	 	
10.4.6 b	 	Pinnacle West APS	 	Letter Agreement dated October 3, 1997 between Arizona Public Service Company and James M. Levine	 	10.17A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.4.7 b	 	Pinnacle West APS	 	Employment Agreement dated February 27, 2003 between APS and James M. Levine	 	10.1 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962	 	5-15-03	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.4.8 b	 	Pinnacle West APS	 	Summary of James M. Levine Retirement Benefits	 	10.2 to Pinnacle West’s March 31, 2003 Form 10-Q Report, File No. 1-8962	 	5-15-03	
 	 	 	 	 	 	 	 	 	
10.4.9 b	 	Pinnacle West APS	 	Employment Agreement, effective as of October 1, 2002, between APS and James M. Levine	 	10.1 to Pinnacle West’s September 30, 2002 Form 10-Q Report, File No. 1-8962	 	11-14-02	
 	 	 	 	 	 	 	 	 	
10.4.9a b	 	Pinnacle West APS	 	Amendment to Agreement between APS and James M. Levine effective October 11, 2002	 	10.2 to Pinnacle West’s September 30, 2004 Form 10-Q Report, File No. 1-8962	 	11-8-04	
 	 	 	 	 	 	 	 	 	
10.4.9b b	 	Pinnacle West APS	 	Second Amendment to Agreement between APS and James M. Levine effective as of 1-1-05	 	10.79.2 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-16-05	
 	 	 	 	 	 	 	 	 	
10.4.10 b	 	Pinnacle West APS	 	Letter Agreement dated June 28, 2001 between Pinnacle West Capital Corporation and Steve Wheeler	 	10.4A to Pinnacle West’s 2002 Form 10-K Report, File No. 1-8962	 	3-31-03	
 	 	 	 	 	 	 	 	 	
10.4.11 b	 	APS	 	Letter Agreement dated December 20, 2006 between APS and Randall K. Edington	 	10.78 to Pinnacle West/APS 2006 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	2-28-07	
 	 	 	 	 	 	 	 	 	
10.5.1 bd	 	Pinnacle West APS	 	Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries	 	10.77 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-13-06	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.5.1a bd	 	Pinnacle West APS	 	Form of Amended and Restated Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries	 	10.4 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473	 	11-5-07	
 	 	 	 	 	 	 	 	 	
10.5.2 bd	 	Pinnacle West APS	 	Form of Key Executive Employment and Severance Agreement between Pinnacle West and certain officers of Pinnacle West and its subsidiaries	 	10.3 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File Nos. 1-8962 and 1-4473	 	11-5-07	
 	 	 	 	 	 	 	 	 	
10.6.1 b	 	Pinnacle West APS	 	Pinnacle West Capital Corporation 1994 Long- Term Incentive Plan, effective as of March 23, 1994	 	Appendix A to the Proxy Statement for the Plan Report for Pinnacle West’s 1994 Annual Meeting of Shareholders, File No. 1-8962	 	4-15-94	
 	 	 	 	 	 	 	 	 	
10.6.1a b	 	Pinnacle West APS	 	First Amendment dated December 7, 1999 to the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan	 	10.12A to Pinnacle West’s 1999 Form 10-K Report, File No. 1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.6.2 b	 	Pinnacle West APS	 	Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	 	10.5A to Pinnacle West’s 2002 Form 10-K Report	 	3-31-03	
 	 	 	 	 	 	 	 	 	
10.6.2a bd	 	Pinnacle West APS	 	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	 	10.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	 	12-15-05	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.6.2b bd	 	Pinnacle West APS	 	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	 	10.1 to Pinnacle West/APS December 31, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	 	2-1-06	
 	 	 	 	 	 	 	 	 	
10.6.2c d	 	Pinnacle West APS	 	Performance Accelerated Stock Option Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	 	10.98 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-16-05	
 	 	 	 	 	 	 	 	 	
10.6.2d bd	 	Pinnacle West APS	 	Stock Ownership Incentive Agreement under Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	 	10.99 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-16-05	
 	 	 	 	 	 	 	 	 	
10.6.2e bd	 	Pinnacle West APS	 	Performance Share Agreement under the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan	 	10.91 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-13-06	
 	 	 	 	 	 	 	 	 	
10.6.3 b	 	Pinnacle West	 	Pinnacle West Capital Corporation 2000 Director Equity Plan	 	99.1 to Pinnacle West’s Registration Statement on Form S-8 (No. 333-40796), File No. 1-8962)	 	7-3-00	
 	 	 	 	 	 	 	 	 	
10.6.4 b	 	Pinnacle West	 	Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	 	Appendix B to the Proxy Statement for Pinnacle West’s 2007 Annual Meeting of Shareholders, File No. 1-8962	 	4-20-07	
 	 	 	 	 	 	 	 	 	
10.6.4a b	 	Pinnacle West	 	First Amendment to the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	 	10.2 to Pinnacle West/APS April 18, 2007 Form 8-K Report, File No. 1-8962	 	4-20-07	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.6.4b bd	 	Pinnacle West	 	Form of Restricted Stock Unit Agreement Under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	 	10.1 to Pinnacle West/APS June 30, 2007 Form 10-Q Report, File No. 1-8962	 	8-7-07	
 	 	 	 	 	 	 	 	 	
10.6.4c b	 	Pinnacle West	 	Description of Annual Stock Grants to Non-Employee Directors	 	10.1 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962	 	11-5-07	
 	 	 	 	 	 	 	 	 	
10.6.4d b	 	Pinnacle West	 	Description of Stock Grant to W. Douglas Parker	 	10.2 to Pinnacle West/APS September 30, 2007 Form 10-Q Report, File No. 1-8962	 	11-5-07	
 	 	 	 	 	 	 	 	 	
10.6.4e bd	 	Pinnacle West APS	 	Form of Restricted Stock Unit Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	 	10.1 to Pinnacle West/APS January 22, 2008 Form 8-K Report, File Nos. 1-8962 and 1-4473	 	1-28-08	
 	 	 	 	 	 	 	 	 	
10.6.4f bd	 	Pinnacle West APS	 	Form of Performance Share Agreement under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	 	10.2 to Pinnacle West/APS January 22, 2008 Form 8-K Report, File Nos. 1-8962 and 1-4473	 	1-28-08	
 	 	 	 	 	 	 	 	 	
10.6.4g bd	 	Pinnacle West APS	 	Form of Restricted Stock Agreement Under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan	 	10.3 to Pinnacle West/APS January 22, 2008 Form 8-K Report, File Nos. 1-8962 and 1-4473	 	1-28-08	
 	 	 	 	 	 	 	 	 	
10.6.5 bd	 	Pinnacle West APS	 	Summary of 2008 CEO Variable Incentive Plan and Officer Variable Incentive Plan	 	 	 	 	
 	 	 	 	 	 	 	 	 	
10.7.1	 	Pinnacle West APS	 	Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant	 	5.01 to APS’ Form S-7 Registration Statement, File No. 2-59644	 	9-1-77	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.7.1a	 	Pinnacle West APS	 	Supplemental and Additional Indenture of Lease, including amendments and supplements to original lease with Navajo Tribe of Indians, Four Corners Plant	 	5.02 to APS’ Form S-7 Registration Statement, File No. 2-59644	 	9-1-77	
 	 	 	 	 	 	 	 	 	
10.7.1b	 	Pinnacle West APS	 	Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease Four Corners, dated April 25, 1985	 	10.36 to Pinnacle West’s Registration Statement on Form 8-B Report, File No. 1-8962	 	7-25-85	
 	 	 	 	 	 	 	 	 	
10.7.2	 	Pinnacle West APS	 	Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site	 	5.04 to APS’ Form S-7 Registration Statement, File No. 2-59644	 	9-1-77	
 	 	 	 	 	 	 	 	 	
10.7.2a	 	Pinnacle West APS	 	Application and Amendment No. 1 to Grant of multi-party rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985	 	10.37 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962	 	7-25-85	
 	 	 	 	 	 	 	 	 	
10.7.3	 	Pinnacle West APS	 	Application and Grant of Arizona Public Service Company rights- of-way and easements, Four Corners Plant Site	 	5.05 to APS’ Form S-7 Registration Statement, File No. 2-59644	 	9-1-77	
 	 	 	 	 	 	 	 	 	
10.7.3a	 	Pinnacle West APS	 	Application and Amendment No. 1 to Grant of Arizona Public Service Company rights-of-way and easements, Four Corners Power Plant Site dated April 25, 1985	 	10.38 to Pinnacle West’s Registration Statement on Form 8-B, File No. 1-8962	 	7-25-85	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.7.4	 	Pinnacle West APS	 	Four Corners Project Co-Tenancy Agreement Amendment No. 6	 	10.7 to Pinnacle West’s 2000 Form 10-K Report, File No. 1-8962	 	3-14-01	
 	 	 	 	 	 	 	 	 	
10.8.1	 	Pinnacle West APS	 	Indenture of Lease, Navajo Units 1, 2, and 3	 	5(g) to APS’ Form S-7 Registration Statement, File No. 2-36505	 	3-23-70	
 	 	 	 	 	 	 	 	 	
10.8.2	 	Pinnacle West APS	 	Application of Grant of rights-of-way and easements, Navajo Plant	 	5(h) to APS Form S-7 Registration Statement, File No. 2-36505	 	3-23-70	
 	 	 	 	 	 	 	 	 	
10.8.3	 	Pinnacle West APS	 	Water Service Contract Assignment with the United States Department of Interior, Bureau of Reclamation, Navajo Plant	 	5(l) to APS’ Form S-7 Registration Statement, File No. 2-394442	 	3-16-71	
 	 	 	 	 	 	 	 	 	
10.8.4	 	Pinnacle West APS	 	Navajo Project Co-Tenancy Agreement dated as of March 23, 1976, and Supplement No. 1 thereto dated as of October 18, 1976, Amendment No. 1 dated as of July 5, 1988, and Amendment No. 2 dated as of June 14, 1996; Amendment No. 3 dated as of February 11, 1997; Amendment No. 4 dated as of January 21, 1997; Amendment No. 5 dated as of January 23, 1998; Amendment No. 6 dated as of July 31, 1998	 	10.107 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-13-06	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.8.5	 	Pinnacle West APS	 	Navajo Project Participation Agreement dated as of September 30, 1969, and Amendment and Supplement No. 1 dated as of January 16, 1970, and Coordinating Committee Agreement No. 1 dated as of September 30, 1971	 	10.108 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-13-06	
 	 	 	 	 	 	 	 	 	
10.9.1	 	Pinnacle West APS	 	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles, and amendments 1-12 thereto	 	10. 1 to APS’ 1988 Form 10-K Report, File No. 1-4473	 	3-8-89	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.9.1a	 	Pinnacle West APS	 	Amendment No. 13, dated as of April 22, 1991, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	 	10.1 to APS’ March 31, 1991 Form 10-Q Report, File No. 1-4473	 	5-15-91	
 	 	 	 	 	 	 	 	 	
10.9.1b	 	Pinnacle West APS	 	Amendment No. 14 to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	 	99.1 to Pinnacle West’s June 30, 2000 Form 10-Q Report, File No. 1-8962	 	8-14-00	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.10.1	 	Pinnacle West APS	 	Asset Purchase and Power Exchange Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991	 	10.1 to APS’ June 30, 1991 Form 10-Q Report, File No. 1-4473	 	8-8-91	
 	 	 	 	 	 	 	 	 	
10.10.2	 	Pinnacle West APS	 	Long-Term Power Transaction Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8, 1991	 	10.2 to APS’ June 30, 1991 Form 10-Q Report, File No. 1-4473	 	8-8-91	
 	 	 	 	 	 	 	 	 	
10.10.2a	 	Pinnacle West APS	 	Amendment No. 1 dated April 5, 1995 to the Long-Term Power Transaction Agreement and Asset Purchase and Power Exchange Agreement between PacifiCorp and APS	 	10.3 to APS’ 1995 Form 10-K Report, File No. 1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.10.3	 	Pinnacle West APS	 	Restated Transmission Agreement between PacifiCorp and APS dated April 5, 1995	 	10.4 to APS’ 1995 Form 10-K Report, File No. 1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.10.4	 	Pinnacle West APS	 	Contract among PacifiCorp, APS and United States Department of Energy Western Area Power Administration, Salt Lake Area Integrated Projects for Firm Transmission Service dated May 5, 1995	 	10.5 to APS’ 1995 Form 10-K Report, File No. 1-4473	 	3-29-96	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.10.5	 	Pinnacle West APS	 	Reciprocal Transmission Service Agreement between APS and PacifiCorp dated as of March 2, 1994	 	10.6 to APS’ 1995 Form 10-K Report, File No. 1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.11.1	 	Pinnacle West APS	 	Amended and Restated Reimbursement Agreement among APS, the Banks party thereto, and JPMorgan Chase Bank, as Administrative Agent and Issuing Bank, dated as of July 22, 2002	 	10.100 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-16-05	
 	 	 	 	 	 	 	 	 	
10.11.2	 	Pinnacle West APS	 	Three-Year Credit Agreement dated as of May 21, 2004 between APS as Borrower, and the banks, financial institutions and other institutional lenders and initial issuing banks listed on the signature pages thereof	 	10.101 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-16-05	
 	 	 	 	 	 	 	 	 	
10.11.3	 	Pinnacle West APS	 	Amended and Restated Five-Year Credit Agreement dated as of December 9, 2005 between APS, as Borrower, Citibank, N.A., as Agent, and the lenders and other parties thereto	 	10.95 to Pinnacle West/APS 2005 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-13-06	
 	 	 	 	 	 	 	 	 	
10.11.4	 	Pinnacle West	 	$200,000,000 Senior Notes Uncommitted Master Shelf Agreement dated as of February 28, 2006	 	10.96 to Pinnacle West 2005 Form 10-K Report, File No. 1-8962	 	3-13-06	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.11.5	 	Pinnacle West	 	Amended and Restated Credit Agreement dated as of December 9, 2005 among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A., as Agent, and the other agent parties thereto	 	10.97 to Pinnacle West 2005 Form 10-K Report, File No. 1-8962	 	3-13-06	
 	 	 	 	 	 	 	 	 	
10.11.5a	 	Pinnacle West	 	First Amendment to Amended and Restated Credit Agreement, dated as of May 15, 2006, supplementing and amending the Amended and Restated Credit Agreement, dated as of December 9, 2005, among Pinnacle West Capital Corporation, as Borrower, JPMorgan Chase Bank, N.A. as Agent and the other parties thereto	 	10.1 to Pinnacle West’s June 30, 2006 Form 10-Q Report, File No. 1-8962	 	8-8-06	
 	 	 	 	 	 	 	 	 	
10.11.6	 	Pinnacle West APS	 	Credit Agreement dated as of October 19, 2004 among Pinnacle West, other lenders, and JPMorgan Chase Bank, as Administrative Agent	 	10.1 to Pinnacle West’s September 30, 2004 Form 10-Q Report, File No. 1-8962	 	11-8-04	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.11.7	 	APS	 	$500,000,000 Five-Year Credit Agreement dated as of September 29, 2006 among Arizona Public Service Company as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, The Bank of New York as Syndication Agent and Issuing Bank and the other parties thereto	 	10.1 to APS’ September 2006 Form 10-Q Report, File No. 1-4473	 	11-8-06	
 	 	 	 	 	 	 	 	 	
10.11.8	 	Pinnacle West APS	 	Amended and Restated Reimbursement Agreement among Arizona Public Service Company, The Banks party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and Issuing Bank, and Barclays Bank PLC, as Syndication Agent, dated as of May 19, 2005	 	99.6 to PinnacleWest/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473	 	8-9-05	
 	 	 	 	 	 	 	 	 	
10.12.1 c	 	Pinnacle West APS	 	Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	 	4.3 to APS’ Form S-3 Registration Statement, File No. 33-9480	 	10-24-86	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.12.1a c	 	Pinnacle West APS	 	Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	 	10.5 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	 	12-4-86	
 	 	 	 	 	 	 	 	 	
10.12.1b c	 	Pinnacle West APS	 	Amendment No. 2 dated as of June 1, 1987 to Facility Lease dated as of August 1, 1986 between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	 	10.3 to APS’ 1988 Form 10-K Report, File No. 1-4473	 	3-8-89	
 	 	 	 	 	 	 	 	 	
10.12.1c c	 	Pinnacle West APS	 	Amendment No. 3, dated as of March 17, 1993, to Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	 	10.3 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.12.2	 	Pinnacle West APS	 	Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	 	10.1 to APS’ November 18, 1986 Form 8-K Report, File No. 1-4473	 	1-20-87	
 	 	 	 	 	 	 	 	 	
10.12.2a	 	Pinnacle West APS	 	Amendment No. 1, dated as of August 1, 1987, to Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	 	4.13 to APS’ Form S-3 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473	 	8-24-87	
 	 	 	 	 	 	 	 	 	
10.12.2b	 	Pinnacle West APS	 	Amendment No. 2, dated as of March 17, 1993, to Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Lessor, and APS, as Lessee	 	10.4 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.13.1	 	Pinnacle West APS	 	Agreement No. 13904 (Option and Purchase of Effluent) with Cities of Phoenix, Glendale, Mesa, Scottsdale, Tempe, Town of Youngtown, and Salt River Project Agricultural Improvement and Power District, dated April 23, 1973	 	10.3 to APS’ 1991 Form 10-K Report, File No. 1-4473	 	3-19-92	
 	 	 	 	 	 	 	 	 	
10.13.2	 	Pinnacle West APS	 	Agreement between Pinnacle West Energy Corporation and Arizona Public Service Company for Transportation and Treatment of Effluent by and between Pinnacle West Energy Corporation and APS dated as of the 10 th day of April, 2001	 	10.102 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-16-05	
 	 	 	 	 	 	 	 	 	
10.13.3	 	Pinnacle West APS	 	Agreement for the Transfer and Use of Wastewater and Effluent by and between APS, SRP and PWE dated June 1, 2001	 	10.103 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-16-05	
 	 	 	 	 	 	 	 	 	
10.13.4	 	Pinnacle West APS	 	Agreement for the Sale and Purchase of Wastewater Effluent dated November 13, 2000, by and between the City of Tolleson, Arizona, APS and SRP	 	10.104 to Pinnacle West/APS 2004 Form 10-K Report, File Nos. 1-8962 and 1-4473	 	3-16-05	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.13.5	 	Pinnacle West	 	Operating Agreement	 	10.105 to Pinnacle West/APS 2004 Form	 	3-16-05	
 	 	APS	 	for the Co-Ownership of Wastewater Effluent dated November 16, 2000 by and between APS and SRP	 	10-K Report, File Nos. 1-8962 and 1-4473	 	 	
 	 	 	 	 	 	 	 	 	
10.13.6	 	Pinnacle West APS	 	Agreement for the Sale and Purchase of Wastewater Effluent with City of Tolleson and Salt River Agricultural Improvement and Power District, dated June 12, 1981, including Amendment No. 1 dated as of November 12, 1981 and Amendment No. 2 dated as of June 4, 1986	 	10.4 to APS’ 1991 Form 10-K Report, File 1-4473	 	3-19-92	
 	 	 	 	 	 	 	 	 	
10.14.1	 	Pinnacle West APS	 	Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high-level radioactive waste, ANPP	 	10.31 to Pinnacle West’s Form S-14 Registration Statement, File No. 2-96386	 	3-13-85	
 	 	 	 	 	 	 	 	 	
10.15.1	 	Pinnacle West APS	 	Territorial Agreement between APS and Salt River Project	 	10.1 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473	 	5-15-98	
 	 	 	 	 	 	 	 	 	
10.15.2	 	Pinnacle West APS	 	Power Coordination Agreement between APS and Salt River Project	 	10.2 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473	 	5-15-98	
 	 	 	 	 	 	 	 	 	
10.15.3	 	Pinnacle West APS	 	Memorandum of Agreement between APS and Salt River Project	 	10.3 to APS’ March 31, 1998 Form 10-Q Report, File No. 1-4473	 	5-15-98	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
10.15.3a	 	Pinnacle West APS	 	Addendum to Memorandum of Agreement between APS and Salt River Project dated as of May 19, 1998	 	10.2 to APS’ May 19, 1998 Form 8-K Report, File No. 1-4473	 	6-26-98	
 	 	 	 	 	 	 	 	 	
12.1	 	Pinnacle West	 	Ratio of Earnings to Fixed Charges	 	 	 	 	
 	 	 	 	 	 	 	 	 	
12.2	 	APS	 	Ratio of Earnings to Fixed Charges	 	 	 	 	
 	 	 	 	 	 	 	 	 	
12.3	 	Pinnacle West	 	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements	 	 	 	 	
 	 	 	 	 	 	 	 	 	
21.1	 	Pinnacle West	 	Subsidiaries of Pinnacle West	 	 	 	 	
 	 	 	 	 	 	 	 	 	
23.1	 	Pinnacle West	 	Consent of Deloitte & Touche LLP	 	 	 	 	
 	 	 	 	 	 	 	 	 	
23.2	 	APS	 	Consent of Deloitte & Touche LLP	 	 	 	 	
 	 	 	 	 	 	 	 	 	
31.1	 	Pinnacle West	 	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended	 	 	 	 	
 	 	 	 	 	 	 	 	 	
31.2	 	Pinnacle West	 	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended	 	 	 	 	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
31.3	 	APS	 	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended	 	 	 	 	
 	 	 	 	 	 	 	 	 	
31.4	 	APS	 	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended	 	 	 	 	
 	 	 	 	 	 	 	 	 	
32.1	 	Pinnacle West	 	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	 	 	 	 	
 	 	 	 	 	 	 	 	 	
32.2	 	APS	 	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	 	 	 	 	
 	 	 	 	 	 	 	 	 	
99.1	 	Pinnacle West APS	 	Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	 	4.2 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
99.1a	 	Pinnacle West APS	 	Supplemental Indenture to Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	 	4.3 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.2 c	 	Pinnacle West APS	 	Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	 	28.1 to APS’ September 30, 1992 Form 10-Q Report, File No. 1-4473	 	11-9-92	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
99.2a c	 	Pinnacle West APS	 	Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	 	10.8 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8, File No. 1-4473	 	12-4-86	
 	 	 	 	 	 	 	 	 	
99.2b c	 	Pinnacle West APS	 	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	 	28.4 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
99.3 c	 	Pinnacle West APS	 	Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	 	4.5 to APS’ Form S-3 Registration Statement, File No. 33-9480	 	10-24-86	
 	 	 	 	 	 	 	 	 	
99.3a c	 	Pinnacle West APS	 	Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	 	10.6 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8, File No. 1-4473	 	12-4-86	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
99.3b c	 	Pinnacle West APS	 	Supplemental Indenture No. 2 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee	 	4.4 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.4 c	 	Pinnacle West APS	 	Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	 	28.3 to APS’ Form S-3 Registration Statement, File No. 33-9480	 	10-24-86	
 	 	 	 	 	 	 	 	 	
99.4a c	 	Pinnacle West APS	 	Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	 	10.10 to APS’ September 30, 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8, File No. 1-4473	 	12-4-86	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
99.4b c	 	Pinnacle West APS	 	Amendment No. 2, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	 	28.6 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.5	 	Pinnacle West APS	 	Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Report Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, APS, and the Owner Participant named therein	 	28.2 to APS’ September 30, 1992 Form 10-Q Report, File No. 1-4473	 	11-9-92	
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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
99.5a	 	Pinnacle West APS	 	Amendment No. 1, dated as of August 1, 1987, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc. as Funding Corporation, State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, Chemical Bank, as Indenture Trustee, APS, and the Owner Participant named therein	 	28.20 to APS’ Form S-3 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473	 	8-10-87	
 	 	 	 	 	 	 	 	 	
99.5b	 	Pinnacle West APS	 	Amendment No. 2, dated as of March 17, 1993, to Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Corp., Inc., PVNGS II Funding Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Owner Participant named therein	 	28.5 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
 192 

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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
99.6	 	Pinnacle West APS	 	Trust Indenture, Mortgage Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	 	10.2 to APS’ November 18, 1986 Form 10-K Report, File No. 1-4473	 	1-20-87	
 	 	 	 	 	 	 	 	 	
99.6a	 	Pinnacle West APS	 	Supplemental Indenture No. 1, dated as of August 1, 1987, to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	 	4.13 to APS’ Form S-3 Registration Statement No. 33-9480 by means of August 1, 1987 Form 8-K Report, File No. 1-4473	 	8-24-87	
 193 

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Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
99.6b	 	Pinnacle West APS	 	Supplemental Indenture No. 2 to Trust Indenture Mortgage, Security Agreement and Assignment of Facility Lease, dated as of December 15, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Lease Indenture Trustee	 	4.5 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.7	 	Pinnacle West APS	 	Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	 	10.5 to APS’ November 18, 1986 Form 8-K Report, File No. 1-4473	 	1-20-87	
 	 	 	 	 	 	 	 	 	
99.7a	 	Pinnacle West APS	 	Amendment No. 1, dated as of March 17, 1993, to Assignment, Assumption and Further Agreement, dated as of December 15, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	 	28.7 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.8 c	 	Pinnacle West APS	 	Indemnity Agreement dated as of March 17, 1993 by APS	 	28.3 to APS’ 1992 Form 10-K Report, File No. 1-4473	 	3-30-93	
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Table of Contents

 	 	 	 	 	 	 	 	 	
Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit: a	 	Filed	
99.9	 	Pinnacle West APS	 	Extension Letter, dated as of August 13, 1987, from the signatories of the Participation Agreement to Chemical Bank	 	28.20 to APS’ Form S-3 Registration Statement No. 33-9480 by means of a November 6, 1986 Form 8-K Report, File No. 1-4473	 	8-10-87	
 	 	 	 	 	 	 	 	 	
99.10	 	Pinnacle West APS	 	Arizona Corporation Commission Order, Decision No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules	 	10.2 to APS’ September 30, 1999 Form 10-Q Report, File No. 1-4473	 	11-15-99	
 	 	 	 	 	 	 	 	 	
99.11	 	Pinnacle West	 	Purchase Agreement by and among Pinnacle West Energy Corporation and GenWest, L.L.C. and Nevada Power Company, dated June 21, 2005	 	99.5 to Pinnacle West/APS June 30, 2005 Form 10-Q Report, File Nos. 1-8962 and 1-4473	 	8-9-05	

a	 	Reports filed under File No. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.	
 		
b	 	Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 15(b) of Form 10-K.	
 		
c	 	An additional document, substantially identical in all material respects to this Exhibit, has been entered into, relating to an additional Equity Participant. Although such additional document may differ in other respects (such as dollar amounts, percentages, tax indemnity matters, and dates of execution), there are no material details in which such document differs from this Exhibit.	
 		
d	 	Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.	
 195 

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

Date: February 27, 2008	PINNACLE WEST CAPITAL CORPORATION
(Registrant)

 	/s/ William J. Post  	 	
 	(William J. Post, Chairman of the 	 	
 	Board of Directors and Chief Executive Officer) 	 	
 	
Power of Attorney
     We, the undersigned directors and executive officers of Pinnacle West Capital Corporation, hereby severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.
     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 	 	 	 	 	
Signature	 	Title	 	Date	
 	 	 	 	 	
/s/ William J. Post
 
(William J. Post, Chairman	 	Principal Executive Officer and Director	 	February 27, 2008	
of the Board of Directors and	 	 	 	 	
Chief Executive Officer)	 	 	 	 	
 	 	 	 	 	
/s/ Jack E. Davis
 
(Jack E. Davis, President	 	Director 	 	February 27, 2008	
and Chief Operating Officer)	 	 	 	 	
 	 	 	 	 	
/s/ Donald E. Brandt
 
(Donald E. Brandt,	 	Principal Accounting Officer and Principal Financial Officer	 	February 27, 2008	
Executive Vice President and	 	 	 	 	
Chief Financial Officer)	 	 	 	 	
 196 

Table of Contents

 	 	 	 	 	
Signature	 	Title	 	Date	
 	 	 	 	 	
/s/ Edward N. Basha, Jr.
 
(Edward N. Basha, Jr.)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Susan Clark-Johnson
 
(Susan Clark-Johnson)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Michael L. Gallagher
 
(Michael L. Gallagher)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Pamela Grant
 
(Pamela Grant)	 	Director	 	February 27, 2008	
 	 	 	 	 	
/s/ Roy A. Herberger, Jr.
 
(Roy A. Herberger, Jr.)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ William S. Jamieson
 
(William S. Jamieson)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Humberto S. Lopez
 
(Humberto S. Lopez)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Kathryn L. Munro
 
(Kathryn L. Munro)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Bruce J. Nordstrom
 
(Bruce J. Nordstrom)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ W. Douglas Parker
 
(W. Douglas Parker)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ William L. Stewart
 
(William L. Stewart)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
 197 

Table of Contents

SIGNATURES
     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 	 	 	 	 	
 	ARIZONA PUBLIC SERVICE COMPANY
(Registrant)	 	
 		
Date: February 27, 2008 	/s/ Jack E. Davis  	 	
 	(Jack E. Davis, Chief 	 	
 	Executive Officer) 	 	
 	
Power of Attorney
     We, the undersigned directors and executive officers of Arizona Public Service Company, hereby severally appoint Donald E. Brandt, Barbara M. Gomez and Nancy C. Loftin, and each of them, our true and lawful attorneys with full power to them and each of them to sign for us, and in our names in the capacities indicated below, any and all amendments to this Annual Report on Form 10-K filed with the Securities and Exchange Commission.
     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 	 	 	 	 	
Signature	 	Title	 	Date	
 	 	 	 	 	
/s/ William J. Post
 
(William J. Post, Chairman	 	Director 	 	February 27, 2008	
of the Board of Directors )	 	 	 	 	
 	 	 	 	 	
/s/ Jack E. Davis
 
(Jack E. Davis,
Chief Executive Officer)	 	Principal Executive Officer and Director	 	February 27, 2008	
 	 	 	 	 	
/s/ Donald E. Brandt
 
(Donald E. Brandt,	 	Principal Financial Officer 	 	February 27, 2008	
President and Chief	 	 	 	 	
Financial Officer)	 	 	 	 	
 	 	 	 	 	
/s/ Chris N. Froggatt
 
(Chris N. Froggatt,	 	Principal Accounting Officer 	 	February 27, 2008	
Vice President and Controller)	 	 	 	 	
 198 

Table of Contents

 	 	 	 	 	
Signature	 	Title	 	Date	
 	 	 	 	 	
/s/ Edward N. Basha, Jr.
 
(Edward N. Basha, Jr.)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Susan Clark-Johnson
 
(Susan Clark-Johnson)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Michael L. Gallagher
 
(Michael L. Gallagher)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Pamela Grant
 
(Pamela Grant)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Roy A. Herberger, Jr.
 
(Roy A. Herberger, Jr.)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ William S. Jamieson
 
(William S. Jamieson)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Humberto S. Lopez
 
(Humberto S. Lopez)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Kathryn L. Munro
 
(Kathryn L. Munro)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ Bruce J. Nordstrom
 
(Bruce J. Nordstrom)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ W. Douglas Parker
 
(W. Douglas Parker)	 	Director 	 	February 27, 2008	
 	 	 	 	 	
/s/ William L. Stewart
 
(William L. Stewart)	 	Director 	 	February 27, 2008	
 199 

Exhibit 10.1.2h
AMENDMENT NO. 8
Decommissioning Trust Agreement
(PVNGS Unit 2)
     This Amendment No. 8 dated as of April 1, 2007, to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of January 31, 1992, as amended by Amendment No. 1 thereto dated as of November 1, 1992, Amendment No. 2 thereto dated as of November 1, 1994, Amendment No. 3 thereto dated as of June 20, 1996, Amendment No. 4 thereto dated as of December 16, 1996, Amendment No. 5 thereto dated as of June 30, 2000, Amendment No. 6 thereto dated as of March 18, 2002, and Amendment No. 7 thereto dated as of December 19, 2003 (the “Decommissioning Trust Agreement”, terms used herein as therein defined), is entered into between Arizona Public Service Company (“APS”), U.S. Bank National Association, as successor to State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee and as Lessor, and Mellon Bank, N.A., as Decommissioning Trustee (“Decommissioning Trustee”).
R E C I T A L S :
     WHEREAS, the parties hereto wish to amend the Decommissioning Trust Agreement.
     NOW, THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
     SECTION 1. Amendments.

 	(a)	 	Clause (iii) of Paragraph (c) of Section 5 shall be restated as follows:	
 		
 	 	 	APS shall cause or permit any of the assets of either Fund to be used for any purpose other than as permitted by this Agreement or shall cause or permit any assets of either Fund to be invested in any investment that is not in accordance with Section 9 of this Agreement and shall fail to remedy such non-permitted use or investment within 30 days following notice by a Lessor or an Equity Participant to APS of such non-permitted use or investment.	
 		
 	(b)	 	Clause (v) of Section 6 shall be restated as follows:	
 		
 	 	 	(v) the term “Decommissioning Fund Permitted Investments” (as such term is defined in Section 10(b)(3)(viii) of each of the Participation Agreements) shall mean those investments that are in accordance with Exhibit B.	
 		
 	(c)	 	Paragraph (c) of Section 7 shall be restated as follows:	
 		
 	 	 	to (i) hold assets, in a depository, in a clearing corporation, in book entry form, or by any subcustodian or other entity or in any other manner permitted by law; provided that the Decommissioning Trustee shall not be	

 

 	 	 	responsible for any losses resulting from the deposit or maintenance of securities or other property (in accordance with market practice, custom, or regulation) with any foreign or domestic clearing facility, book-entry system, centralized custodial depository, or similar organization generally used by professional custodians engaged in the banking or trust company industry within the applicable market for the asset type in question and (ii) settle transactions in futures and/or options contracts, foreign exchange or foreign exchange contracts, swaps and other derivative investments with third parties;	
 		
 	(d)	 	Paragraph (a) of Section 9 shall be restated as follows:	
 		
 	 	 	To hold, manage, invest, and reinvest the assets of the Funds; provided however that notwithstanding the provisions of Section 9(c), Decommissioning Trustee shall, at the close of business on each day, without prior approval or direction from the Investment Manager(s), have the power, rights, and responsibility to invest cash balances, including those held as part of an account of the Investment Manager(s), in accordance with Exhibit B. Nothing in this Section shall be construed as authorizing Decommissioning Trustee to carry on any business or to divide the gains therefrom.	
 		
 	(e)	 	The first sentence of clause (ii) of Paragraph (c) of Section 9 shall be deleted.	
 		
 	(f)	 	The third sentence of clause (ii) of Paragraph (c) of Section 9 shall be restated as follows:	
 		
 	 	 	Upon proper notification from the Investment Manager(s), Decommissioning Trustee shall execute and deliver instruments in accordance with the appropriate trading authorizations; provided that the Decommissioning Trustee shall not follow any direction that would result in assets of the Second Fund being invested in investments not allowed for a qualified nuclear decommissioning reserve fund under Section 468A of the Code and the regulations thereunder.	
 		
 	(g)	 	Clause (ii) of Paragraph (d) of Section 9 shall be restated as follows:	
 		
 	 	 	Decommissioning Trustee is required to supervise and review the securities and other assets and investments authorized for purchase by the Investment Managers(s) within two weeks of the end of the calendar month during which such purchase was made to determine that such securities, assets and/or investments are in accordance with Exhibit B. Upon the completion of such review, the Decommissioning Trustee shall promptly notify APS, the Secured Parties and the Equity Participants in writing if any securities, assets or investments are not in accordance with Exhibit B.	
 2 

 

 	(h)	 	The following shall be added to Section 13:	
 		
 	 	 	Notwithstanding the foregoing, if the Decommissioning Trustee advances cash or securities for any purpose or in the event that the Decommissioning Trustee shall incur or be assessed taxes, interest, charges, expenses, assessments, or other liabilities in connection with the performance of this Agreement, except such as may arise from its failure to exercise due care, any property at any time held for the Fund or under this Agreement shall be security therefor and the Decommissioning Trustee shall be entitled to collect from the Fund sufficient cash for reimbursement, and if such cash is insufficient, dispose of the assets held under this Agreement to the extent necessary to obtain reimbursement.	
 		
 	 	 	Notwithstanding the foregoing, nothing in this Agreement shall prohibit the lending of the assets of the Fund in accordance with the terms and conditions of a separate securities lending agreement.	
 		
 	(i)	 	The last sentence of Section 16 shall be restated as follows:	
 		
 	 	 	APS agrees to pay, be solely responsible for and to indemnify the Owner Trustees and the Equity Participants against all costs and expenses relating or allocable to, or incurred in connection with, Decommissioning regardless of Fund performance or asset valuations of the Fund at the time of Decommissioning.	
 		
 	(j)	 	The second sentence of the fourth paragraph of Section 24 shall be restated as follows:	
 		
 	 	 	Within two weeks of the end of each calendar quarter, the Decommissioning Trustee shall send a written statement to APS and the Secured Parties and Equity Participants indicating whether during that previous quarter such securities, assets and/or investments held in the Funds during that quarter were in accordance with Exhibit B; provided however, the Decommissioning Trustee shall promptly advise APS and the Secured Parties and Equity Participants if it has actual knowledge that any of the investments were not in accordance with Exhibit B .	
 		
 	(k)	 	The following shall be added to the first paragraph of Section 26.	
 		
 	 	 	The Decommissioning Trustee shall not be responsible or liable for any losses or damages suffered by the Fund arising as a result of the insolvency of any custodian, (other than the Decommissioning Trustee or any affiliate of the Decommissioning Trustee) subtrustee or subcustodian, except to the extent the Decommissioning Trustee failed to exercise due care in its selection, monitoring or continued retention of such entity. Settlements of transactions may be effected in trading and processing practices customary in the jurisdiction or market where the transaction	
 3 

 

 	 	 	occurs. APS acknowledges that this may, in certain circumstances, require the delivery of cash or securities (or other property) without the concurrent receipt of securities (or other property) or cash. In such circumstances, provided the Trustee has exercised due care and used reasonable efforts, the Decommissioning Trustee shall have no responsibility for nonreceipt of payment (or late payment) or nondelivery of securities or other property (or late delivery) by the counterparty.	
 		
 	(l)	 	The definition of the terms “Investment Grade” and “Permitted Investments” in Exhibit A to the Decommissioning Trust Agreement is hereby deleted.	
 		
 	(m)	 	Exhibit B to the Decommissioning Trust Agreement is hereby deleted and replaced in its entirety by Exhibit B hereto.	
     SECTION 2. Miscellaneous

 	(a)	 	Full Force and Effect.	
     Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to “this Agreement,” “hereto,” “hereof” and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby.

 	(b)	 	Counterparts/Representations.	
     The Amendment No. 8 may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any of the parties hereto may execute this Amendment No. 8 by signing any such counterpart. Each party represents and warrants to the other that it has full authority to enter into this Amendment upon the terms and conditions hereof and that the individual executing this Amendment on its behalf has the requisite authority to bind that Party.
 4 

 

     IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 8 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
 	 	 	 	 	
 	ARIZONA PUBLIC SERVICE COMPANY
 	 	
 	By:  	/s/ Janice Emery  	 	
 	Title:	 Director, Trust Investments 	 	

 	MELLON BANK, N.A. as Decommissioning Trustee
 	 	
 	By:  	/s/ Thomas McNally  	 	
 	Title:	 Vice President 	 	

 	U.S. BANK NATIONAL ASSOCIATION, as Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing Corporation and as Lessor under a Facility Lease with Arizona Public Service Company
 	 	
 	By:  	/s/ Todd R. DiNezza  	 	
 	Title:	 Assistant Vice President 	 	

 	U.S. BANK NATIONAL ASSOCIATION, as Owner Trustee under a Trust Agreement with Emerson Finance Co. and as Lessor under a Facility Lease with Arizona Public Service Company
 	 	
 	By:  	/s/ Todd R. DiNezza  	 	
 	Title:	 Assistant Vice President 	 	

 5 

 

 	 	 	 	 	 	 	 	 	
STATE OF ARIZONA	 	 	)	 	 	 	 	 	
 	 	 	)	 	 	ss:	 	 	
County of Maricopa	 	 	)	 	 	 	 	 	
     The foregoing instrument was acknowledged before me this 11th day of June, 2007, by Janice Emery, the Dir., TI of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.

 	/s/ Linda G. Redman  	 	
 	Notary Public 	 	

 	 	 	 	 	 	 	 	 	
My commission expires:	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
February 8, 2011	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
COMMONWEALTH OF PENNSYLVANIA	 	 	)	 	 	 	 	 	
 	 	 	)	 	 	ss:	 	 	
County of Allegheny	 	 	)	 	 	 	 	 	
     The foregoing instrument was acknowledged before me this 20th day of December, 2007, by Thomas J. McNally, a Vice President of Mellon Bank, N.A. a national banking association having trust powers, as Decommissioning Trustee, on behalf of said national banking association.

 	/s/ Karesse M. Doss  	 	
 	Notary Public 	 	

My commission expires:
8-16-2011
 6 

 

 	 	 	 	 	 	 	 	 	
[COMMONWEALTH OF MASSACHUSETTS]	 	 	)	 	 	 	 	 	
 	 	 	)	 	 	ss:	 	 	
County of	 	 	)	 	 	 	 	 	
     The foregoing instrument was acknowledged before me this 24th day of July, 2007, by Todd R. DiNezza, a Asst. Vice Pres. of U.S. Bank National Association, in its capacity as Owner Trustee under a Trust Agreement with Security Pacific Capital Leasing Corporation and as Lessor under a Facility Lease with Arizona Public Service Company, on behalf of said association in such capacities.

 	/s/ Josh [surname illegible]  	 	
 	Notary Public 	 	

My commission expires:
2/7/08
 	 	 	 	 	 	 	 	 	
[COMMONWEALTH OF MASSACHUSETTS]	 	 	)	 	 	 	 	 	
 	 	 	)	 	 	ss:	 	 	
County of	 	 	)	 	 	 	 	 	
     The foregoing instrument was acknowledged before me this 24th day of July, 2007, by Todd R. DiNezza, a Asst. Vice Pres. of U.S. Bank National Association, in its capacity as Owner Trustee under a Trust Agreement with Emerson Finance Company and as Lessor under a Facility Lease with Arizona Public Service Company, on behalf of said association in such capacities.

 	/s/ Josh [surname illegible]  	 	
 	Notary Public 	 	

My commission expires:
2/7/08
 7 

 

Exhibit B
INVESTMENT GUIDELINES FOR THE
UNIT 2 DECOMMISSIONING TRUST FUND AND THE SECOND FUND
     The Unit 2 Decommissioning Trust Fund and the Second Fund (collectively, the “Funds”) shall be invested in compliance with all applicable requirements of the Code, rules and regulations of the Internal Revenue Service, and applicable State regulations. The Second Fund shall be invested in a manner that does not jeopardize its tax-preferred status.
          Subject to the foregoing, the Funds shall adhere to the following restrictions and guidelines, provided that a standard of care is exercised, whether in investing or otherwise, that a prudent investor would use in the same circumstances. The term “prudent investor” shall have the same meaning as set forth in the Federal Energy Regulatory Commission’s “Regulations Governing Nuclear Plant Decommissioning Trust Funds” at 18 CFR 35.32(a)(3), or any successor regulation:
     l. Equity securities, including, but not limited to, investment of units of common or collective trust funds or other private funds investing in corporate equity securities, shall not exceed:

 	a.	 	Fifty percent (50%) of the market value of the aggregate assets of the Funds during the period from June 27, 1996 through December 31, 2003.	
 		
 	b.	 	Forty percent (40%) of the market value of the aggregate assets of the Funds during the period from January 1, 2004 through December 31, 2006.	
 		
 	c.	 	Twenty percent (20%) of the market value of the aggregate assets of the Funds during the period from January 1, 2007 through January 31, 2010.	
 		
 	d.	 	No investments shall be made in equity securities after January 31, 2010.	
     2. Securities of APS, APS’s parent corporation, Pinnacle West Capital Corporation, or its affiliates, are not permitted.
     3. Securities issued in connection with the assets or operations of the Palo Verde Nuclear Generation Station, Pinnacle West, or its affiliates, are not permitted.
     4. Securities issued by or on behalf of any participant in the Palo Verde Nuclear Generating Station are not permitted.
 1 

 

     5. There shall be no short-selling or use of economic leverage. Economic Leverage is defined as exposing the Funds to risk and/or volatility in excess of what the Fund would experience by making an un-financed investment in the underlying securities directly.
     6. Derivatives are permitted as long as derivatives are used to (i) hedge existing long positions, (ii) manage aggregate portfolio durations, (iii) obtain security or market exposure, or (iv) for other risk management. Derivatives used for the purpose of speculation, which expose the Funds to Economic Leverage, or which cause the Funds to fall outside the parameters of this Exhibit B are prohibited.
     7. The holding of any one issue (excluding direct or moral obligations of the United States Government and the shares or units of any diversified investment vehicle), shall not exceed ten percent (10%) of the market value of the Funds’ aggregate assets.
     8. The market value of unhedged non-U.S. dollar denominated equity securities shall not exceed twenty percent (20%) of the aggregate market value of the Funds’ equity allocation.
     9. The market value of unhedged non-U.S. dollar denominated fixed income securities shall not exceed thirty percent (30%) of the aggregate market value of the Funds’ fixed income allocation.
     10. The average credit quality of the Funds’ fixed income securities shall be rated “Aa3/AA-/AA-” or higher by Moody’s Investors Service, Standard & Poor’s, or Fitch respectively. The Lehman Brothers rating methodology shall be used to determine the Funds’ average credit quality. Notwithstanding the forgoing, securities rated below Baa3/BBB-/BBB- shall not exceed twenty percent (20%) of the aggregate market value of the Funds’ fixed income allocation.
     11. The Funds shall hold no more than three percent (3%) of the aggregate market value of the Funds’ fixed income securities in issues not rated by either Moody’s Investors Service, Standard & Poor’s or Fitch (“Unrated Issues”). Notwithstanding the forgoing, Unrated Issues may not be held unless the investment manager has assigned its own credit rating to an Unrated Issue.
     12. In the event that a security fails to meet the credit quality criteria defined herein, the security shall be sold within ninety (90) days unless the investment manager provides reasonable written justification for continued holding of the security.
     13. Time or demand deposits are not permitted unless they are insured by the Federal Deposit Insurance Corporation or other comparable entity.
     14. Derivative, swap or similar transactions involving counterparty risk shall be limited to counterparties having a credit rating from Moody’s Investor Services and Standard & Poor’s of A or better. A “Counterparty” is defined as any entity with whom the Funds enter into an over-the-counter derivatives, swap or similar contract.
 2 

Exhibit 10.6.5
Summary of 2008 Incentive Plans
     On January 23, 2008, the Company’s Board of Directors, acting on the recommendation of the Board’s Human Resources Committee (the “Committee”), approved the 2008 Pinnacle West Employee Variable Incentive Plan and the 2008 APS Employee Variable Incentive Plan (collectively, the “2008 Plans”). The 2008 Plans provide incentive award opportunities for Pinnacle West and APS employees, including the following “named executive officers” from the Company’s proxy statement relating to its 2008 Annual Meeting: William J. Post, the Company’s Chairman and CEO; Donald E. Brandt, Pinnacle West’s Executive Vice President and Chief Financial Officer and APS’ President and Chief Financial Officer; Randall K. Edington, APS’ Executive Vice President, Nuclear and Chief Nuclear Officer; and Steven M. Wheeler, APS’ Executive Vice President Customer Service and Regulation (Mr. Davis will be retiring this year and will not be participating in the 2008 Plans). As required by the Committee’s Charter, the Committee, rather than the Board, approved Mr. Post’s award opportunity.
     The Committee granted Messrs. Post and Brandt incentive opportunities up to 150% of base salary and Messrs. Edington and Wheeler up to 50% of base salary. In assessing the award opportunity for each of these officers, the Committee will first consider 2008 earnings (Pinnacle West earnings in the case of Mr. Post, and APS earnings in the case of Messrs. Brandt, Edington and Wheeler), excluding impacts from Arizona Corporation Commission rate decisions. In order for the officers to be eligible for an incentive award, earnings must meet or exceed a specified threshold level. However, because the payment of incentive awards is in the sole discretion of the Committee, the Committee will then consider other factors in assessing award opportunities, including customer value, financial strength, operational and environmental performance, and safety.

 
Exhibit 12.1
Arizona Public Service Company
Computation of Earnings to Fixed Charges
($000’s)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	 	2003	 	 	2002	 	
Earnings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations	 	$	283,940	 	 	$	269,730	 	 	$	170,479	 	 	$	199,627	 	 	$	180,937	 	 	$	199,343	 	
Income Taxes	 	 	151,157	 	 	 	138,927	 	 	 	98,010	 	 	 	120,030	 	 	 	86,854	 	 	 	126,805	 	
Fixed Charges	 	 	202,044	 	 	 	191,174	 	 	 	178,437	 	 	 	181,372	 	 	 	181,793	 	 	 	168,985	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Earnings	 	$	637,141	 	 	$	599,831	 	 	$	446,926	 	 	$	501,029	 	 	$	449,584	 	 	$	495,133	 	

Fixed Charges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest Charges	 	$	170,594	 	 	$	158,769	 	 	$	145,502	 	 	$	146,983	 	 	$	147,610	 	 	$	133,878	 	
Amortization of Debt Discount	 	 	4,639	 	 	 	4,363	 	 	 	4,085	 	 	 	4,854	 	 	 	3,337	 	 	 	2,888	 	
Estimated Interest Portion of Annual Rents	 	 	26,811	 	 	 	28,042	 	 	 	28,850	 	 	 	29,535	 	 	 	30,846	 	 	 	32,219	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Fixed Charges	 	$	202,044	 	 	$	191,174	 	 	$	178,437	 	 	$	181,372	 	 	$	181,793	 	 	$	168,985	 	

Ratio of Earnings to Fixed Charges (rounded down)	 	 	3.15	 	 	 	3.13	 	 	 	2.50	 	 	 	2.76	 	 	 	2.47	 	 	 	2.93	 	

 
Exhibit 12.2
Pinnacle West Capital Corporation
Computation of Earnings to Fixed Charges
($000’s)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	 	2003	 	 	2002	 	
Earnings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations	 	$	298,780	 	 	$	317,143	 	 	$	223,163	 	 	$	246,590	 	 	$	225,384	 	 	$	236,563	 	
Income Taxes	 	 	150,920	 	 	 	156,418	 	 	 	126,892	 	 	 	136,142	 	 	 	102,202	 	 	 	152,145	 	
Fixed Charges	 	 	239,804	 	 	 	225,119	 	 	 	214,430	 	 	 	214,803	 	 	 	225,041	 	 	 	219,178	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Earnings	 	$	689,504	 	 	$	698,680	 	 	$	564,485	 	 	$	597,535	 	 	$	552,627	 	 	$	607,886	 	

Fixed Charges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest Expense	 	$	212,620	 	 	$	196,826	 	 	$	185,087	 	 	$	183,527	 	 	$	193,973	 	 	$	187,039	 	
Estimated Interest Portion of Annual Rents	 	 	27,184	 	 	 	28,293	 	 	 	29,343	 	 	 	31,276	 	 	 	31,068	 	 	 	32,139	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Fixed Charges	 	$	239,804	 	 	$	225,119	 	 	$	214,430	 	 	$	214,803	 	 	$	225,041	 	 	$	219,178	 	

Ratio of Earnings to Fixed Charges (rounded down)	 	 	2.87	 	 	 	3.10	 	 	 	2.63	 	 	 	2.78	 	 	 	2.45	 	 	 	2.77	 	

 
Exhibit 12.3
Pinnacle West Capital Corporation
Computation of Earnings to Fixed Charges
and Preferred Stock Dividend Requirements
($000’s)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	 	2003	 	 	2002	 	
Earnings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income From Continuing Operations	 	$	298,780	 	 	$	317,143	 	 	$	223,163	 	 	$	246,590	 	 	$	225,384	 	 	$	236,563	 	
Income Taxes	 	 	150,920	 	 	 	156,418	 	 	 	126,892	 	 	 	136,142	 	 	 	102,202	 	 	 	152,145	 	
Fixed Charges	 	 	239,804	 	 	 	225,119	 	 	 	214,430	 	 	 	214,803	 	 	 	225,041	 	 	 	219,178	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Earnings	 	$	689,504	 	 	$	698,680	 	 	$	564,485	 	 	$	597,535	 	 	$	552,627	 	 	$	607,886	 	

Fixed Charges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest Expense	 	$	212,620	 	 	$	196,826	 	 	$	185,087	 	 	$	183,527	 	 	$	193,973	 	 	$	187,039	 	
Estimated Interest Portion of Annual Rents	 	 	27,184	 	 	 	28,293	 	 	 	29,343	 	 	 	31,276	 	 	 	31,068	 	 	 	32,139	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Fixed Charges	 	$	239,804	 	 	$	225,119	 	 	$	214,430	 	 	$	214,803	 	 	$	225,041	 	 	$	219,178	 	

Preferred Stock Dividend Requirements:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income Before Income Taxes	 	$	449,700	 	 	$	473,561	 	 	$	350,055	 	 	$	382,732	 	 	$	327,586	 	 	$	388,708	 	
Net Income From Continuing Operations	 	 	298,780	 	 	 	317,143	 	 	 	223,163	 	 	 	246,590	 	 	 	225,384	 	 	 	236,563	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ratio of Income Before Income Taxes to Net Income	 	 	1.505	 	 	 	1.493	 	 	 	1.569	 	 	 	1.552	 	 	 	1.453	 	 	 	1.643	 	
Preferred Stock Dividends	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend Requirements — Ratio (above) Times Preferred Stock Dividends	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

Fixed Charges and Preferred Stock Dividend Requirements:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fixed Charges	 	$	239,804	 	 	$	225,119	 	 	$	214,430	 	 	$	214,803	 	 	$	225,041	 	 	$	219,178	 	
Preferred Stock Dividend Requirements	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	239,804	 	 	$	225,119	 	 	$	214,430	 	 	$	214,803	 	 	$	225,041	 	 	$	219,178	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements (rounded down)	 	 	2.87	 	 	 	3.10	 	 	 	2.63	 	 	 	2.78	 	 	 	2.45	 	 	 	2.77	 	

   

Exhibit 21.1
SUBSIDIARIES OF PINNACLE WEST CAPITAL CORPORATION
 	 	 	 	 	
Arizona Public Service Company	 	 	 	 	
APS Foundation, Inc.	 	 	 	 	
AXIOM Power Solutions, Inc.	 	 	 	 	
Bixco, Inc.	 	 	 	 	
Powertree Carbon Company, LLC	 	 	 	 	
PWENewco, Inc.	 	 	 	 	
Pinnacle West Energy Corporation (merged into Pinnacle West Capital Corporation 8/1/06)	 	 	 	 	
GenWest, LLC	 	 	 	 	
APACS Holdings LLC	 	 	 	 	
Pinnacle West Marketing & Trading Co., LLC	 	 	 	 	
APSES Holdings, Inc.	 	 	 	 	
APS Energy Services Company, Inc.	 	 	 	 	
Apex Power LLC	 	 	 	 	
Northwind Phoenix LLC	 	 	 	 	
Tucson District Energy LLC	 	 	 	 	
Crest Power, LLC	 	 	 	 	
SunCor Development Company	 	 	 	 	
SunCor Golf, Inc.	 	 	 	 	
Westworld Golf Course, L.L.C.	 	 	 	 	
SunCor Homes, Inc. (formerly known as Golden Heritage Homes, Inc.)	 	 	 	 	
SunCor Construction AZ, Inc. (formerly known as Golden Heritage	 	 	 	 	
Construction, Inc.)	 	 	 	 	
Golden Heritage Construction Nevada, LLC	 	 	 	 	
SunCor Financial, LLC (formerly known as HFS Mortgage, L.L.C.)	 	 	 	 	
SCM, Inc.	 	 	 	 	
SunCor Realty & Management Company	 	 	 	 	
Palm Valley Golf Club, Inc.	 	 	 	 	
Rancho Viejo de Santa Fe, Inc.	 	 	 	 	
Ranchland Utility Company	 	 	 	 	
Santa Fe Water Resource Alliance, LLC	 	 	 	 	
SunCor Idaho, Inc.	 	 	 	 	
Avimor, LLC (formerly SunCor Idaho, LLC)	 	 	 	 	
SunCor Realty & Management Idaho, LLC	 	 	 	 	
Avimor Water Reclamation Company (f/k/a Foothills Sewer Company)	 	 	 	 	
Type Two, Inc.	 	 	 	 	
StoneRidge- Prescott Valley L.L.C.	 	 	 	 	
StoneRidge Golf Course, LLC	 	 	 	 	
Hayden Ferry Lakeside II, L.L.C.	 	 	 	 	
Hayden Ferry Lakeside III, L.L.C.	 	 	 	 	
Hayden Ferry Lakeside, L.L.C.	 	 	 	 	
Lakeside Residential Communities, L.L.C.	 	 	 	 	
Edgewater at Hayden Ferry Lakeside, L.L.C.	 	 	 	 	
BV at Hayden Ferry Lakeside, L.L.C.	 	 	 	 	
Waterford at Hayden Ferry Lakeside, L.L.C.	 	 	 	 	

 

 	 	 	 	 	
Club West Golf Course LLC	 	 	 	 	
SunRidge Canyon, L.L.C.	 	 	 	 	
Sedona Golf Resort, L.C.	 	 	 	 	
Kabuto SunCor Joint Venture	 	 	 	 	
Marina Heights, LLC	 	 	 	 	
Palm Valley 303 Building 1, LLC	 	 	 	 	
Centrepoint Associates, L.L.P.	 	 	 	 	
Hidden Hills of Scottsdale, L.C.	 	 	 	 	
Talavi Associates, L.L.C.	 	 	 	 	
Coral Canyon Town Center, L.L.C.	 	 	 	 	
Coral Canyon Town Center II, L.L.C.	 	 	 	 	
Coral Canyon HD, L.L.C.	 	 	 	 	
Golf de Mexico, S.A. de C.V.	 	 	 	 	
Highland Water Company	 	 	 	 	
Palm Valley Professional Plaza, LLC	 	 	 	 	
Ranch Communities of America LLC	 	 	 	 	
Riverside Distribution Center, LLC	 	 	 	 	
Scottsdale Mountain Limited Partnership	 	 	 	 	
SDC Prescott Valley, LLC	 	 	 	 	
SDC Prescott, LLC	 	 	 	 	
SDC Yavapai, LLC	 	 	 	 	
StoneRidge Commercial, L.L.C.	 	 	 	 	
SunCor New Mexico, Inc.	 	 	 	 	
SunCor Albuquerque, LLC	 	 	 	 	
SunCor Construction NM, LLC	 	 	 	 	
SunCor Utah, Inc.	 	 	 	 	
El Dorado Investment Company	 	 	 	 	
Aegis Technologies, Inc.	 	 	 	 	
Underground Imaging Technologies, LLC	 	 	 	 	
AZ PB Partnership	 	 	 	 	
El Dorado Ventures III	 	 	 	 	
Phoenix Downtown Theater LLC	 	 	 	 	
Nxt-Phase Corporation	 	 	 	 	
Acoustic Locating Services, LLC	 	 	 	 	
Arizona Business Accelerator	 	 	 	 	
PowerOneData, Inc.	 	 	 	 	
Severon Corporation	 	 	 	 	

 
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement Nos. 33-15190 and 333-134206 on Form S-3; in Registration Statement Nos. 33-54307, 333-143432, 333-91786, and 333-138089 on Form S-8; and in Registration Statement No. 2-96386 on Form S-14 of our report dated February 27, 2008 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company’s adoption of Statement of Financial Accounting Standards No. 158), relating to the consolidated financial statements and financial statement schedules of Pinnacle West Capital Corporation and the effectiveness of Pinnacle West Capital Corporation’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Pinnacle West Capital Corporation for the year ended December 31, 2007.
Phoenix, Arizona
February 27, 2008
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP

 
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Post-Effective Amendment No. 1 to Registration Statement No. 333-134206 on Form S-3; and in Registration Statement No. 333-46161 on Form S-8 of our report dated February 27, 2008, (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company’s adoption of Statement of Financial Accounting Standards No. 158), relating to the financial statements and financial statement schedule of Arizona Public Service Company, and the effectiveness of Arizona Public Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Arizona Public Service Company for the year ended December 31, 2007.
Phoenix, Arizona
February 27, 2008
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP

 

Exhibit 31.1
CERTIFICATION
I, William J. Post, certify that:

1.	 	I have reviewed this Annual Report on Form 10-K of Pinnacle West Capital Corporation;	
 		
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 		
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 		
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	a)	 	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 		
 	b)	 	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 		
 	c)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 		
 	d)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	a)	 	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 		
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: February 27, 2008.

 	/s/ William J. Post  	 	
 	William J. Post 	 	
 	Chairman and Chief Executive Officer 	 	
 	
 2 

Exhibit 31.2
CERTIFICATION
I, Donald E. Brandt, certify that:

1.	 	I have reviewed this Annual Report on Form 10-K of Pinnacle West Capital Corporation;	
 		
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 		
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 		
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	a)	 	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 		
 	b)	 	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 		
 	c)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 		
 	d)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	a)	 	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 		
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: February 27, 2008.

 	/s/ Donald E. Brandt  	 	
 	Donald E. Brandt 	 	
 	Executive Vice President & Chief Financial Officer 	 	

 

 	 	 	 	 	
Exhibit 31.3
CERTIFICATION
I, Jack E. Davis, certify that:

1.	 	I have reviewed this Annual Report on Form 10-K of Arizona Public Service Company;	
 		
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 		
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 		
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	a)	 	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 		
 	b)	 	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 		
 	c)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 		
 	d)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	a)	 	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 		
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: February 27, 2008.

 	/s/ Jack E. Davis  	 	
 	Jack E. Davis 	 	
 	Chief Executive Officer 	 	
 	
 2 

Exhibit 31.4
CERTIFICATION
I, Donald E. Brandt, certify that:

1.	 	I have reviewed this Annual Report on Form 10-K of Arizona Public Service Company;	
 		
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 		
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 		
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	a)	 	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 		
 	b)	 	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 		
 	c)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 		
 	d)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	a)	 	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 		
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: February 27, 2008.

 	/s/ Donald E. Brandt  	 	
 	Donald E. Brandt 	 	
 	President & Chief Financial Officer 	 	

 

Exhibit 32.1
CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
     I, William J. Post, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Pinnacle West Capital Corporation for the fiscal year ended December 31, 2007, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.
Date: February 27, 2008.

 	/s/ William J. Post  	 	
 	William J. Post 	 	
 	Chairman and Chief Executive Officer 	 	
 	
     I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Pinnacle West Capital Corporation for the fiscal year ended December 31, 2007 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.
Date: February 27, 2008.

 	/s/ Donald E. Brandt  	 	
 	Donald E. Brandt 	 	
 	Executive Vice President and Chief Financial Officer 	 	

 

Exhibit 32.2
CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
     I, Jack E. Davis, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Arizona Public Service Company for the fiscal year ended December 31, 2007 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.
Date: February 27, 2008.

 	/s/ Jack E. Davis  	 	
 	Jack E. Davis 	 	
 	Chief Executive Officer 	 	
 	
     I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report on Form 10-K of Arizona Public Service Company for the fiscal year ended December 31, 2007 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Annual Report on Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.
Date: February 27, 2008.

 	/s/ Donald E. Brandt  	 	
 	Donald E. Brandt 	 	
 	President and Chief Financial Officer