SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K
(Mark One)

x	 	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
 	 	For the fiscal year ended December 31, 2003	
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 File Number 1-8962
PINNACLE WEST CAPITAL CORPORATION
(Exact name of registrant as specified in its charter)
 	 	 	
ARIZONA
(State or other jurisdiction
of incorporation or organization)	 	86-0512431
(I.R.S. Employer Identification No.)	
400 North Fifth Street, P.O. Box 53999	 	 	
Phoenix, Arizona 85072-3999
(Address of principal executive offices,
including zip code)	 	(602) 250-1000
(Registrant’s telephone number,
including area code)	
Securities registered pursuant to Section 12(b) of the Act:

 	 	 	
Title Of Each Class	 	Name Of Each Exchange On
Which Registered	

 	
Common Stock,
No Par Value	 	New York Stock Exchange
Pacific Stock Exchange	
Securities registered pursuant to Section 12(g) of the Act: None.
     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. Yes x 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. x
     Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes x No o
     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 the registrant’s most recently completed second fiscal quarter: $3,404,788,658 as of June 30, 2003
     The number of shares outstanding of the registrant’s common stock as of March 11, 2004 was 91,297,881.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive Proxy Statement relating to its Annual Meeting of Shareholders to be held on May 19, 2004 are incorporated by reference into Part III hereof.

 

 

TABLE OF CONTENTS

									
GLOSSARY	
PART I	
	ITEM 1. BUSINESS	
	ITEM 2. PROPERTIES	
	ITEM 3. LEGAL PROCEEDINGS	
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	
PART II	
	ITEM 5. MARKET FOR REGISTRANT’S COMMON STOCK AND RELATED STOCKHOLDER MATTERS	
	ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA	
	ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	
	ITEM 7A. QUANTITATIVE AND QUALITATIVE	
	ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	
	ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	
	ITEM 9A. CONTROLS AND PROCEDURES	
PART III	
	ITEM 10. DIRECTORS AND EXECUTIVE                      OFFICERS OF THE REGISTRANT	
	ITEM 11. EXECUTIVE COMPENSATION	
	ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	
	ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	
	ITEM 14. PRINCIPAL ACCOUNTANT	
PART IV	
	ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K	
SIGNATURES	
EX-3.1	
EX-10.1a	
EX-10.2a	
EX-10.3	
EX-10.4	
EX-10.5	
EX-10.6a	
EX-10.7a	
EX-12.1	
EX-21.1	
EX-23.1	
EX-31.1	
EX-31.2	
EX-32.1	
EX-99.1	
TABLE OF CONTENTS

 	 	 	 	 	 	Page
	
GLOSSARY	 	 	 	 	1	 	
PART I	 	 	 	 	4	 	
	 	Item 1.	 	Business	 	 	4	 	
	 	Item 2.	 	Properties	 	 	17	 	
	 	Item 3.	 	Legal Proceedings	 	 	22	 	
	 	Item 4.	 	Submission of Matters to a Vote of Security Holders	 	 	22	 	
 	 	Supplemental Item.	 	 	 	 	
	 	 	 	Executive Officers of the Registrant	 	 	23	 	
PART II	 	 	 	 	25	 	
	 	Item 5.	 	Market for Registrant’s Common Stock and Related Stockholder Matters	 	 	25	 	
	 	Item 6.	 	Selected Consolidated Financial Data	 	 	26	 	
	 	Item 7.	 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	27	 	
	 	Item 7A.	 	Quantitative and Qualitative Disclosures about Market Risk.	 	 	56	 	
	 	Item 8.	 	Financial Statements and Supplementary Data	 	 	57	 	
	 	Item 9.	 	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	 	 	124	 	
	 	Item 9A.	 	Controls and Procedures	 	 	124	 	
PART III	 	 	 	 	124	 	
	 	Item 10.	 	Directors and Executive Officers of the Registrant	 	 	124	 	
	 	Item 11.	 	Executive Compensation	 	 	124	 	
	 	Item 12.	 	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	 	 	125	 	
	 	Item 13.	 	Certain Relationships and Related Transactions	 	 	127	 	
	 	Item 14.	 	Principal Accountant Fees and Services	 	 	127	 	
PART IV	 	 	 	 	128	 	
	 	Item 15.	 	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	 	 	128	 	
SIGNATURES	 	 	 	 	160	 	
 i 

 

GLOSSARY
ACC – Arizona Corporation Commission
ADEQ – Arizona Department of Environmental Quality
AFUDC – allowance for funds used during construction
AISA – Arizona Independent Scheduling Administrator
ALJ – Administrative Law Judge
ANPP – Arizona Nuclear Power Project, also known as Palo Verde
APS – Arizona Public Service Company, a subsidiary of the Company
APS Energy Services – APS Energy Services Company, Inc., a subsidiary of the Company
CC&N – Certificate of Convenience and Necessity
Cholla – Cholla Power Plant
Citizens – Citizens Communications Company
Clean Air Act – the Clean Air Act, as amended
Company – Pinnacle West Capital Corporation
CPUC – California Public Utility Commission
DOE – United States Department of Energy
EITF – the 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
Financing Order – ACC Order that authorized APS’ $500 million loan to Pinnacle West Energy in May 2003
FIP – Federal Implementation Plan
Four Corners – Four Corners Power Plant
GAAP – accounting principles generally accepted in the United States of America
IRS – United States Internal Revenue Service
ISO – California Independent System Operator
kW – kilowatt, one thousand watts
kWh – kilowatt-hour, one thousand watts per hour

 

Moody’s – Moody’s Investors Service
MW – megawatt, one million watts
MWh – megawatt-hours, one million watts per hour
NAC – NAC International Inc., a subsidiary of El Dorado
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
1999 Settlement Agreement – comprehensive settlement agreement related to the implementation of retail electric competition
NOV – Notice of Violation
NRC – United States Nuclear Regulatory Commission
Nuclear Waste Act – Nuclear Waste Policy Act of 1982, as amended
OCI – other comprehensive income
Palo Verde – Palo Verde Nuclear Generating Station
PCAOB – Public Company Accounting Oversight Board
PG&E – PG&E Corp.
Pinnacle West – Pinnacle West Capital Corporation, the Company
Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company
PRP – potentially responsible parties under Superfund
PWEC Dedicated Assets – the following Pinnacle West Energy power plants, each of which is dedicated to serving APS’ customers: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3
PX – California Power Exchange
RTO – regional transmission organization
Rules – ACC retail electric competition rules
Salt River Project – Salt River Project Agricultural Improvement and Power District
SCE – Southern California Edison Company
SEC – United States Securities and Exchange Commission
SFAS – Statement of Financial Accounting Standards
SNWA – Southern Nevada Water Authority
SPE – special-purpose entity
Standard & Poor’s – Standard & Poor’s Corporation
SunCor – SunCor Development Company, a subsidiary of the Company
Superfund – Comprehensive Environmental Response, Compensation and Liability Act
T&D – transmission and distribution
2

 

Track A Order – ACC order dated September 10, 2002 regarding generation asset transfers and related issues
Track B Order –ACC order dated March 14, 2003 regarding competitive solicitation requirements for power purchases by Arizona’s investor-owned electric utilities
Trading – energy-related activities entered into with the objective of generating profits on changes in market prices
VIE – variable interest entity
WestConnect – WestConnect RTO, LLC, a proposed RTO to be formed by owners of electric transmission lines in the southwestern United States
3

 
PART I 
ITEM 1. BUSINESS
CURRENT STATUS
General 
     We were incorporated in 1985 under the laws of the State of Arizona and own all of the outstanding equity securities of APS, our major subsidiary. 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 the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. Through its marketing and trading division, APS also generates, sells and delivers electricity to wholesale customers in the western United States.
     Our other significant subsidiaries are Pinnacle West Energy, which owns and operates generating plants; APS Energy Services, which provides competitive energy services and products in the western United States; and SunCor, which is engaged in real estate development activities. We discuss each of these subsidiaries in greater detail below. See “Business of Pinnacle West Energy Corporation,” “Business of APS Energy Services Company, Inc.” and “Business of SunCor Development Company” in this Item 1.
Business Segments
     We have three principal business segments (determined by products, services and the regulatory environment):

•	 	our regulated electricity segment (70% of operating revenues in 2003), which consists of traditional regulated retail and wholesale electricity businesses and related activities, and includes electricity generation, transmission and distribution;	
 	
•	 	our marketing and trading segment (14% of operating revenues in 2003), which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services; and	
 	
•	 	our real estate segment (13% of operating revenues in 2003), which consists of SunCor’s real estate development and investment activities.	
     See Note 17 of Notes to Consolidated Financial Statements in Item 8 for financial information about our business segments.
APS General Rate Case
     We believe APS’ general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3 of Notes to Consolidated Financial Statements in Item 8, in this rate case APS has requested, among other things, a 9.8% retail rate increase (approximately $175 million annually), rate treatment for the PWEC Dedicated Assets and the recovery of $234 million written off by APS as part of the 1999 Settlement Agreement. In its filed
4

 

testimony, the ACC staff recommended, among other things, that the ACC decrease APS’ rates by approximately 8% (approximately $143 million annually), not allow the PWEC Dedicated Assets to be included in APS’ rate base, and not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement. The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings and access to capital markets. We believe that APS’ rate case requests are supported by, among other things, APS’ demonstrated need for the PWEC Dedicated Assets; APS’ need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in APS’ high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard. The hearing on the rate case is scheduled to begin on May 25, 2004. We believe the ACC will be able to make a decision by the end of 2004.
Employees
     At December 31, 2003, we employed about 7,200 people, including the employees of our subsidiaries. Of these employees, about 6,000 were employees of APS, including employees at jointly-owned generating facilities for which APS serves as the generating facility manager. About 1,200 people were employed by Pinnacle West and our other subsidiaries. Our principal executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).
Available Information
     We make available free of charge on or through our Internet Website (www.pinnaclewest.com) the following filings as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC: our Annual Report on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. The information on our Website is not part of this report.
Forward-Looking Statements
     This document contains forward-looking statements based on current expectations, and we assume no 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 “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 us. These factors include, but are not limited to:

•	 	state and federal regulatory and legislative decisions and actions, including the outcome of the rate case APS filed with the ACC on June 27, 2003 and the wholesale electric price mitigation plan adopted by the FERC;	
 	
•	 	the outcome of regulatory, legislative and judicial proceedings relating to the restructuring;	
5

 

•	 	the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition;	
 	
•	 	market prices for electricity and natural gas;	
 	
•	 	power plant performance and outages;	
 	
•	 	weather variations affecting local and regional customer energy usage;	
 	
•	 	energy usage;	
 	
•	 	regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile purchased power and fuel costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;	
 	
•	 	the cost of debt and equity capital and access to capital markets;	
 	
•	 	our ability to compete successfully outside traditional regulated markets (including the wholesale market);	
 	
•	 	the performance of our marketing and trading activities due to volatile market liquidity and deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);	
 	
•	 	changes in accounting principles generally accepted in the United States of America;	
 	
•	 	the successful completion of our generation construction program;	
 	
•	 	regulatory issues associated with generation construction, such as permitting and licensing;	
 	
•	 	the performance of the stock market and the changing interest rate environment, which affect the amount of our required contributions to our pension plan and nuclear decommissioning trust funds, as well as our 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;	
 	
•	 	conservation programs; and	
 	
•	 	other uncertainties, all of which are difficult to predict and many of which are beyond our control.	
REGULATION AND COMPETITION
Retail
     The ACC regulates APS’ retail electric rates and its issuance of securities. The ACC must also approve any transfer of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS and their respective affiliates. See Note 3 of Notes to Consolidated Financial Statements in Item 8 for a discussion of the status of electric industry restructuring in Arizona.
     The electric utility industry has undergone significant regulatory change in the last few years designed to encourage competition in the sale of electricity and related services. However, the experience in California with deregulation has caused many states, including Arizona, to reexamine retail electric competition.
6

 

     As of January 1, 2001, all of APS’ retail customers were eligible to choose an alternate energy supplier. However, 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. Also, regulatory developments and legal challenges to the ACC’s electric competition rules have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. See “Retail Electric Competition Rules” in Note 3 of Notes to Consolidated Financial Statements in Item 8 for additional information.
     APS is subject to varying degrees of competition from other investor-owned utilities in Arizona (such as Tucson Electric Power Company and Southwest Gas Corporation) as well as cooperatives, municipalities, electrical districts and similar types of governmental or non-profit organizations (principally Salt River Project). APS also faces competition from low-cost, hydroelectric power and parties that have access to low-priced preferential, federal power and other governmental subsidies. In addition, some customers, particularly industrial and large commercial customers, may own and operate generation facilities to meet their own energy requirements.
Wholesale
      General
     The FERC regulates rates for wholesale power sales and transmission services. During 2003, approximately 19% of our electric operating revenues resulted from such sales and services. In early 2003, we moved our marketing and trading division from Pinnacle West to APS for all future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of APS’ generating assets to Pinnacle West Energy (see “Track A Order” in Note 3 of Notes to Consolidated Financial Statements in Item 8).
     The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with its costs of serving retail customer energy requirements. The division also sells, in the wholesale market, APS and Pinnacle West Energy generation output that is not needed for APS’ Native Load and, in doing so, competes with other utilities, power marketers and independent power producers. See “Track B Order” in Note 3 of Notes to Consolidated Financial Statements in Item 8 for information regarding an ACC-mandated process by which APS must competitively procure energy. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emissions allowances and credits.
      Regional Transmission Organizations
      Federal In a December 1999 order, the FERC established characteristics and functions that must be met by utilities in forming and operating RTOs. The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to support efficient and nondiscriminatory markets and exclusive authority to maintain short-term reliability. Additionally, in a pending notice of proposed rulemaking, the FERC is considering implementing a standard market design for wholesale markets.
7

 

     On October 16, 2001, APS and other owners of electric transmission lines in the Southwest filed with the FERC a request for a declaratory order confirming that their proposal to form WestConnect RTO, LLC would satisfy the FERC’s requirements for the formation of an RTO. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if modified to address specified issues, could meet the FERC’s RTO requirements and provide the basic framework for a standard market design for the Southwest. On September 15, 2003, the FERC issued an order granting clarification and rehearing, in part, of its prior orders. In particular, this order approved the use of a physical congestion management scheme, which is used to allocate transmission rights on congested lines, for WestConnect for an initial phase-in period. The FERC indicated that the WestConnect utilities and the appropriate regional state advisory committee should develop a market-based congestion management scheme for subsequent implementation. APS is now participating in a cost/benefit analysis of implementing WestConnect, the results of which are expected to be completed in 2004.
      State The Rules also required the formation and implementation of an Arizona Independent Scheduling Administrator. The purpose of the AISA is to oversee the application of operating protocols to ensure statewide consistency for transmission access. The AISA is anticipated to be a temporary organization until the implementation of an independent system operator or RTO. APS participated in the creation of the AISA, a not-for-profit entity, and the filing at the FERC for approval of its operating protocols. The operating protocols were partially rejected and the remainder are currently under review. In its Track B Order, the ACC directed that a hearing be held on whether or not APS should be required to continue funding the AISA.
BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY
General
     APS was incorporated in 1920 under the laws of Arizona and currently has more than 931,500 customers. APS does not distribute any products. During 2003, no single purchaser or user of energy (other than Pinnacle West) accounted for more than 4% of consolidated electric revenues. See “Current Status – General” and “Regulation and Competition” above for additional background information about APS’ business, including its marketing and trading division.
     At December 31, 2003, APS employed approximately 6,000 people, including employees at jointly-owned generating facilities for which APS serves as the generating facility manager. APS’ principal executive offices are located at 400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999 (telephone 602-250-1000).
Purchased Power and Generating Fuel
     See “Properties – Capacity” in Item 2 for information about our power plants by fuel types.
      2003 Energy Mix
     Our consolidated sources of energy during 2003 were: purchased power – 54.4% (approximately 90.0% of which was for wholesale power operations); coal – 20.1%; nuclear – 14.7%; gas – 10.7%; and other (includes oil, hydro and solar) – 0.1%.
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     APS’ sources of energy during 2003 were: purchased power – 55.3% (approximately 75.0% of which was for wholesale power operations); coal – 24.5%; nuclear – 17.9%; gas – 2.2%; and other (includes oil, hydro and solar) – 0.1%.
      Coal Supply
      Cholla Cholla is a coal-fired power plant located in northeastern Arizona. It is a jointly-owned facility operated by APS. APS purchases most of Cholla’s coal requirements from a coal supplier that mines all of the coal under a long-term lease of coal reserves owned by the Navajo Nation, the federal government and private landholders. Cholla has sufficient coal under current contracts to ensure a reliable fuel supply through 2007. This includes our expected requirements for low sulfur coal, which is required for limited operating conditions; however, if necessary, low sulfur coal may be purchased on the open market. APS may purchase a portion of Cholla’s coal requirements on the spot market to take advantage of competitive pricing options. Following expiration of current contracts, APS believes that numerous competitive fuel supply options will exist to ensure the continued operation of Cholla for its useful life.
      Four Corners Four Corners is a coal-fired power plant located in the northwestern corner of New Mexico. It is a jointly-owned facility operated by APS. APS purchases all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation. The Four Corners coal contract runs through July 2016, with options to extend the contract for five to fifteen additional years beyond the plant site lease expiration in 2017.
      Navajo Generating Station The Navajo Generating Station is a coal-fired power plant located in northern Arizona. It is a jointly-owned facility operated by Salt River Project. The Navajo Generating Station’s coal requirements are purchased from a supplier with long-term leases from the Navajo Nation and the Hopi Tribe. The Navajo Generating Station is under contract with its coal supplier through 2011, with options to extend through the plant site lease expiration in 2019. The Navajo Generating Station lease waives certain taxes through the lease expiration in 2019. The lease provides for the potential to renegotiate the coal royalty in 2007 and 2017 and a five-year price review, each of which may impact the fuel price.
     See “Properties – Capacity” in Item 2 for information about APS’ ownership interests in Cholla, Four Corners and the Navajo Generating Station. See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information regarding our coal mine reclamation obligations.
      Natural Gas Supply
     See Note 11 of Notes to Consolidated Financial Statements in Item 8 for a discussion of our natural gas requirements.
      Nuclear Fuel Supply
      Palo Verde Fuel Cycle Palo Verde is a nuclear power plant located about 50 miles west of Phoenix, Arizona. It is a jointly-owned facility operated by APS. The fuel cycle for Palo Verde is comprised of the following stages:

•	 	mining and milling of uranium ore to produce uranium concentrates;	
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•	 	conversion of uranium concentrates to uranium hexafluoride;	
 	
•	 	enrichment of uranium hexafluoride;	
 	
•	 	fabrication of fuel assemblies;	
 	
•	 	utilization of fuel assemblies in reactors; and	
 	
•	 	storage and disposal of spent nuclear fuel.	
     The Palo Verde participants have contracted for all of Palo Verde’s requirements for uranium concentrates and conversion services through 2008. The Palo Verde participants have also contracted for all of Palo Verde’s enrichment services through 2010 and fuel assembly fabrication services until at least 2015.
      Spent Nuclear Fuel and Waste Disposal See “Palo Verde Nuclear Generating Station” in Note 11 of Notes to Consolidated Financial Statements in Item 8 for a discussion of spent nuclear fuel and waste disposal.
Purchased Power Agreements
     In addition to its own available generating capacity (see “Properties” in Item 2), APS purchases electricity under various arrangements. One of the most important of these is a long-term contract with Salt River Project. The amount of electricity available to APS is based in large part on customer demand within certain areas now served by APS pursuant to a related territorial agreement. The generating capacity available to APS pursuant to the contract was 343 MW from January through May 2003, and starting in June 2003, it changed to 350 MW. In 2003, APS received approximately 952,146 MWh of energy under the contract and paid about $64.4 million for capacity availability and energy received. This contract may be canceled by Salt River Project on three years’ notice, given no earlier than December 31, 2003. To date, Salt River Project has not given any notice to cancel. APS may also cancel the contract on five years’ notice, given no earlier than December 31, 2006.
     In September 1990, APS entered into a thirty-year seasonal capacity exchange agreement with PacifiCorp. Under this agreement, APS receives electricity from PacifiCorp during the summer peak season (from May 15 to September 15) and APS returns electricity to PacifiCorp during the winter season (from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW of capacity and a related amount of energy available to it under the agreement for its respective seasons. In 2003, APS received approximately 571,392 MWh of energy under the capacity exchange. APS must also make additional offers of energy to PacifiCorp each year through October 31, 2020. Pursuant to this requirement, during 2003, PacifiCorp received offers of 1,091,450 MWh and purchased about 168,000 MWh.
     In December 2003, APS issued a request for proposals for the purchase of at least 500 MW of long-term power supply resources for delivery beginning June 1, 2007 to be used for APS’ anticipated retail load. For additional information, see “Request for Proposals” in Note 3 of Notes to Consolidated Financial Statements in Item 8.
     Consistent with the ACC’s Track B Order, APS issued a request for proposals (“RFP”) in March 2003 and, as a result of that RFP, on or before May 6, 2003, APS entered into contracts with three parties, including Pinnacle West Energy, to meet a portion of APS’ capacity and energy requirements for the years 2003 through 2006. See “Track B Order” in Note 3 of Notes to
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Consolidated Financial Statements in Item 8 for additional information about the contracts and the Track B Order.
Construction Program
     During the years 2001 through 2003, APS incurred approximately $1.4 billion in capital expenditures. APS’ capital expenditures for the years 2004 through 2006 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 $429 million in 2003. APS’ capital expenditures, including expenditures for environmental control facilities, for the years 2004 through 2006 have been estimated as follows:
(dollars in millions) 

By Year
	 	By Major Facilities
	
2004	 	$	426	 	 	Delivery	 	$	1,152	 	
2005	 	 	562	 	 	Generation	 	 	467	 	
2006	 	 	655	 	 	Other	 	 	24	 	
 	 	 		 	 	 	 	 		 	
Total	 	$	1,643	 	 	Total	 	$	1,643	 	
 	 	 		 	 	 	 	 		 	
     The above amounts exclude capitalized interest costs and include capitalized property taxes and approximately $30 million per year for nuclear fuel. These amounts include only APS’ generation (production) assets. APS conducts a continuing review of its construction program.
     See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Needs and Resources by Company” in Item 7 for additional information about APS’ and Pinnacle West Energy’s construction programs.
Environmental Matters
      EPA Environmental Regulation
      Regional Haze Rules On April 22, 1999, the EPA announced final regional haze rules. These new regulations require states to submit, by 2008, implementation plans to eliminate all man-made emissions causing visibility impairment in certain specified areas, including Class I Areas in the Colorado Plateau, and to consider and potentially apply the best available retrofit technology for major stationary sources.
     The rules allow nine western states and tribes to follow an alternate implementation plan and schedule for the Class I Areas. Five western states, including Arizona, have submitted proposed State Implementation Plans (SIPs) to the EPA to implement this alternative plan. If the EPA approves Arizona’s SIP, APS does not anticipate any new emission reduction requirements for its Arizona plants through 2013.
     With respect to hazardous air pollutants emitted by electric utility steam generating units, the EPA determined in 2000 that mercury emissions and other hazardous air pollutants from coal and oil-fired power plants should be regulated. The EPA recently proposed two alternatives to regulate mercury emissions from these plants. Under the first alternative, the EPA would promulgate a Maximum Achievable Control Technology (MACT) standard establishing mercury emission limitations for coal- and oil-fired power plants, effective 2008. APS is currently assessing the need
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for additional controls to meet this proposed alternative. Under the second alternative, the EPA would rescind its 2000 finding requiring the establishment of a MACT standard for such plants, and would instead establish a two-phased mercury emissions trading program under the Clean Air Act’s new source performance standards provisions. If this second alternative is adopted, APS does not anticipate any emission reduction requirements under the first phase of the program (from 2010 through 2018). Because the ultimate requirements that the EPA may impose are not yet known, we cannot currently estimate the capital expenditures, if any, which may be required.
      Federal Implementation Plan In September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and Four Corners. The FIP is similar to current Arizona regulation of the Navajo Generating Station and New Mexico regulation of Four Corners, with minor modifications. APS does not currently expect the FIP to have a material adverse effect on its financial position, results of operations or liquidity.
      Superfund The Comprehensive Environmental Response, Compensation, and Liability Act (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 “potentially responsible party” in the Motorola 52 nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this superfund site. The EPA has only recently begun to study the OU3 site. Because the ultimate remediation requirements the EPA may require are not yet known, we cannot currently estimate the expenditures, if any, which may be required.
      Manufactured Gas Plant Sites APS is currently investigating properties which it now owns or which were previously owned by it or its corporate predecessors, that were at one time sites of, or sites associated with, manufactured gas plants. Where appropriate, APS conducts clean-up activities for these sites. APS does not expect these matters to have a material adverse effect on its financial position, results of operations or liquidity.
      Arizona Department of Environmental Quality
     ADEQ issued two NOVs to APS in 2001 alleging, among other things, the burning of unauthorized materials and storage of hazardous waste without a permit at the Cholla Power Plant. APS, the Attorney General for the State of Arizona and ADEQ have reached an agreement (in the form of a Consent Judgment) to settle this matter. The Consent Judgment (No. CV2004-000731) was entered on January 26, 2004, and on February 2, 2004, pursuant to its terms, APS paid a $200,000 penalty to the State of Arizona.
     ADEQ issued an NOV to APS in January 2004 alleging that, among other things, the discharge limit for lead was exceeded at the Saguaro Power Plant. APS is in the process of investigating this matter.
      Navajo Nation Environmental Issues
     Four Corners and the Navajo Generating Station are located on the Navajo Reservation and are held under easements granted by the federal government as well as leases from the Navajo Nation. APS is the Four Corners operating agent. APS owns a 100% interest in Four Corners Units
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1, 2 and 3, and a 15% interest in Four Corners Units 4 and 5. APS owns a 14% interest in Navajo Generating Station Units 1, 2 and 3.
     In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water and pesticide activities, including those activities that occur at Four Corners and the Navajo Generating Station. On October 17, 1995, the Four Corners participants and the Navajo Generating Station participants each filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, challenging the applicability of the Navajo Nation as to Four Corners and 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. APS cannot currently predict the outcome of this matter.
     In February 1998, the EPA issued regulations identifying those Clean Air Act provisions for which it is appropriate to treat Indian tribes in the same manner as states. The EPA has announced that it has not yet determined whether the Clean Air Act would supersede pre-existing binding agreements between the Navajo Nation and the Four Corners participants and the Navajo Generating Station participants that could limit the Navajo Nation’s environmental regulatory authority over the Navajo Generating Station and Four Corners. APS believes that the Clean Air Act does not supersede these pre-existing agreements. APS cannot currently predict the outcome of this matter.
     In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. We believe 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. We cannot currently predict the outcome of this matter.
Water Supply
     Assured supplies of water are important for our generating plants. At the present time, APS has adequate water to meet its needs. However, conflicting claims to limited amounts of water in the southwestern United States have resulted in numerous court actions.
     Both groundwater and surface water in areas important to APS’ operations have been the subject of inquiries, claims and legal proceedings, which will require a number of years to resolve. APS is one of a number of parties in a proceeding before a state court in New Mexico to adjudicate rights to a stream system from which water for Four Corners is derived. ( State of New Mexico, in the relation of S.E. Reynolds, State Engineer vs. United States of America, City of Farmington, Utah International, Inc., et al ., San Juan County, New Mexico, District Court No. 75-184). 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 a then-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. (In re The General Adjudication of All
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Rights to Use Water in the Gila River System and Source , Supreme Court Nos. WC-79-0001 through WC 79-0004 (Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the geographic area subject to the summons. APS’ rights and the rights of the Palo Verde participants to the use of groundwater and effluent at Palo Verde are potentially at issue in this action. As project manager of Palo Verde, APS filed claims that dispute the court’s jurisdiction over the Palo Verde participants’ groundwater rights and their contractual rights to effluent relating to Palo Verde. Alternatively, APS seeks confirmation of such rights. Three of APS’ other power plants and two of Pinnacle West Energy’s 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 will continue in the trial court. 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. ( In re The General Adjudication of All Rights to Use Water in the Little Colorado River System and Source , Supreme Court No. WC-79-0006 WC-6, Apache County No. 6417). APS’ groundwater resource utilized at Cholla is within the geographic area subject to the adjudication and is therefore potentially at issue in the case. APS’ claims dispute the court’s jurisdiction over its groundwater rights. Alternatively, APS seeks confirmation of such rights. A number of parties are in the process of settlement negotiations with respect to certain claims in this matter. Other claims have been identified as ready for litigation in motions filed with the court. No trial date concerning APS’ water rights claims has been set in this matter.
     Although the above matters remain subject to further evaluation, APS expects that the described litigation will not have a material adverse impact on its financial position, results of operations 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 in 2004, as well as later years if adequate moisture is not received in the watershed that supplies the area. We are negotiating agreements with various parties to provide backup supplies of water for 2004, if required, and are continuing to work with area stakeholders to implement additional agreements to minimize the effect, if any, on operations of the plant for 2005 and later years. The effect of the drought cannot be fully assessed at this time, and we 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.
BUSINESS OF PINNACLE WEST ENERGY CORPORATION
     Pinnacle West Energy was incorporated in 1999 under the laws of the State of Arizona and is engaged principally in the operation of generating plants. Pinnacle West Energy had approximately 100 employees as of December 31, 2003. Pinnacle West Energy’s principal offices are located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone (602) 250-4145).
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     See “Liquidity and Capital Resources” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of Pinnacle West Energy’s capital expenditures.
     Pinnacle West Energy’s Arizona plants were built as a result of what we believed was a regulatory restriction against APS’ construction of additional plants and based on the requirement in the 1999 Settlement Agreement that APS transfer its generation assets. As discussed under “APS General Rate Case and Retail Rate Adjustment Mechanisms” in Note 3 of Notes to Consolidated Financial Statements in Item 8, as part of its general rate case, APS is seeking rate base treatment of the PWEC Dedicated Assets.
     At December 31, 2003, Pinnacle West Energy had total assets of $1.4 billion. Pinnacle West Energy had a net loss of $1 million in 2003, a net loss of $19 million in 2002 and net income of $18 million in 2001. See footnote (c) in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Earnings Contributions by Subsidiary and Business Segments” in Item 7 for a discussion of Pinnacle West Energy’s contract to supply purchase power requirements in summer months through September 2006.
BUSINESS OF APS ENERGY SERVICES COMPANY, INC.
     APS Energy Services was incorporated in 1998 under the laws of the State of Arizona and provides competitive commodity-related energy services (such as direct access commodity contracts, energy procurement and energy supply consultation) and energy-related products and services (such as energy master planning, energy use consultation and facility audits, cogeneration analysis and installation and project management) to commercial, industrial and institutional retail customers in the western United States. APS Energy Services had approximately 100 employees as of December 31, 2003. APS Energy Services’ principal offices are located at 400 East Van Buren Street, Phoenix, Arizona 85004 (telephone (602) 250-5000).
     APS Energy Services had net income of $16 million in 2003, pretax income of $28 million in 2002, and a pretax loss of $10 million in 2001. Income taxes related to APS Energy Services were recorded by the parent company prior to 2003. At December 31, 2003, APS Energy Services had total assets of $90 million.
BUSINESS OF SUNCOR DEVELOPMENT COMPANY
     SunCor was incorporated in 1965 under the laws of the State of Arizona and is a developer of residential, commercial and industrial real estate projects in Arizona, Idaho, New Mexico and Utah. The principal executive offices of SunCor are located at 80 East Rio Salado Parkway, Suite 410, Tempe, Arizona 85281 (telephone (480) 317-6800). SunCor and its subsidiaries had approximately 800 full- and part-time employees at December 31, 2003.
     At December 31, 2003, SunCor had total assets of about $439 million. SunCor’s assets consist primarily of land with improvements, commercial buildings, golf courses and other real estate investments. SunCor intends to continue its focus on real estate development of master-planned communities, mixed-use residential, commercial, office and industrial projects.
     SunCor projects under development include seven master-planned communities and several commercial projects. The commercial projects and four of the master-planned communities are in
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Arizona. Other master-planned communities are located near St. George, Utah, Boise, Idaho and Santa Fe, New Mexico.
     SunCor has implemented an accelerated asset sales program for 2004 and 2005. As a result of this program, SunCor expects to have net income of approximately $30 – 40 million a year in this period. SunCor also expects to make cash distributions of $80 – 100 million annually to the parent in this time frame.
     For the past three years, SunCor’s operating revenues were approximately: $362 million in 2003; $201 million in 2002; and $169 million in 2001. For those same periods, SunCor’s net income was approximately $56 million in 2003; $19 million in 2002; and $3 million in 2001.
     See Note 6 of Notes to Consolidated Financial Statements in Item 8 for information regarding SunCor’s long-term debt and “Liquidity and Capital Resources” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for a discussion of SunCor’s capital expenditures.
BUSINESS OF EL DORADO INVESTMENT COMPANY
     El Dorado was incorporated in 1983 under the laws of the State of Arizona. El Dorado’s largest holding is a majority interest in NAC, a company specializing in spent nuclear fuel technology. El Dorado also 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, we may use El Dorado, when appropriate, as our subsidiary for investments that are strategic to our principal 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 approximately 100 employees (all NAC) at December 31, 2003.
     El Dorado had pretax income of $7 million in 2003, a pretax loss of $55 million in 2002 and net income of $0.2 million in 2001. The parent company recorded income taxes related to El Dorado in 2003 and 2002. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 for information regarding El Dorado’s 2002 losses. At December 31, 2003, El Dorado had total assets of $27 million.
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ITEM 2. PROPERTIES
Capacity
     Our generating facilities are described below. For APS’ plants, the “net accredited capacities” are reported, consistent with industry practice for regulated utilities. For Pinnacle West Energy, the “permitted capacities” are reported, consistent with industry practice for unregulated plants. 
APS – Net Accredited Capacity
     APS’ present generating facilities have net accredited capacities as follows:

 	 	Capacity (kW)
	
Coal:	 	 	 	 	
Units 1, 2 and 3 at Four Corners	 	 	560,000	 	
15% owned Units 4 and 5 at Four Corners	 	 	222,000	 	
Units 1, 2 and 3 at Cholla Plant	 	 	615,000	 	
14% owned Units 1, 2 and 3 at the Navajo Plant	 	 	315,000	 	

Subtotal	 	 	1,712,000	 	

Gas or Oil:	 	 	 	 	
Two steam units at Ocotillo and two steam units at Saguaro	 	 	430,000	 	
Eleven combustion turbine units	 	 	493,000	 	
Three combined cycle units	 	 	255,000	 	

Subtotal	 	 	1,178,000	 	

Nuclear:	 	 	 	 	
29.1% owned or leased Units 1, 2, and 3 at Palo Verde	 	 	1,113,000	 	

Hydro and Solar	 	 	9,191	 	

Total APS facilities	 	 	4,012,191	 	

Pinnacle West Energy – Permitted Capacities
     Pinnacle West Energy’s present generating facilities have permitted capacities as follows:

Gas or Oil:	 	 	 	 	
Two combined cycle units at Redhawk and two combined cycle units at West Phoenix	 	 	1,710,000	 	
One combustion turbine unit at Saguaro	 	 	80,000	 	

Total Pinnacle West Energy facilities	 	 	1,790,000	 	

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Reserve Margin
     APS’ 2003 peak one-hour demand on its electric system was recorded on July 14, 2003 at 6,332,400 kW, compared to the 2002 peak of 5,802,900 kW recorded on July 9, 2002. Firm purchases totaling 4,198,000 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 12.1%. Taking into account additional capacity then available to APS under long-term purchase power contracts as well as APS’ and Pinnacle West Energy’s generating capacity, APS’ capability of meeting system demand on July 14, 2003 amounted to 6,371,600 kW, for an installed reserve margin of 1.0%. The power actually available to APS from its resources fluctuates from time to time due in part to outages, both planned and unplanned, and technical problems. The available capacity from sources actually operable at the time of the 2003 peak amounted to 3,736,500 kW, for a margin of negative 50.4%.
     See “Business of Arizona Public Service Company – Purchased Power Agreements” in Item 1 for information about certain of APS’ long-term power agreements. See “Request for Proposals” in Note 3 of Notes to Consolidated Financial Statements in Item 8 for information regarding a request for proposals issued by APS in December 2003 for the purchase of at least 500 MW of long-term power supply resources for delivery beginning June 1, 2007.
Plant Sites Leased from Navajo Nation
     The Navajo Generating Station and Four Corners are located on land held under easements from the federal government and also under leases from the Navajo Nation. These are long-term agreements with options to extend, and we do not believe that the risk with respect to enforcement of these easements and leases is material. The majority of coal contracted for use in these plants and certain associated transmission lines are also located on Indian reservations. See “Purchased Power and Generating Fuel – Coal Supply” in Item 1.
Palo Verde Nuclear Generating Station
      Regulatory
     Operation of each of the three Palo Verde units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power operating licenses, each valid for a period of approximately 40 years, authorize APS, as operating agent for Palo Verde, to operate the three Palo Verde units at full power.
      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 to recover certain types of ACC-approved 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”
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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 the external sinking fund mechanism are not met. APS currently relies on the 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. The Rules provide that decommissioning costs would be recovered through a non-bypassable “system benefits” charge, which would allow APS to maintain its external sinking fund mechanism. See Note 12 of Notes to Consolidated Financial Statements in Item 8 for additional information about our nuclear decommissioning costs.
      Palo Verde Liability and Insurance Matters
     See “Palo Verde Nuclear Generating Station” in Note 11 of Notes to Consolidated Financial Statements in Item 8 for a discussion of the insurance maintained by the Palo Verde participants, including APS, for Palo Verde. 
Property Not Held in Fee or Subject to Encumbrances
      Jointly-Owned Facilities
     APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS’ interest in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2003:

 	 	 	Percent	
 	 	 	Owned by APS	
 	 	 		
Generating facilities:	 	 	 	 	
 	Palo Verde Nuclear Generating Station Units 1 and 3	 	 	29.1	%	
 	Palo Verde Nuclear Generating Station Unit 2 (see “Palo Verde Leases” below)	 	 	17.0	%	
 	Four Corners Steam Generating Station Units 4 and 5	 	 	15.0	%	
 	Navajo Steam Generating Station Units 1, 2, and 3	 	 	14.0	%	
 	Cholla Steam Generating Station Common Facilities (a)	 	 	62.4	%(b)	
Transmission facilities:	 	 	 	 	
 	ANPP 500KV System	 	 	35.8	%(b)	
 	Navajo Southern System	 	 	31.4	%(b)	
 	Palo Verde – Yuma 500KV System	 	 	23.9	%(b)	
 	Four Corners Switchyards	 	 	27.5	%(b)	
 	Phoenix – Mead System	 	 	17.1	%(b)	
 	Palo Verde – Estrella 500KV System	 	 	55.5	%(b)	
 	Palo Verde – SE Valley Project	 	 	15.0	%(b)	
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 	(a)	 	PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned.	
 		
 	(b)	 	Weighted average of interests.	
      Palo Verde Leases
     In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. APS accounts for these leases as operating leases. The leases, which have terms of 29.5 years, contain options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. See Notes 9 and 20 of Notes to Consolidated Financial Statements in Item 8 for additional information regarding the Palo Verde Unit 2 sale leaseback transactions.
      APS First Mortgage Lien
     APS’ first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment and other excluded assets). See Note 6 of Notes to Consolidated Financial Statements in Item 8 for information regarding APS’ outstanding first mortgage bonds.
Transmission Access
     APS’ transmission facilities consist of approximately 5,000 pole miles of overhead lines and approximately 35 miles of underground lines, all of which are located within the State of Arizona. APS’ distribution facilities consist of approximately 12,000 pole miles of overhead lines and approximately 13,000 miles of underground lines, all of which are located within the State of Arizona. In June 2003 APS energized a new 37-mile 500-kilovolt transmission line that runs from Palo Verde to the Phoenix area. See also “Regional Transmission Organizations” in Item 1 above.
Other Information Regarding Our Properties
     See “Environmental Matters” and “Water Supply” in Item 1 with respect to matters having a possible impact on the operation of certain of our power plants.
     See “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 our construction program.
Information Regarding SunCor’s Properties
     See “Business of SunCor Development Company” in Item 1 for information regarding SunCor’s properties. SunCor’s debt is collateralized by interests in certain real property.
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ITEM 3. LEGAL PROCEEDINGS
     See “Environmental Matters” and “Water Supply” in Item 1 in regard to pending or threatened litigation and other disputes. See Note 3 of Notes to Consolidated Financial Statements in Item 8 for a discussion of the ACC retail electric competition Rules, the Track A Order and related litigation.
     See Note 11 of Notes to Consolidated Financial Statements in Item 8 for information relating to the FERC proceedings on California energy market issues and a claim by Citizens that APS overcharged Citizens under a power service agreement.  
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
     Not applicable.
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SUPPLEMENTAL ITEM.
EXECUTIVE OFFICERS OF THE REGISTRANT
Our executive officers are as follows:

Name	 	Age at March 1, 2004	 	Position(s) at March 2, 2004	
	 		 		
William J. Post	 	 	53	 	 	Chairman of the Board and Chief Executive Officer (1)	
 	 	 	 	 	 	 	
Jack E. Davis	 	 	57	 	 	President and Chief Operating Officer, and President and Chief Executive Officer, APS (1)	
 	 	 	 	 	 	 	
Donald E. Brandt	 	 	49	 	 	Executive Vice President and Chief Financial Officer	
 	 	 	 	 	 	 	
Armando B. Flores	 	 	60	 	 	Executive Vice President,
Corporate Business Services,
APS	
 	 	 	 	 	 	 	
Chris N. Froggatt	 	 	46	 	 	Vice President and Controller, APS	
 	 	 	 	 	 	 	
Barbara M. Gomez	 	 	49	 	 	Vice President and Treasurer	
 	 	 	 	 	 	 	
James M. Levine	 	 	54	 	 	Executive Vice President, Generation, APS and President, Pinnacle West Energy	
 	 	 	 	 	 	 	
Nancy C. Loftin	 	 	50	 	 	Vice President, General Counsel and Secretary	
 	 	 	 	 	 	 	
Donald G. Robinson	 	 	50	 	 	Vice President, Planning, APS	
 	 	 	 	 	 	 	
Steven M. Wheeler	 	 	55	 	 	Executive Vice President, Customer Service and Regulation, APS	

(1)	 	Member of the Board of Directors.	
     The executive officers of Pinnacle West are elected no less often than annually and may be removed by the Board of Directors at any time. The terms served by the named officers in their current positions and the principal occupations (in addition to those stated in the table) of such officers for the past five years have been as follows:
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     Mr. Post was elected Chairman of the Board effective February 2001, and Chief Executive Officer effective February 1999. He has served as an officer of Pinnacle West since 1995 in the following capacities: from August 1999 to February 2001 as President; from February 1997 to February 1999 as President; and from June 1995 to February 1997 as Executive Vice President. Mr. Post is also Chairman of the Board (since February 2001) of APS. He was President of APS from February 1997 until October 1998 and he was Chief Executive Officer from February 1997 until October 2002. Mr. Post is also a director of APS, Pinnacle West Energy and Phelps Dodge Corporation.
     Mr. Davis was elected President effective February 2001 and Chief Operating Officer effective September 2003. Prior to that time he was Chief Operating Officer and Executive Vice President of Pinnacle West (April 2000 – February 2001) and Executive Vice President, Commercial Operations of APS (September 1996 – October 1998). Mr. Davis is also President of APS (since October 1998) and Chief Executive Officer of APS (since October 2002). He is a director of APS and Pinnacle West Energy.
     Mr. Brandt was elected to his present position in September 2003 and was Senior Vice President and Chief Financial Officer (December 2002 – September 2003). Prior to that time he was Senior Vice President and Chief Financial Officer of Ameren Corporation (diversified energy services company). Mr. Brandt was elected Executive Vice President and Chief Financial Officer of APS in September 2003. He was also Senior Vice President and Chief Financial Officer of APS (January 2003 – September 2003).
     Mr. Flores was elected to his present position in September 2003. Prior to that time he was Executive Vice President, Corporate Business Services of Pinnacle West (July 1999 – September 2003). He was also Executive Vice President, Corporate Business Services of APS (October 1998 – July 1999).
     Mr. Froggatt was elected to his present position in October 2002. Prior to that time he was Vice President and Controller of Pinnacle West (August 1999 – October 2002), Controller of Pinnacle West (July 1999 – August 1999) and Controller of APS (July 1997 – July 1999).
     Ms. Gomez was elected to her present position in February 2004. Prior to that time, she was Treasurer (August 1999 – February 2004) and Manager, Treasury Operations of APS (1997 – 1999). She was also elected Treasurer of APS in October 1999 and Vice President of APS in February 2004.
     Mr. Levine was elected Executive Vice President of APS in July 1999 and President and Chief Executive Officer of Pinnacle West Energy in January 2003. Prior to that time he was Senior Vice President, Nuclear Generation of APS (September 1996 – July 1999).
     Ms. Loftin was elected Vice President and General Counsel in July 1999 and Secretary in October 2002. She was elected to the positions of Vice President and Chief Legal Counsel of APS in September 1996. She was also elected Vice President and General Counsel of APS in July 1999 and Secretary of APS in October 2002.
     Mr. Robinson was elected to his present position in September 2003. Prior to that time he was Vice President, Finance and Planning of APS (October 2002 – September 2003), Vice President, Regulation and Planning of Pinnacle West (June 2001 – October 2002) and Director, Accounting, Regulation and Planning of Pinnacle West (prior to June 2001).
     Mr. Wheeler was elected to his present position in September 2003. Prior to that time he was Senior Vice President, Regulation, System Planning and Operations of APS (October 2002 – September 2003) and Senior Vice President, Transmission, Regulation and Planning of Pinnacle
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     West and APS (June 2001 – October 2002). Prior to that time he was a partner with Snell & Wilmer L.L.P.  
PART II 
ITEM 5. MARKET FOR REGISTRANT’S COMMON
STOCK AND RELATED STOCKHOLDER MATTERS
     Our common stock is publicly held and is traded on the New York and Pacific Stock Exchanges. At the close of business on March 11, 2004, our common stock was held of record by approximately 35,623 shareholders. 
QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE
STOCK SYMBOL: PNW

 	 	 	 	 	 	 	 	 	 	 	 	 	 	Dividends	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Per	
2003	 	High	 	Low	 	Close	 	Share	
	 		 		 		 		
1st Quarter	 	$	37.13	 	 	$	28.34	 	 	$	33.24	 	 	$	0.425	 	
2nd Quarter	 	 	39.59	 	 	 	31.35	 	 	 	37.45	 	 	 	0.425	 	
3rd Quarter	 	 	38.03	 	 	 	32.87	 	 	 	35.50	 	 	 	0.425	 	
4th Quarter	 	 	40.48	 	 	 	34.91	 	 	 	40.02	 	 	 	0.450	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Dividends	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	Per	
2002	 	High	 	Low	 	Close	 	Share	
	 		 		 		 		
1st Quarter	 	$	45.60	 	 	$	39.36	 	 	$	45.35	 	 	$	0.400	 	
2nd Quarter	 	 	46.68	 	 	 	37.08	 	 	 	39.50	 	 	 	0.400	 	
3rd Quarter	 	 	39.72	 	 	 	25.82	 	 	 	27.76	 	 	 	0.400	 	
4th Quarter	 	 	34.36	 	 	 	21.70	 	 	 	34.09	 	 	 	0.425	 	
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ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA 

 	 	 	2003	 	2002	 	2001	 	2000	 	1999	
 	 	 		 		 		 		 		
 	 	 	(dollars in thousands, except shares and per share amounts)	
OPERATING RESULTS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Regulated electricity segment (a)	 	$	1,978,075	 	 	$	1,890,391	 	 	$	1,984,305	 	 	$	2,538,752	 	 	$	1,915,108	 	
 	Marketing and trading segment (a)	 	 	391,886	 	 	 	286,879	 	 	 	469,784	 	 	 	418,532	 	 	 	154,125	 	
 	Real estate segment	 	 	361,604	 	 	 	201,081	 	 	 	168,908	 	 	 	158,365	 	 	 	130,169	 	
 	Other revenues	 	 	86,287	 	 	 	61,937	 	 	 	11,771	 	 	 	3,873	 	 	 	439	 	
Income from continuing operations	 	$	230,576	 	 	$	206,198	 	 	$	327,367	 	 	$	302,332	 	 	$	269,772	 	
Discontinued operations – net of income taxes (b)(c)	 	 	10,003	 	 	 	8,955	 	 	 	—	 	 	 	—	 	 	 	38,000	 	
Extraordinary charge – net of income taxes (d)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(139,885	)	
Cumulative effect of change in accounting – net of income taxes (e) (f)	 	 	—	 	 	 	(65,745	)	 	 	(15,201	)	 	 	—	 	 	 	—	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Net income	 	$	240,579	 	 	$	149,408	 	 	$	312,166	 	 	$	302,332	 	 	$	167,887	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
COMMON STOCK DATA	
Book value per share – year-end	 	$	30.97	 	 	$	29.40	 	 	$	29.46	 	 	$	28.09	 	 	$	26.00	 	
Earnings (loss) per weighted average common share outstanding:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Continuing operations – basic	 	$	2.53	 	 	$	2.43	 	 	$	3.86	 	 	$	3.57	 	 	$	3.18	 	
 	Discontinued operations	 	 	0.11	 	 	 	0.10	 	 	 	—	 	 	 	—	 	 	 	0.45	 	
 	Extraordinary charge	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1.65	)	
 	Cumulative effect of change in accounting	 	 	—	 	 	 	(0.77	)	 	 	(0.18	)	 	 	—	 	 	 	—	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Net income – basic	 	$	2.64	 	 	$	1.76	 	 	$	3.68	 	 	$	3.57	 	 	$	1.98	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Continuing operations – diluted	 	$	2.52	 	 	$	2.43	 	 	$	3.85	 	 	$	3.56	 	 	$	3.17	 	
 	Net income – diluted	 	$	2.63	 	 	$	1.76	 	 	$	3.68	 	 	$	3.56	 	 	$	1.97	 	
Dividends declared per share	 	$	1.725	 	 	$	1.625	 	 	$	1.525	 	 	$	1.425	 	 	$	1.325	 	
Indicated annual dividend rate per share – year-end	 	$	1.80	 	 	$	1.70	 	 	$	1.60	 	 	$	1.50	 	 	$	1.40	 	
Weighted-average common shares outstanding – basic	 	 	91,264,696	 	 	 	84,902,946	 	 	 	84,717,649	 	 	 	84,732,544	 	 	 	84,717,135	 	
Weighted-average common shares outstanding – diluted	 	 	91,405,134	 	 	 	84,963,921	 	 	 	84,930,140	 	 	 	84,935,282	 	 	 	85,008,527	 	
BALANCE SHEET DATA	
Total assets	 	$	9,536,378	 	 	$	9,139,157	 	 	$	8,529,124	 	 	$	7,697,558	 	 	$	7,095,441	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Liabilities and equity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt less current maturities	 	$	2,897,725	 	 	$	2,743,741	 	 	$	2,673,078	 	 	$	1,955,083	 	 	$	2,206,052	 	
Other liabilities	 	 	3,808,874	 	 	 	3,709,263	 	 	 	3,356,723	 	 	 	3,359,761	 	 	 	2,683,656	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total liabilities	 	 	6,706,599	 	 	 	6,453,004	 	 	 	6,029,801	 	 	 	5,314,844	 	 	 	4,889,708	 	
Common stock equity	 	 	2,829,779	 	 	 	2,686,153	 	 	 	2,499,323	 	 	 	2,382,714	 	 	 	2,205,733	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total liabilities and equity	 	$	9,536,378	 	 	$	9,139,157	 	 	$	8,529,124	 	 	$	7,697,558	 	 	$	7,095,441	 	

(a)	 	Includes reclassifications of revenues in 2003, 2002 and 2001 for the adoption of EITF 03-11. See Note 18 of Notes to Consolidated Financial Statements.	
 		
(b)	 	Tax benefit stemming from the resolution of income tax matters related to a former subsidiary, MeraBank, A Federal Savings Bank in 1999.	
 		
(c)	 	Real estate discontinued operations in 2003 and 2002. See Note 22 of Notes to Consolidated Financial Statements.	
 		
(d)	 	Charges associated with a regulatory disallowance. See “Regulatory Accounting” in Note 1 of Notes to Consolidated Financial Statements.	
 		
(e)	 	Change in accounting standards related to derivatives in 2001. See Note 18 of Notes to Consolidated Financial Statements.	
 		
(f)	 	Change in accounting standards related to energy trading activities in 2002. See Note 18 of Notes to Consolidated Financial Statements.	
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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 the Consolidated Financial Statements and the related Notes that appear in Item 8 of this report.
OVERVIEW
     We own all of the outstanding common stock of APS. 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 the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. Through its marketing and trading division, APS also generates, sells and delivers electricity to wholesale customers in the western United States. APS has historically accounted for a substantial part of our revenues and earnings. Growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.
     Pinnacle West Energy is our unregulated generation subsidiary. We formed Pinnacle West Energy in 1999 as a result of the ACC’s requirement that APS transfer all of its competitive assets and services to an affiliate or to a third party by the end of 2002. We planned to transfer APS’ generation assets to Pinnacle West Energy. Additionally, Pinnacle West Energy constructed several power plants to meet growing energy needs (1790 MW in Arizona and 570 MW in Nevada). In September 2002, the ACC issued the Track A Order, which prohibited APS from transferring its generation assets to Pinnacle West Energy. As a result of the Track A Order, we are seeking to transfer the plants built by Pinnacle West Energy in Arizona to APS to unite the Arizona generation under one common owner, as originally intended.
     SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow, particularly during the years 2003 through 2005 due to accelerated asset sales activity. Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial, industrial and institutional retail customers in the western United States.
     The earnings contributions of our marketing and trading segment significantly decreased over the past two years due to lower market liquidity and deteriorating counterparty credit in the wholesale power markets in the western United States. The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with APS’ costs of serving retail customer energy requirements. We currently expect contributions from our trading activities to be negligible for 2004 and approximately $10 million (pretax) annually thereafter.
     We continue to focus on solid operational performance in our electricity generation and delivery activities. In the generation area, 2003 represented the twelfth consecutive year Palo Verde was the largest power producer in the United States. In the delivery area, we focus on superior reliability and expanding our transmission and distribution system to meet growth and sustain reliability.
27 

 

     We believe APS’ general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3 in Item 8, in this rate case APS has requested, among other things, a 9.8% retail rate increase (approximately $175 million annually), rate treatment for the PWEC Dedicated Assets and the recovery of $234 million written off by APS as part of the 1999 Settlement Agreement. In its filed testimony, the ACC staff recommended, among other things, that the ACC decrease APS’ rates by approximately 8% (approximately $143 million annually), not allow the PWEC Dedicated Assets to be included in APS’ rate base, and not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement. The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings and access to capital markets. We believe that APS’ rate case requests are supported by, among other things, APS’ demonstrated need for the PWEC Dedicated Assets; APS’ need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in APS’ high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard. The hearing on the rate case is scheduled to begin on May 25, 2004. We believe the ACC will be able to make a decision by the end of 2004.
     Other factors affecting our past and future financial results include customer growth; purchased power and fuel costs; operations and maintenance expenses, including those relating to plant outages; weather variations; depreciation and amortization expenses, which are affected by net additions to existing utility plant and other property and changes in regulatory asset amortization; and the expected performance of our subsidiaries, SunCor and El Dorado.
EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENTS
     We have three principal business segments (determined by products, services and the regulatory environment):

 	•	 	our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses and related activities and includes electricity generation, transmission and distribution;	
 		
 	•	 	our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services. In early 2003, we moved our marketing and trading activities to APS from Pinnacle West (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of APS’ generating assets to Pinnacle West Energy; and	
 		
 	•	 	our real estate segment, which consists of SunCor’s real estate development and investment activities.	
     The following tables summarize net income and segment details for the years ended December 31, 2003, 2002 and 2001 for Pinnacle West and each of our subsidiaries (dollars in millions):
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 	 	 	 	 	 	 	Regulated	 	Marketing and	 	 	 	 	 	 	 	 	
 	 	 	Total	 	Electricity	 	Trading	 	Real Estate (a)	 	Other (b)	
 	 	 		 		 		 		 		
2003	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
APS (c)	 	$	181	 	 	$	184	 	 	$	(3	)	 	$	—	 	 	$	—	 	
Pinnacle West Energy (c)	 	 	(1	)	 	 	—	 	 	 	(1	)	 	 	—	 	 	 	—	 	
APS Energy Services	 	 	16	 	 	 	—	 	 	 	13	 	 	 	—	 	 	 	3	 	
SunCor	 	 	46	 	 	 	—	 	 	 	—	 	 	 	46	 	 	 	—	 	
El Dorado (principally NAC) (d)	 	 	7	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7	 	
Parent company (d)	 	 	(18	)	 	 	(14	)	 	 	—	 	 	 	(1	)	 	 	(3	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Income from continuing operations	 	 	231	 	 	 	170	 	 	 	9	 	 	 	45	 	 	 	7	 	
 	Income from discontinued operations – net of income taxes	 	 	10	 	 	 	—	 	 	 	—	 	 	 	10	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net income	 	$	241	 	 	$	170	 	 	$	9	 	 	$	55	 	 	$	7	 	

 	 	 	 	 	 	 	Regulated	 	Marketing and	 	 	 	 	 	 	 	 	
 	 	 	Total	 	Electricity	 	Trading	 	Real Estate (a)	 	Other (b)	
 	 	 		 		 		 		 		
2002	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
APS (c)	 	$	199	 	 	$	198	 	 	$	1	 	 	$	—	 	 	$	—	 	
Pinnacle West Energy (c) (e)	 	 	(19	)	 	 	(21	)	 	 	2	 	 	 	—	 	 	 	—	 	
APS Energy Services (d)	 	 	28	 	 	 	—	 	 	 	23	 	 	 	—	 	 	 	5	 	
SunCor	 	 	10	 	 	 	—	 	 	 	—	 	 	 	10	 	 	 	—	 	
El Dorado (principally NAC) (d)	 	 	(55	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(55	)	
Parent company (d)	 	 	43	 	 	 	(7	)	 	 	32	 	 	 	—	 	 	 	18	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Income (loss) from continuing operations	 	 	206	 	 	 	170	 	 	 	58	 	 	 	10	 	 	 	(32	)	
Income from discontinued operations – net of income taxes	 	 	9	 	 	 	—	 	 	 	—	 	 	 	9	 	 	 	—	 	
Cumulative effect of change in accounting – net of income taxes (f)	 	 	(66	)	 	 	—	 	 	 	(66	)	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net income (loss)	 	$	149	 	 	$	170	 	 	$	(8	)	 	$	19	 	 	$	(32	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
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 	 	 	 	 	 	 	Regulated	 	Marketing and	 	 	 	 	 	 	 	 	
 	 	 	Total	 	Electricity	 	Trading	 	Real Estate (a)	 	Other	
 	 	 		 		 		 		 		
2001	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
APS (c)	 	$	281	 	 	$	139	 	 	$	142	 	 	$	—	 	 	$	—	 	
Pinnacle West Energy (c)	 	 	18	 	 	 	18	 	 	 	—	 	 	 	—	 	 	 	—	 	
APS Energy Services (d)	 	 	(10	)	 	 	—	 	 	 	(11	)	 	 	—	 	 	 	1	 	
SunCor	 	 	3	 	 	 	—	 	 	 	—	 	 	 	3	 	 	 	—	 	
El Dorado (d)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Parent company (d)	 	 	35	 	 	 	(5	)	 	 	40	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Income before accounting change	 	 	327	 	 	 	152	 	 	 	171	 	 	 	3	 	 	 	1	 	
Cumulative effect of change in accounting – net of income taxes (g)	 	 	(15	)	 	 	(15	)	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net income	 	$	312	 	 	$	137	 	 	$	171	 	 	$	3	 	 	$	1	 	

 	(a)	 	See Note 22, “Real Estate Activities – Discontinued Operations.”	
 		
 	(b)	 	The “Other” segment primarily includes activities related to El Dorado’s investment in NAC. We recorded pretax losses of $59 million in 2002, primarily related to NAC contracts with three customers.	
 		
 	(c)	 	Consistent with APS’ October 2001 ACC filing, APS entered into contracts with its affiliates to buy power through June 2003. The contracts reflected prices based on the fully-dispatchable dedication of the PWEC Dedicated Assets to APS’ Native Load customers (customers receiving power under traditional cost-based rate regulation). Beginning July 1, 2003, under the ACC Track B Order, APS was required to solicit bids for certain estimated capacity and energy requirements. Pinnacle West Energy bid and entered into a contract to supply most of these purchase power requirements in summer months through September 2006. See “Track B Order” in Note 3 for more information.	
 		
 	(d)	 	APS Energy Services’ net income prior to 2003 and El Dorado’s net income (loss) are primarily reported before income taxes. The income tax expense or benefit for these subsidiaries is recorded at the parent company.	
 		
 	(e)	 	In the fourth quarter of 2002 Pinnacle West Energy recorded a charge related to the cancellation of Redhawk Units 3 and 4 of approximately $30 million after income taxes ($49 million pretax).	
 		
 	(f)	 	As of October 1, 2002, we recorded a $66 million after-tax charge for the cumulative effect of a change in accounting for trading activities, for the early adoption of EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” See Note 18.	
 		
 	(g)	 	APS recorded a $15 million after-tax charge in 2001 for the cumulative effect of a change in accounting for derivatives related to the adoption of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” See Note 18.	
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     See Note 17 for additional financial information regarding our business segments. 
RESULTS OF OPERATIONS
General
     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs. Our real estate segment gross margin refers to real estate revenues less real estate operations costs of SunCor. Other gross margin refers to other operating revenues less other operating expenses, which primarily includes El Dorado’s investment in NAC, which we began consolidating in our financial statements in July 2002. Other gross margin also includes amounts related to APS Energy Services’ energy consulting services. In addition, we have reclassified certain prior period amounts to conform to our current period presentation, including netting of certain revenues and purchased power amounts as a result of the adoption of 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 Issue No. 02-3” (see Note 18).
2003 Compared with 2002
     Our consolidated net income for the year ended December 31, 2003 was $241 million compared with $149 million for the prior year. The 2002 net income includes a $66 million after-tax charge for the cumulative effect of a change in accounting for trading activities due to the adoption of EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (see Note 18). Excluding the accounting change, the $26 million increase in the period-to-period comparison reflects the following changes in earnings by segment:

 	•	 	Regulated Electricity Segment – Net income was flat when comparing the two years, due to offsetting factors. Net income in 2003 was negatively impacted by higher purchased power and fuel costs resulting from higher prices for hedged gas and purchased power; higher costs related to new power plants, net of purchased power savings; higher replacement power costs from plant outages due to higher market prices and more unplanned outages (Unit 3 of the Cholla Power Plant experienced an unplanned outage from August 3, 2003 through November, 2003 and Units 1 and 2 of the Redhawk Power Plant were substantially restricted for almost one-half of the fourth quarter to correct an equipment design defect); higher operations and maintenance costs related to increased pension and other benefits; two retail electricity price reductions; and higher depreciation expense related to increased delivery and other assets. These negative factors were offset by higher retail sales primarily due to customer growth and favorable weather; the absence of the 2002 write-off of Redhawk Units 3 and 4; lower operating costs primarily related to severance costs recorded in 2002; lower regulatory asset amortization; tax credits and favorable income tax adjustments related to prior years resolved in 2003; and higher income related to APS’ return to the AFUDC method of capitalizing construction finance costs.	
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 	•	 	Marketing and Trading Segment – Income from continuing operations decreased approximately $49 million primarily due to lower market liquidity and deteriorating counterparty credit in the wholesale power markets in the western United States.	
 		
 	•	 	Real Estate Segment – Net income improved approximately $36 million primarily due to increased asset, land and home sales.	
 		
 	•	 	Other Segment – Net income increased approximately $39 million primarily due to NAC losses recognized in 2002.	
     Additional details on the major factors that increased (decreased) income from continuing operations and net income for the year ended December 31, 2003 compared with the prior year are contained in the following table (dollars in millions).
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 	 	 	 	Increase (Decrease)	
 	 	 	 		
 	 	 	 	Pretax	 	After Tax	
 	 	 	 		 		
Regulated electricity segment gross margin:	 	 	 	 	 	 	 	 	
 	Increased purchased power and fuel costs primarily due to higher prices for hedged gas and purchased power	 	$	(60	)	 	$	(36	)	
 	Higher replacement power costs from plant outages due to higher market prices and more unplanned outages	 	 	(47	)	 	 	(28	)	
 	Retail electricity price reductions effective July 1, 2002 and July 1, 2003	 	 	(27	)	 	 	(16	)	
 	Higher retail sales volumes due to customer growth, excluding weather effects	 	 	48	 	 	 	29	 	
 	Decreased purchased power costs due to new power plants in service	 	 	16	 	 	 	10	 	
 	Effects of weather on retail sales	 	 	13	 	 	 	8	 	
 	Miscellaneous factors, net	 	 	5	 	 	 	2	 	
 	 	 	 		 	 	 		 	
 	 	Net decrease in regulated electricity segment gross margin	 	 	(52	)	 	 	(31	)	
 	 	 		 	 	 		 	
Marketing and trading segment gross margin:	 	 	 	 	 	 	 	 	
 	Lower mark-to-market gains for future delivery due to lower market liquidity and deteriorating counterparty credit	 	 	(59	)	 	 	(35	)	
 	Lower realized margins on wholesale sales primarily due to lower unit margins, partially offset by higher volumes	 	 	(32	)	 	 	(19	)	
 	Higher margin related to structured contracts originated in prior years	 	 	13	 	 	 	7	 	
 	Decrease in generation sales other than Native Load primarily due to lower unit margins partially offset by higher sales volumes, including sales from new power plants in service	 	 	(7	)	 	 	(4	)	
 	 	 	 		 	 	 		 	
 	 	Net decrease in marketing and trading segment gross margin	 	 	(85	)	 	 	(51	)	
 	 	 		 	 	 		 	
 	Net decrease in regulated electricity and marketing and trading segments’ gross margins	 	 	(137	)	 	 	(82	)	
Higher income primarily related to NAC losses recognized in 2002	 	 	66	 	 	 	40	 	
Higher real estate segment contribution primarily due to higher asset, land and home sales	 	 	58	 	 	 	36	 	
Operations and maintenance expense decreases (increases):	 	 	 	 	 	 	 	 	
 	 	Write-off of Redhawk Units 3 and 4 in 2002	 	 	47	 	 	 	28	 	
 	 	Severance costs recorded in 2002	 	 	36	 	 	 	21	 	
 	 	Increased pension and other benefit costs	 	 	(28	)	 	 	(17	)	
 	 	Costs for new power plants in service	 	 	(20	)	 	 	(12	)	
 	 	Net other items	 	 	1	 	 	 	1	 	
Higher interest expense and lower capitalized interest primarily related to new power plants in service	 	 	(26	)	 	 	(16	)	
Depreciation and amortization decreases (increases):	 	 	 	 	 	 	 	 	
 	 	New power plants in service	 	 	(19	)	 	 	(11	)	
 	 	Increased delivery and other assets	 	 	(24	)	 	 	(14	)	
 	 	Decreased regulatory asset amortization	 	 	29	 	 	 	17	 	
APS’ return to the AFUDC method of capitalizing construction finance costs	 	 	8	 	 	 	11	 	
Miscellaneous items, net	 	 	7	 	 	 	7	 	
Tax credits and favorable income tax adjustments related to prior years resolved in 2003	 	 	—	 	 	 	17	 	
 	 	 	 		 	 	 		 	
 	 	Net (decrease)/increase in income from continuing operations	 	$	(2	)	 	 	26	 	
 	 	 		 	 	 	 	 	
Increase due to 2002 cumulative effect of a change in accounting for trading activities – net of income taxes	 	 	 	 	 	 	66	 	
 	 	 	 	 	 	 		 	
 	 	Net increase in net income	 	 	 	 	 	$	92	 	
 	 	 	 	 	 	 		 	
33 

 

     The increase in operating and interest costs related to new power plants placed in service by Pinnacle West Energy, net of purchased power savings and increased gross margin from generation sales other than Native Load, totaled approximately $30 million after income taxes in the year ended December 31, 2003 compared with the prior-year period.
      Regulated Electricity Segment Revenues
     Regulated electricity segment revenues were $88 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:

 	•	 	an $85 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;	
 		
 	•	 	a $21 million increase in retail revenues related to weather;	
 		
 	•	 	a $6 million increase related to traditional wholesale sales as a result of higher prices and higher sales volumes;	
 		
 	•	 	a $27 million decrease in retail revenues related to two reductions in retail electricity prices; and	
 		
 	•	 	a $3 million net increase due to miscellaneous factors.	
      Marketing and Trading Segment Revenues
     Marketing and trading segment revenues were $105 million higher in the year ended December 31, 2003 compared with the prior year, primarily as a result of:

 	•	 	$74 million of higher revenues related to the adoption of EITF 02-3 in the fourth quarter of 2002, primarily due to structured contracts that were reported gross in the current period and net in most of the prior period;	
 		
 	•	 	a $69 million increase from higher competitive retail sales in California by APS Energy Services;	
 		
 	•	 	a $38 million increase from generation sales other than Native Load primarily due to higher prices and sales volumes, including sales from new power plants in service;	
 		
 	•	 	$59 million in lower mark-to-market gains for future-period deliveries primarily as a result of lower market liquidity and lower price volatility; and	
 		
 	•	 	$17 million of lower realized wholesale revenues primarily due to lower unit margins on trading activities that are reported on a net basis.	
34 

 

      Real Estate Segment Revenues
     Real estate segment revenues were $161 million higher in the year ended December 31, 2003 compared with the prior year primarily as a result of increased asset, land and home sales related to SunCor’s effort to accelerate asset sales.
      Other Revenues
     Other revenues were $24 million higher in the year ended December 31, 2003 compared with the prior year primarily due to our consolidation of NAC’s financial statements beginning in the third quarter of 2002, partially offset by decreased sales activity at NAC.
      2002 Compared with 2001
     Our consolidated net income for the year ended December 31, 2002 was $149 million compared with $312 million for the prior year. We recognized a $66 million after-tax charge in 2002 for the cumulative effect of a change in accounting for trading activities for the early adoption of EITF 02-3 on October 1, 2002 (see Note 18). In 2001, we recognized a $15 million after-tax charge for the cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133 (see Note 18). Net income for 2002 includes income from discontinued operations of $9 million after-tax related to our real estate segment (see Note 22). Excluding the accounting changes and discontinued operations, the $121 million decrease in the period-to-period comparison reflects the following changes in earnings by segment:

 	•	 	Regulated Electricity Segment - Income from continuing operations increased $18 million primarily due to lower replacement power costs for power plants outages, retail customer growth and higher average customer usage. These positive factors were partially offset by a write-off of Redhawk Units 3 and 4, higher operating costs primarily related to severance costs recorded in 2002, retail electricity price decreases, the effects of milder weather, and higher costs for purchased power and gas due to higher hedged gas and power prices.	
 		
 	•	 	Marketing and Trading Segment - Income from continuing operations decreased $113 million primarily due to lower liquidity and lower price volatility in the wholesale power markets in the western United States.	
 		
 	•	 	Other Segment - Net income decreased approximately $33 million, primarily due to 2002 losses related to our investment in NAC.	
 		
 	•	 	Real Estate Segment - Income from continuing operations increased by $7 million primarily due to increased asset, land and home sales.	
     Additional details on the major factors that increased (decreased) income from continuing operations and net income for the year ended December 31, 2002 compared with the prior year are contained in the following table (dollars in millions).
35 

 

 	 	 	 	Increase/(Decrease)	
 	 	 	 		
 	 	 	 	Pretax	 	After Tax	
 	 	 	 		 		
Regulated electricity segment gross margin:	 	 	 	 	 	 	 	 	
 	Lower replacement power costs for plant outages due to lower market prices and fewer unplanned outages	 	$	127	 	 	$	76	 	
 	Higher retail sales volumes due to customer growth and higher average usage, excluding weather effects	 	 	38	 	 	 	23	 	
 	2001 charges related to purchased power contracts with Enron and its affiliates	 	 	13	 	 	 	8	 	
 	Retail price reductions effective July 1, 2001 and July 1, 2002	 	 	(28	)	 	 	(17	)	
 	Effects of milder weather on retail sales	 	 	(27	)	 	 	(16	)	
 	Increased purchased power and fuel costs due to higher hedged gas and power prices, partially offset by improved hedge management, net of mark-to-market reversals	 	 	(9	)	 	 	(5	)	
 	Miscellaneous factors, net	 	 	(2	)	 	 	(2	)	
 	 	 	 		 	 	 		 	
 	 	Net increase in regulated electricity segment gross margin	 	 	112	 	 	 	67	 	
 	 	 	 		 	 	 		 	
Marketing and trading segment gross margin:	 	 	 	 	 	 	 	 	
 	Lower realized wholesale margins net of related mark-to-market reversals due to lower prices and volumes	 	 	(91	)	 	 	(55	)	
 	Lower mark-to-market gains for future delivery due to lower market liquidity and lower price volatility	 	 	(76	)	 	 	(45	)	
 	Decrease in generation sales other than Native Load due to lower market prices partially offset by higher sales volumes	 	 	(66	)	 	 	(40	)	
 	Higher competitive retail sales in California by APS Energy Services	 	 	32	 	 	 	19	 	
 	2001 write-off of prior period mark-to-market value related to trading with Enron and its affiliates	 	 	8	 	 	 	5	 	
 	Lower mark-to-market reversals due to the adoption of EITF 02-3	 	 	8	 	 	 	5	 	
 	 	 	 		 	 	 		 	
 	 	Net decrease in marketing and trading segment gross margin	 	 	(185	)	 	 	(111	)	
 	 	 	 		 	 	 		 	
Net decrease in regulated electricity and marketing and trading segments’ gross margins	 	 	(73	)	 	 	(44	)	
Lower other gross margin primarily related to NAC losses	 	 	(44	)	 	 	(26	)	
Higher operations and maintenance expense related to a $47 million write-off of Redhawk Units 3 and 4 and 2002 severance costs of approximately $36 million, partially offset by lower generation reliability costs	 	 	(54	)	 	 	(32	)	
Higher taxes other than income taxes	 	 	(7	)	 	 	(4	)	
Lower other income primarily due to a 2001 insurance recovery of environmental remediation costs	 	 	(12	)	 	 	(7	)	
Higher net interest expense primarily due to higher debt balances and lower capitalized interest	 	 	(16	)	 	 	(10	)	
Miscellaneous factors, net	 	 	4	 	 	 	2	 	
 	 	 	 		 	 	 		 	
 	 	Net decrease in income from continuing operations	 	$	(202	)	 	 	(121	)	
 	 	 		 	 	 	 	 	
Decrease due to 2002 cumulative effect of change in accounting for trading activities — net of income taxes	 	 	 	 	 	 	(66	)	
Increase due to 2001 cumulative effect of change in accounting for derivatives — net of income taxes	 	 	 	 	 	 	15	 	
Increase due to 2002 discontinued operations — net of income taxes	 	 	 	 	 	 	9	 	
 	 	 	 	 	 	 		 	
 	 	Net decrease in net income	 	 	 	 	 	$	(163	)	
 	 	 	 	 	 	 		 	
36 

 

      Regulated Electricity Segment Revenues
     Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $94 million lower in the year ended December 31, 2002, compared with the prior year as a result of:

 	•	 	a $64 million decrease in revenues related to traditional wholesale sales as a result of lower sales volumes and lower prices;	
 		
 	•	 	a $60 million decrease in retail revenues related to milder weather;	
 		
 	•	 	a $69 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects;	
 		
 	•	 	a $28 million decrease in retail revenues related to reductions in retail electricity prices; and	
 		
 	•	 	an $11 million decrease due to other miscellaneous factors.	
Marketing and Trading Segment Revenues
     Marketing and trading segment revenues were $183 million lower in the year ended December 31, 2002, compared with the prior year as a result of:

 	•	 	a $98 million decrease in revenues from generation sales other than Native Load primarily due to lower market prices partially offset by higher sales volumes;	
 		
 	•	 	$131 million of lower realized wholesale revenues net of related mark-to-market reversals primarily due to lower prices partially offset by higher volumes;	
 		
 	•	 	a $105 million increase in revenues from higher competitive retail sales in California by APS Energy Services;	
 		
 	•	 	an $8 million increase in revenues due to the absence of a 2001 write-off of prior period mark-to-market value related to trading with Enron and its affiliates;	
 		
 	•	 	$8 million of higher revenues related to the adoption of EITF 02-3; and	
 		
 	•	 	$75 million of lower mark-to-market gains for future delivery primarily as a result of lower market liquidity and lower price volatility, resulting in lower volumes.	
      Real Estate Segment Revenues
     Real Estate segment revenues were $32 million higher in the year ended December 31, 2002 compared with the prior year primarily as a result of increased land, asset and home sales.
37 

 

Other Revenues
     Other revenues were $50 million higher in the year ended December 31, 2002 compared with the prior year primarily due to the consolidation of NAC’s financial statements beginning in the third quarter of 2002. 
LIQUIDITY AND CAPITAL RESOURCES
Capital Needs and Resources
      Capital Expenditure Requirements
     The following table summarizes the actual capital expenditures for the year ended December 31, 2003 and estimated capital expenditures for the next three years. 
CAPITAL EXPENDITURES
(dollars in millions)

 	 	 	 	Actual	 	Estimated	
 	 	 	 		 		
 	 	 	 	2003	 	2004	 	2005	 	2006	
 	 	 	 		 		 		 		
APS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Delivery	 	$	288	 	 	$	309	 	 	$	390	 	 	$	453	 	
 	Generation (a)	 	 	136	 	 	 	107	 	 	 	160	 	 	 	200	 	
 	Other	 	 	5	 	 	 	10	 	 	 	12	 	 	 	2	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	 	Subtotal	 	 	429	 	 	 	426	 	 	 	562	 	 	 	655	 	
Pinnacle West Energy (a) (b)	 	 	250	 	 	 	61	 	 	 	24	 	 	 	4	 	
SunCor (c)	 	 	72	 	 	 	83	 	 	 	27	 	 	 	17	 	
Other (d)	 	 	16	 	 	 	11	 	 	 	18	 	 	 	16	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total	 	$	767	 	 	$	581	 	 	$	631	 	 	$	692	 	

(a)	 	As discussed in Note 3 under “APS General Rate Case and Retail Rate Adjustment Mechanisms,” as part of its 2003 general rate case, APS requested rate base treatment of the PWEC Dedicated Assets. Pinnacle West Energy actual capital expenditures related to PWEC Dedicated Assets were $49 million for 2003 and are estimated to be $15 million in 2004, $21 million in 2005 and $4 million in 2006.	
 		
(b)	 	See “Capital Needs and Resources by Company — Pinnacle West Energy” below for further discussion of Pinnacle West Energy’s generation construction program. These amounts do not include an expected reimbursement by SNWA of about $100 million (plus capitalized interest), based upon SNWA’s agreement to purchase a 25% interest in the Silverhawk project upon completion in 2004.	
 		
(c)	 	Consists primarily of capital expenditures for land development and retail and office building construction reflected in “Real estate investments” on the Consolidated Statements of Cash Flows.	
 		
(d)	 	Primarily related to the parent company and APS Energy Services.	
          Delivery capital expenditures are comprised of T&D infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs.
38 

 

Examples of the types of projects included in the forecast include T&D lines and substations, line extensions to new residential and commercial developments and upgrades to customer information systems. APS completed the Southwest Valley transmission project in 2003 at a cost of approximately $70 million. Major transmission projects are driven by strong regional customer growth. APS will begin major projects each year for the next several years, and expects to spend about $200 million on major transmission projects during the 2004 to 2006 time frame. These amounts are included in “APS-Delivery” in the table above. Completion of these projects will stretch from 2005 through at least 2008.
     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants and the replacement of Palo Verde steam generators. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Generation also includes nuclear fuel expenditures of approximately $30 million annually for 2004 to 2006.
     Replacement of the steam generators in Palo Verde Unit 2 was completed during the fall outage of 2003 at a cost to APS of approximately $70 million. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. These generators will be installed in Unit 1 (scheduled completion in 2005) and Unit 3 (scheduled completion in 2007). Our portion of steam generator expenditures for Units 1 and 3 is approximately $140 million, which will be spent through 2008. In 2004 through 2006, approximately $90 million of the Unit 1 and Unit 3 costs are included in the generation capital expenditures table above and will be funded with internally-generated cash or external financings. 
      Contractual Obligations
     The following table summarizes contractual requirements as of December 31, 2003 (dollars in millions):

 	 	 	 	 	 	 	2005-	 	2007-	 	There-	 	 	 	 	
 	 	 	2004	 	2006	 	2008	 	after	 	Total	
 	 	 		 		 		 		 		
Long-term debt payments, including interest: (a)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	APS	 	$	342	 	 	$	699	 	 	$	192	 	 	$	2,567	 	 	$	3,800	 	
 	Pinnacle West	 	 	242	 	 	 	497	 	 	 	—	 	 	 	—	 	 	 	739	 	
 	SunCor	 	 	4	 	 	 	12	 	 	 	5	 	 	 	—	 	 	 	21	 	
 	El Dorado	 	 	1	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	2	 	
Short-term debt payments, including interest (b)	 	 	88	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	88	 	
Capital lease payments	 	 	3	 	 	 	5	 	 	 	2	 	 	 	3	 	 	 	13	 	
Operating lease payments	 	 	73	 	 	 	138	 	 	 	132	 	 	 	421	 	 	 	764	 	
Minimum pension funding requirement (c)	 	 	100	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	100	 	
Purchase power and fuel commitments (d)	 	 	209	 	 	 	134	 	 	 	102	 	 	 	461	 	 	 	906	 	
Purchase obligations (e)	 	 	85	 	 	 	22	 	 	 	5	 	 	 	68	 	 	 	180	 	
Nuclear decommissioning funding requirements	 	 	11	 	 	 	22	 	 	 	22	 	 	 	158	 	 	 	213	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total contractual commitments	 	$	1,158	 	 	$	1,530	 	 	$	460	 	 	$	3,678	 	 	$	6,826	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
39 

 

(a)	 	The long-term debt matures at various dates through fiscal year 2034 and bears interest principally at fixed rates. Interest on variable long-term debt is set at the December 31, 2003 rates.	
 		
(b)	 	The short-term debt matures within 12 months. The weighted-average interest rate of the short-term debt is 4.26% at December 31, 2003.	
 		
(c)	 	If currently pending legislation is enacted, our required pension contribution in 2004 would decrease to the $25 to $50 million range. Future pension contributions are not determinable for time periods after 2004.	
 		
(d)	 	Our purchase power and fuel commitments include purchases of coal, electricity, natural gas and nuclear fuel (see Note 11).	
 		
(e)	 	These contractual obligations include commitments for capital expenditures and other obligations.	
      Off-Balance Sheet Arrangements
     In 2003, we adopted FIN No. 46R, “Consolidation of Variable Interest Entities,” as it applies to special-purpose entities. FIN No. 46R requires that we consolidate a VIE if we have a majority of the risk of loss from the VIE’s activities or we are entitled to receive a majority of the VIE’s residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. In 1986, APS entered into agreements with three separate SPE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. See Note 9 for further information about the sale leaseback transactions. Based on our assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs. Certain provisions of FIN No. 46R have a future effective date. We do not expect these provisions to have a material impact on our financial statements.
     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, 2003, APS would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.
      Guarantees and Letters of Credit
     We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Consolidated Balance Sheets with respect to these obligations. See Note 21 for additional information regarding guarantees and letters of credit.
      Credit Ratings
     The ratings of securities of Pinnacle West and APS as of March 11, 2004 are shown below and are considered to be “investment-grade” ratings. 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
40 

 

price of Pinnacle West’s or APS’ securities and serve to increase those companies’ cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 18). 

 	 	Moody's	 	Standard & Poor's	
 	 		 		
Pinnacle West	 	 	 	 	
Senior unsecured
Commercial paper
Outlook

APS	 	Baa2
P-2
Negative	 	BBB-
A-2
Stable	
Senior secured
Senior unsecured
Secured lease
   obligation bonds
Commercial paper
Outlook	 	A3
Baa1

Baa2
P-2
Negative	 	A-
BBB

BBB
A-2
Stable	
      Debt Provisions
     Pinnacle West’s and APS’ debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet the covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65% for each of the Company and APS individually. At December 31, 2003, the ratio was approximately 54% for Pinnacle West. At December 31, 2003, the ratio was approximately 53% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for each of the Company and APS. Based on 2003 results, the coverages were approximately 4 times for the Company, 4 times for the APS bank financing agreements and 15 times for the APS mortgage indenture. 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.
     Neither Pinnacle West’s nor APS’ financing agreements contain “ratings triggers” that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.
     All of Pinnacle West’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under other 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 other agreements. Pinnacle West’s and APS’ credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in financial condition or financial prospects.
41 

 

Capital Needs and Resources by Company
      Pinnacle West (Parent Company)
     Our primary cash needs are for dividends to our shareholders; interest payments and optional and mandatory repayments of principal on our long-term debt (see the table above for our contractual requirements, including our debt repayment obligations, but excluding optional repayments) and equity infusions into our subsidiaries, primarily Pinnacle West Energy. On October 22, 2003, our board of directors increased the common stock dividend to an indicated annual rate of $1.80 per share from $1.70 per share, effective with the December 1, 2003 dividend payment. The level of our common dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
     Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. For the years 2001 through 2003, total dividends from APS were $510 million and total distributions from SunCor were $121 million. For the year ended December 31, 2003, dividends from APS were approximately $170 million and distributions from SunCor were approximately $108 million. We expect SunCor to make cash distributions to the parent company of $80 to $100 million annually in 2004 and 2005 due to anticipated accelerated asset sales activity. As discussed in Note 3 under “ACC Financing Orders,” APS must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce its common equity below that threshold. As defined in the Financing Order, common equity ratio is common equity divided by common equity plus long-term debt, including current maturities of long-term debt. At December 31, 2003, APS’ common equity ratio was approximately 46%.
     On May 12, 2003, APS issued $500 million of debt as follows: $300 million aggregate principal amount of its 4.65% Notes due 2015 and $200 million aggregate principal amount of its 5.625% Notes due 2033. Also on May 12, 2003, APS made a $500 million loan to Pinnacle West Energy, and Pinnacle West Energy distributed the net proceeds of that loan to us to fund our repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated Assets. See “ACC Financing Order” in Note 3 for additional information. With Pinnacle West Energy’s distribution to us on May 12, 2003, we repaid the outstanding balance ($167 million) under a credit facility. We used a portion of the remaining proceeds to redeem our $250 million Floating Rate Notes due 2003 on June 2, 2003 and to repay other short-term debt. On November 12, 2003, we issued $165 million of our Floating Rate Senior Notes due 2005.
     At December 31, 2003, the parent company’s outstanding long-term debt, including current maturities, was $681 million. At December 31, 2003, we had unused credit commitments from various banks totaling $275 million, which were available to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2003, we had no commercial paper outstanding and no short-term borrowings. We ended 2003 in an invested position.
     Pinnacle West sponsors a pension plan that covers employees of Pinnacle West and our subsidiaries. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. We elected to contribute cash to our pension plan in each of the last five years; our minimum required contributions during each of
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those years was zero. Specifically, we contributed $73 million for 2002 ($46 million of which was contributed in June 2003); $24 million for 2001; $44 million for 2000 ($20 million of which was contributed in 2001); and $25 million for 1999. APS and other subsidiaries fund their share of the pension contribution, of which APS represents approximately 89% of the total funding amounts described above. The assets in the plan are mostly domestic common stocks, bonds and real estate. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. Under current law, we are required to contribute approximately $100 million to our pension plans in 2004 and expect to contribute approximately $50 million to our other postretirement benefit plan in 2004. If currently pending legislation is enacted, our required pension contribution in 2004 would decrease to the $25 to $50 million range.
      APS
     APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See “Pinnacle West (Parent Company)” above and Note 3 for discussion of the $500 million financing arrangement between APS and Pinnacle West Energy approved by the ACC in 2003 and discussion of a $125 million financing arrangement between APS and Pinnacle West.
     APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid for its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.
     On April 7, 2003, APS redeemed approximately $33 million of its First Mortgage Bonds, 8% Series due 2025, and on August 1, 2003, APS redeemed approximately $54 million of its First Mortgage Bonds, 7.25% Series due 2023.
     On February 15, 2004, $125 million of APS 5.875% Notes due 2004 were redeemed at maturity and on March 1, 2004, $80 million of APS’ First Mortgage Bonds, 6.625% Series due 2004 were redeemed at maturity. APS used cash from operations and short-term debt to redeem the maturing debt.
     APS’ outstanding debt was approximately $2.6 billion at December 31, 2003. At December 31, 2003, APS had unused credit commitments from various banks totaling about $250 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At December 31, 2003, APS had no outstanding commercial paper or bank borrowings. APS ended 2003 in an invested position.
     Although provisions in APS’ first mortgage bond indenture, articles of incorporation and ACC financing orders establish maximum amounts of additional first mortgage bonds, debt and preferred stock that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.
      Pinnacle West Energy
     The costs of Pinnacle West Energy’s construction of 2,360 MW of generating capacity from 2000 through 2004 are expected to be about $1.4 billion, of which $1.35 billion has been incurred
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through December 31, 2003. This does not reflect the proceeds from an anticipated sale in 2004 to SNWA of a 25% interest in the 570 MW Silverhawk Combined Cycle Plant 20 miles north of Las Vegas, Nevada, which would equal about $100 million (plus capitalized interest) of Pinnacle West Energy’s cumulative capital expenditures in the project. SNWA has agreed to purchase a 25% interest in the project upon completion. Such purchase is subject to an appropriation of funds by SNWA. Pinnacle West Energy’s capital requirements are currently funded through capital infusions from Pinnacle West, which finances those infusions through debt and equity financings and internally-generated cash. See the capital expenditures table above for actual capital expenditures in 2003 and projected capital expenditures for the next three years.
     See Note 3 and “Pinnacle West (Parent Company)” above for a discussion of the $500 million financing arrangement between APS and Pinnacle West Energy authorized by the ACC pursuant to the Financing Order.
      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 in 2003 and projected capital expenditures for the next three years. SunCor expects to fund its capital requirements with cash from operations and external financings.
     In 2003, SunCor acquired or issued $10 million in long-term debt, and redeemed, refinanced or repaid $1 million in long-term debt (see Note 6).
     SunCor’s outstanding long and short-term debt was approximately $104 million as of December 31, 2003. SunCor’s total short-term debt was $86 million at December 31, 2003. SunCor had a $120 million line of credit, under which $50 million of short-term borrowings were outstanding at December 31, 2003. SunCor’s long-term debt, including current maturities, totaled $18 million at December 31, 2003.
     We expect SunCor to make cash distributions to the parent company of $80 to $100 million annually in 2004 and 2005 due to anticipated accelerated asset sales activity.
     El Dorado funded its cash requirements during the past three years, primarily for NAC in 2002, with cash infused by the parent company and with cash from operations. El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.
     APS Energy Services’ cash requirements during the past three years were funded with cash infusions from the parent company and with cash from operations. See the capital expenditures table above regarding APS Energy Services’ actual capital expenditures for 2003 and projected capital expenditures for the next three years.
CRITICAL ACCOUNTING POLICIES
     In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,
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expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
Regulatory Accounting
     Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $165 million of regulatory assets on the Consolidated Balance Sheets at December 31, 2003. See Notes 1 and 3 for more information about regulatory assets and APS’ general rate case.
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 2003 projected benefit obligation, our 2003 reported pension liability on the Consolidated Balance Sheets and our 2003 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on our Consolidated Statements of Income (dollars in millions): 

 	 	 	Increase/(Decrease)	
 	 	 		
 	 	 	Impact on	 	 	 	 	 	 	 	 	
 	 	 	Projected	 	Impact on	 	Impact on	
 	 	 	Benefit	 	Pension	 	Pension	
Actuarial Assumption (a)	 	Obligation	 	Liability	 	Expense	
	 		 		 		
Discount rate:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Increase 1%	 	$	(165	)	 	$	(123	)	 	$	(8	)	
 	Decrease 1%	 	 	189	 	 	 	139	 	 	 	6	 	
Expected long-term rate of return on plan assets:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Increase 1%	 	 	—	 	 	 	—	 	 	 	(3	)	
 	Decrease 1%	 	 	—	 	 	 	—	 	 	 	3	 	

(a)	 	Each fluctuation assumes that the other assumptions of the calculation are held constant.	
     The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the 2003 accumulated other postretirement benefit obligation and our 2003
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reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on our Consolidated Statements of Income (dollars in millions): 

 	 	 	Increase/(Decrease)	
 	 	 		
 	 	 	Impact on Accumulated	 	Impact on Other	
 	 	 	Postretirement Benefit	 	Postretirement	
Actuarial Assumption (a)	 	Obligation	 	Benefit Expense	
	 		 		
Discount rate:	 	 	 	 	 	 	 	 	
 	Increase 1%	 	$	(81	)	 	$	(5	)	
 	Decrease 1%	 	 	96	 	 	 	5	 	
Health care cost trend rate (b):	 	 	 	 	 	 	 	 	
 	Increase 1%	 	 	95	 	 	 	7	 	
 	Decrease 1%	 	 	(76	)	 	 	(5	)	
Expected long-term rate of return on plan assets — pretax:	 	 	 	 	 	 	 	 	
 	Increase 1%	 	 	—	 	 	 	(1	)	
 	Decrease 1%	 	 	—	 	 	 	1	 	

(a)	 	Each fluctuation assumes that the other assumptions of the calculation are held constant.	
 		
(b)	 	This assumes a 1% change in the initial and ultimate health care cost trend rate.	
     See Note 8 for further details about our pension and other postretirement benefit plans.
Derivative Accounting
     Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in common stock equity (as a component of other comprehensive income (loss)). See “Market Risks - Commodity Price Risk” below for quantitative analysis. See Note 18 for a further discussion on derivative and energy trading accounting.
Mark-to-Market Accounting
     The market value of our derivative contracts is not always readily determinable. In some cases, we use models and other valuation techniques to determine fair value. The use of these models and valuation techniques sometimes requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. Our marketing and trading portfolio consists of structured activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. See “Market Risks - Commodity Price Risk” below for quantitative analysis. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative and energy trading accounting.
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OTHER ACCOUNTING MATTERS
Accounting for Derivative and Trading Activities
     We adopted EITF 03-11 effective October 1, 2003. EITF 03-11 provides guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. 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 netted these book-outs, reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows.
     We adopted EITF 02-3 in the fourth quarter of 2002. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Contracts that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
     In 2001, we adopted SFAS No. 133 and recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a component of other comprehensive income), both as a cumulative effect of a change in accounting for derivatives.
     See Notes 1 and 18 for further information on accounting for derivatives.
Asset Retirement Obligations
     On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” The standard requires the fair value of asset retirement obligations to be recorded as a liability, along with an offsetting plant asset, when the obligation is incurred. 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 1 for more information regarding our previous accounting for removal costs.)
     We determined that we have asset retirement obligations for our nuclear facilities (nuclear decommissioning) and certain other generation, transmission and distribution assets. On January 1, 2003, we recorded a liability of $219 million for our asset retirement obligations including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, we recorded a regulatory liability of $40 million for our asset retirement obligations related to our regulated utility. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of
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     Regulation” (see Note 1) and SFAS No. 143 (see Note 12). Adopting SFAS No. 143 had no impact on our Consolidated Statements of Income or our Consolidated Statements of Cash Flow.
Variable Interest Entities
     See “Liquidity and Capital Resources - Off-Balance Sheet Arrangements” and Note 20 for discussion of VIEs.
FACTORS AFFECTING OUR FINANCIAL OUTLOOK
APS General Rate Case
     We believe APS’ general rate case pending before the ACC is the key issue affecting our outlook. As discussed in greater detail in Note 3, in this rate case APS has requested, among other things, a 9.8% retail rate increase (approximately $175 million annually), rate treatment for the PWEC Dedicated Assets and the recovery of $234 million written off by APS as part of the 1999 Settlement Agreement. In its filed testimony, the ACC staff recommended, among other things, that the ACC decrease APS’ rates by approximately 8% (approximately $143 million annually), not allow the PWEC Dedicated Assets to be included in APS’ rate base, and not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement. The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings and access to capital markets. We believe that APS’ rate case requests are supported by, among other things, APS’ demonstrated need for the PWEC Dedicated Assets; APS’ need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in APS’ high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard. The hearing on the rate case is scheduled to begin on May 25, 2004. We believe the ACC will be able to make a decision by the end of 2004.
Wholesale Power Market Conditions
     The marketing and trading division focuses primarily on managing APS’ purchased power and fuel risks in connection with its costs of serving retail customer demand. We moved this division to APS in early 2003 for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting APS’ transfer of generating assets to Pinnacle West Energy. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits. Our future earnings will be affected by the strength or weakness of the wholesale power market. The market has suffered a substantial reduction in overall liquidity because there are fewer creditworthy counterparties and because several key participants have exited the market or scaled back their activities. Based on the erosion in the market and on the market outlook, we currently expect contributions from our trading activities to be negligible for 2004, and approximately $10 million (pretax) annually thereafter.
Generation Construction Program
     See “Liquidity and Capital Resources - Pinnacle West Energy” for information regarding Pinnacle West Energy’s generation construction program, which is nearing completion. The
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     additional generation is expected to increase revenues, fuel expenses, operating expenses and financing costs.
      Factors Affecting Operating Revenues
      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. These revenues are expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity prices and variations in weather from period to period. Competitive sales of energy and energy-related products and services are made by APS Energy Services in western states that have opened to competitive supply.
      Customer Growth Customer growth in APS’ service territory averaged about 3.4% a year for the three years 2001 through 2003; we currently expect customer growth to average about 3.5% per year from 2004 to 2006. We currently estimate that total retail electricity sales in kilowatt-hours will grow 4.9% on average, from 2004 through 2006, before the retail effects of weather variations. The customer and sales growth referred to in this paragraph applies to Native Load customers. Customer growth for the year ended December 31, 2003 compared with the prior year period was 3.3%.
      Retail Rate Changes As part of the 1999 Settlement Agreement, APS agreed to a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. The final price reduction was implemented July 1, 2003. See “1999 Settlement Agreement” in Note 3 for further information. In addition, the Company has requested a 9.8% retail rate increase to be effective July 1, 2004. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” in Note 3 for further information.
      Other Factors Affecting Future Financial Results
      Purchased Power and Fuel Costs Purchased power and fuel costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, prevailing market prices, new generating plants being placed in service and our hedging program for managing such costs. See “Natural Gas Supply” in Note 11 for more information on fuel costs.
      Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.
      Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to existing utility plant and other property, changes in regulatory asset amortization and our generation construction program. West Phoenix Unit 4 was placed in service in June 2001. Redhawk Units 1 and 2 and the new Saguaro Unit 3 began commercial operations in July 2002. West Phoenix Unit 5 was placed in service in July 2003 and Silverhawk is expected to be in service in mid-2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):
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1999	 	2000	 	2001	 	2002	 	2003	 	2004	 	Total	
	 		 		 		 		 		 		
$	164	 	 	$	158	 	 	$	145	 	 	$	115	 	 	$	86	 	 	$	18	 	 	$	686	 	
      Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.3% of assessed value for 2003 and 9.7% for 2002. We expect property taxes to increase primarily due to our generation construction program, as the plants phase-in to the property tax base over a five-year period, and our additions to existing 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 in the next several years are expected to be our capital requirements and our internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation. As noted above, we placed new power plants in commercial operation in 2001, 2002 and 2003 and we expect to bring an additional plant on-line in 2004. Interest expense is also affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company’s future liquidity needs. In addition, see Note 1 for a discussion of AFUDC.
      Retail Competition The regulatory developments and legal challenges to the Rules discussed in Note 3 have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
      Subsidiaries In the case of SunCor, efforts to accelerate asset sales activities in 2003 were successful. A portion of these sales have been, and additional amounts may be required to be, reported as discontinued operations on our Consolidated Statements of Income. The annual earnings contribution from SunCor was $56 million after tax in 2003. See Note 22 for further discussion. We anticipate SunCor’s annual earnings contributions in 2004 and 2005 will be in the $30-$40 million range after tax.
     The annual earnings contribution from APS Energy Services is expected to be positive over the next several years due primarily to a number of retail electricity contracts in California. APS Energy Services had after tax earnings of $16 million in 2003.
     We expect SunCor and APS Energy Services to have combined earnings of approximately $10 million per year after tax beyond 2005.
     El Dorado’s historical results are not necessarily indicative of future performance for El Dorado. In addition, we do not currently expect material losses related to NAC in the future.
      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.
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Market Risks
     Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by the nuclear decommissioning trust fund and our pension plans.
      Interest Rate and Equity Risk
     Our major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund (see Note 12). Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. On January 29, 2004, we entered into a fixed-for-floating interest rate swap transaction (see Note 6 for additional information). The nuclear decommissioning fund also has risk associated with changing market values of equity investments. Nuclear decommissioning costs are recovered in regulated electricity prices.
     The table below presents 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, 2003. The interest rates presented in the tables below represent the weighted-average interest rates for the year ended December 31, 2003 (dollars in thousands). 

 	 	 	 	 	 	 	 	 	 	Variable-Rate	 	Fixed-Rate	
 	 	Short-Term Debt	 	Long-Term Debt	 	Long-Term Debt	
 	 		 		 		
 	 	Interest	 	 	 	 	 	Interest	 	 	 	 	 	Interest	 	 	 	 	
 	 	Rates	 	Amount	 	Rates	 	Amount	 	Rates	 	Amount	
 	 		 		 		 		 		 		
2004	 	 	4.26	%	 	$	86,081	 	 	 	2.68	%	 	$	1,209	 	 	 	5.33	%	 	$	424,271	 	
2005	 	 	—	 	 	 	—	 	 	 	1.99	%	 	 	166,269	 	 	 	7.27	%	 	 	403,204	 	
2006	 	 	—	 	 	 	—	 	 	 	6.55	%	 	 	2,937	 	 	 	6.49	%	 	 	391,585	 	
2007	 	 	—	 	 	 	—	 	 	 	4.99	%	 	 	373	 	 	 	5.54	%	 	 	1,256	 	
2008	 	 	—	 	 	 	—	 	 	 	5.19	%	 	 	5,269	 	 	 	5.55	%	 	 	1,098	 	
Years thereafter	 	 	—	 	 	 	—	 	 	 	1.51	%	 	 	386,860	 	 	 	5.83	%	 	 	1,547,775	 	
 	 	 	 	 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	 	 		 	
Total	 	 	 	 	 	$	86,081	 	 	 	 	 	 	$	562,917	 	 	 	 	 	 	$	2,769,189	 	
 	 	 	 	 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	 	 		 	
Fair value	 	 	 	 	 	$	86,081	 	 	 	 	 	 	$	563,047	 	 	 	 	 	 	$	2,913,190	 	
 	 	 	 	 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	 	 		 	
      Commodity Price Risk
     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk
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parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
     The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:

 	•	 	Regulated Electricity - non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and	
 		
 	•	 	Marketing and Trading - non-trading and trading derivative instruments of our competitive business segment.	
     The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions in 2003 and 2002 (dollars in millions): 

 	 	Regulated	 	Marketing and	
 	 	Electricity	 	Trading	
 	 		 		
Mark-to-market of net positions at December 31, 2002	 	$	(49	)	 	$	57	 	
Change in mark-to-market losses for future period deliveries	 	 	(5	)	 	 	(7	)	
Changes in cash flow hedges recorded in OCI	 	 	41	 	 	 	44	 	
Ineffective portion of changes in fair value recorded in earnings	 	 	8	 	 	 	—	 	
Mark-to-market losses/(gains) realized during the year	 	 	5	 	 	 	(25	)	
 	 	 		 	 	 		 	
Mark-to-market of net positions at December 31, 2003	 	$	—	 	 	$	69	 	
 	 	 		 	 	 		 	
52 

 

 	 	Regulated	 	Marketing and	
 	 	Electricity	 	Trading	
 	 		 		
Mark-to-market of net positions at December 31, 2001	 	$	(107	)	 	$	138	 	
Cumulative effect adjustment due to adoption of EITF 02-3	 	 	—	 	 	 	(109	)	
Change in mark-to-market (losses)/gains for future period deliveries	 	 	(13	)	 	 	52	 	
Changes in cash flow hedges recorded in OCI	 	 	57	 	 	 	16	 	
Ineffective portion of changes in fair value recorded in earnings	 	 	11	 	 	 	—	 	
Mark-to-market losses/(gains) realized during the year	 	 	3	 	 	 	(43	)	
Change in valuation techniques	 	 	—	 	 	 	3	 	
 	 	 		 	 	 		 	
Mark-to-market of net positions at December 31, 2002	 	$	(49	)	 	$	57	 	
 	 	 		 	 	 		 	
     The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at December 31, 2003 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Mark-to-Market Accounting,” for more discussion on our valuation methods. 
Regulated Electricity

 	 	 	 	 	 	 	 	 	 	
Years	 	Total
fair	
Source of Fair Value	 	2004	 	2005	 	thereafter	 	value	
	 		 		 		 		
Prices actively quoted	 	$	(4	)	 	$	3	 	 	$	—	 	 	$	(1	)	
Prices provided by other external sources	 	 	2	 	 	 	—	 	 	 	—	 	 	 	2	 	
Prices based on models and other valuation methods	 	 	(1	)	 	 	—	 	 	 	—	 	 	 	(1	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Total by maturity	 	$	(3	)	 	$	3	 	 	$	—	 	 	$	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Marketing and Trading

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Total	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Years	 	fair	
Source of Fair Value	 	2004	 	2005	 	2006	 	2007	 	2008	 	thereafter	 	value	
	 		 		 		 		 		 		 		
Prices actively quoted	 	$	(18	)	 	$	—	 	 	$	—	 	 	$	10	 	 	$	10	 	 	$	—	 	 	$	2	 	
Prices provided by other external sources	 	 	22	 	 	 	23	 	 	 	25	 	 	 	20	 	 	 	8	 	 	 	(2	)	 	 	96	 	
Prices based on models and other valuation methods	 	 	12	 	 	 	(7	)	 	 	(13	)	 	 	(14	)	 	 	(6	)	 	 	(1	)	 	 	(29	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total by maturity	 	$	16	 	 	$	16	 	 	$	12	 	 	$	16	 	 	$	12	 	 	$	(3	)	 	$	69	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
53 

 

     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 the Consolidated Balance Sheets at December 31, 2003 (dollars in millions). 

 	 	 	December 31, 2003	
 	 	 	Gain (Loss)	
 	 	 		
 	 	 	Price Up	 	Price Down	
Commodity	 	10%	 	10%	
	 		 		
Mark-to-market changes reported in earnings (a):	 	 	 	 	 	 	 	 	
 	Electricity	 	$	(2	)	 	$	2	 	
 	Natural gas	 	 	(1	)	 	 	1	 	
 	Other	 	 	1	 	 	 	—	 	
Mark-to-market changes reported in OCI (b):	 	 	 	 	 	 	 	 	
 	Electricity	 	 	36	 	 	 	(36	)	
 	Natural gas	 	 	30	 	 	 	(30	)	
 	 	 	 		 	 	 		 	
 	Total	 	$	64	 	 	$	(63	)	

 	(a)	 	These contracts are primarily structured sales activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.	
 		
 	(b)	 	These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.	
Credit Risk
     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including two counterparties for which a worst case exposure represents approximately 37% of our $237 million of risk management and trading assets as of December 31, 2003. See Note 1, “Mark-to-Market Accounting” for a discussion of our credit valuation adjustment policy. See Note 18 for further discussion of credit risk.
Risk Factors
     Exhibit 99.1, which is hereby incorporated by reference, contains a discussion of risk factors affecting the Company.
54 

 

Forward-Looking Statements
     This document contains forward-looking statements based on current expectations, and we assume no 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 “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 us. These factors include, but are not limited to:

 	•	 	state and federal regulatory and legislative decisions and actions, including the outcome of the rate case APS filed with the ACC on June 27, 2003 and the wholesale electric price mitigation plan adopted by the FERC;	
 		
 	•	 	the outcome of regulatory, legislative and judicial proceedings relating to the restructuring;	
 		
 	•	 	the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition;	
 		
 	•	 	market prices for electricity and natural gas;	
 		
 	•	 	power plant performance and outages;	
 		
 	•	 	weather variations affecting local and regional customer energy usage;	
 		
 	•	 	energy usage;	
 		
 	•	 	regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile purchased power and fuel costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;	
 		
 	•	 	the cost of debt and equity capital and access to capital markets;	
 		
 	•	 	our ability to compete successfully outside traditional regulated markets (including the wholesale market);	
 		
 	•	 	the performance of our marketing and trading activities due to volatile market liquidity and deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);	
 		
 	•	 	changes in accounting principles generally accepted in the United States of America;	
 		
 	•	 	the successful completion of our generation construction program;	
 		
 	•	 	regulatory issues associated with generation construction, such as permitting and licensing;	
 		
 	•	 	the performance of the stock market and the changing interest rate environment, which affect the amount of our required contributions to our pension plan and nuclear decommissioning trust funds, as well as our 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;	
 		
 	•	 	conservation programs; and	
 		
 	•	 	other uncertainties, all of which are difficult to predict and many of which are beyond our control.	
55 

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK 
     See “Factors Affecting Our Financial Outlook - Market Risks” in Item 7 for a discussion of quantitative and qualitative disclosures about market risk.
56 

 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULE

Management’s Report on Internal Control Over Financial Reporting	 	58	
Independent Accountants’ Report	 	59	
Independent Auditors’ Report	 	60	
Consolidated Statements of Income for 2003, 2002 and 2001	 	61	
Consolidated Balance Sheets as of December 31, 2003 and 2002	 	62	
Consolidated Statements of Cash Flows for 2003, 2002 and 2001	 	64	
Consolidated Statements of Changes in Common Stock Equity for 2003, 2002 and 2001	 	65	
Notes to Consolidated Financial Statements	 	66	
Financial Statement Schedule for 2003, 2002 and 2001 Schedule II — Valuation and Qualifying Accounts for 2003, 2002 and 2001	 	123	
See Note 13 for the selected quarterly financial data required to be presented in this Item.
57 

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
     Management at Pinnacle West has always understood and accepted responsibility for our financial statements and related disclosures and the effectiveness of internal control over financial reporting (“internal control”). Just as we do throughout all aspects of our business, we continuously strive to identify opportunities to enhance the effectiveness and efficiency of internal control.
     SEC rules implementing Section 404 of the Sarbanes-Oxley Act will require our 2004 Annual Report to contain a management’s report and an independent accountants’ report regarding the effectiveness of internal control. However, in this 2003 Annual Report, we chose to voluntarily include this report on internal control. As a basis for our report, we tested and evaluated the design, documentation, and operating effectiveness of internal control.
     In early March 2004, the PCAOB issued its auditing standard, which may require changes to the processes we utilize to test and evaluate the design, documentation, and operating effectiveness of internal control and may affect our future internal control disclosures. Based on our assessment as of December 31, 2003, we make the following assertion:

 	•	 	Management is responsible for establishing and maintaining effective internal control over financial reporting of Pinnacle West Capital Corporation and Subsidiaries (the “Company”). The internal control contains monitoring mechanisms, and actions are taken to correct deficiencies identified.	
 		
 	•	 	There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.	
 		
 	•	 	Management evaluated the Company’s internal control over financial reporting as of December 31, 2003. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2003.	
March 11, 2004
58 

 
INDEPENDENT ACCOUNTANTS’ REPORT
Board of Directors and Stockholders
Pinnacle West Capital Corporation
Phoenix, Arizona
We have examined the accompanying management’s assertion that Pinnacle West Capital Corporation and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2003, based on the 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 maintaining effective internal control over financial reporting. Our responsibility is to express an opinion on management’s assertion based on our examination.
Our examination was conducted in accordance with attestation standards established by the American Institute of Certified Public Accountants (“AICPA”) and, accordingly, included obtaining an understanding of the internal control over financial reporting, testing and evaluating the design and operating effectiveness of the internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our examination provides a reasonable basis for our opinion.
Because of inherent limitations in any internal control, misstatements due to error or fraud may occur and not be detected. Also, projections of any evaluation of the internal control over financial reporting to future periods are subject to the risk that the internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assertion that the Company maintained effective internal control over financial reporting as of December 31, 2003 is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
An examination of management’s assertion regarding the effectiveness of internal control under AICPA standards may not be the same in scope as an audit of internal control under the current proposed standards of the Public Company Accounting Oversight Board (the “PCAOB”) and, accordingly, may not necessarily result in the same conclusion or disclose all matters in internal control that might ultimately be noted in performing an audit under PCAOB standards when they are finally adopted. Accordingly, our examination of the accompanying Management’s Report on Internal Control Over Financial Reporting is not intended to comply with, and should not be relied upon for compliance with, the U.S. Securities and Exchange Commission rule relating to Section 404 or Section 103 of the Sarbanes-Oxley Act of 2002.
DELOITTE & TOUCHE LLP
Phoenix, Arizona
March 11, 2004
59 

 
INDEPENDENT AUDITORS’ REPORT
Board of Directors and Stockholders
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, 2003 and 2002 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, 2003. Our audits also included the financial statement schedule listed in the Index. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Pinnacle West Capital Corporation and subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, 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 consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 18 to the consolidated financial statements, in 2003 the Company changed its method of accounting for non-trading derivatives in order to comply with the provisions of Emerging Issues Task Force Issue No. 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 Issue No. 02-3.
As discussed in Note 18 to the consolidated financial statements, in 2002 the Company changed its method of accounting for trading activities in order to comply with the provisions of Emerging Issues Task Force Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.
As discussed in Note 18 to the consolidated financial statements, in 2001 the Company changed its method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities .
DELOITTE & TOUCHE LLP
Phoenix, Arizona
March 11, 2004
60 

 
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)

 	 	 	 	Year Ended December 31,	
 	 	 	 		
 	 	 	 	2003	 	2002	 	2001	
 	 	 	 		 		 		
OPERATING REVENUES	 	 	 	 	 	 	 	 	 	 	 	 	
 	Regulated electricity segment	 	$	1,978,075	 	 	$	1,890,391	 	 	$	1,984,305	 	
 	Marketing and trading segment	 	 	391,886	 	 	 	286,879	 	 	 	469,784	 	
 	Real estate segment	 	 	361,604	 	 	 	201,081	 	 	 	168,908	 	
 	Other revenues	 	 	86,287	 	 	 	61,937	 	 	 	11,771	 	
 	 	 	 		 	 	 		 	 	 		 	
 	 	Total	 	 	2,817,852	 	 	 	2,440,288	 	 	 	2,634,768	 	
 	 	 	 		 	 	 		 	 	 		 	
OPERATING EXPENSES	 	 	 	 	 	 	 	 	 	 	 	 	
 	Regulated electricity segment purchased power and fuel	 	 	517,320	 	 	 	376,911	 	 	 	583,080	 	
 	Marketing and trading segment purchased power and fuel	 	 	344,862	 	 	 	154,987	 	 	 	152,762	 	
 	Operations and maintenance	 	 	548,732	 	 	 	584,538	 	 	 	530,095	 	
 	Real estate operations segment	 	 	305,974	 	 	 	185,925	 	 	 	153,462	 	
 	Depreciation and amortization	 	 	438,143	 	 	 	424,082	 	 	 	427,903	 	
 	Taxes other than income taxes	 	 	110,270	 	 	 	107,952	 	 	 	101,068	 	
 	Other expenses	 	 	70,498	 	 	 	104,959	 	 	 	10,375	 	
 	 	 	 		 	 	 		 	 	 		 	
 	 	Total	 	 	2,335,799	 	 	 	1,939,354	 	 	 	1,958,745	 	
 	 	 	 		 	 	 		 	 	 		 	
OPERATING INCOME	 	 	482,053	 	 	 	500,934	 	 	 	676,023	 	
 	 	 	 		 	 	 		 	 	 		 	
OTHER	 	 	 	 	 	 	 	 	 	 	 	 	
 	Allowance for equity funds used during construction	 	 	14,240	 	 	 	—	 	 	 	—	 	
 	Other income	 	 	35,563	 	 	 	14,910	 	 	 	26,416	 	
 	Other expenses	 	 	(20,574	)	 	 	(33,655	)	 	 	(33,577	)	
 	 	 	 		 	 	 		 	 	 		 	
 	 	Total	 	 	29,229	 	 	 	(18,745	)	 	 	(7,161	)	
 	 	 	 		 	 	 		 	 	 		 	
INTEREST EXPENSE	 	 	 	 	 	 	 	 	 	 	 	 	
 	Interest charges	 	 	204,590	 	 	 	187,512	 	 	 	175,822	 	
 	Capitalized interest	 	 	(29,444	)	 	 	(43,749	)	 	 	(47,862	)	
 	 	 	 		 	 	 		 	 	 		 	
 	 	Total	 	 	175,146	 	 	 	143,763	 	 	 	127,960	 	
 	 	 	 		 	 	 		 	 	 		 	
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	 	 	336,136	 	 	 	338,426	 	 	 	540,902	 	
INCOME TAXES	 	 	105,560	 	 	 	132,228	 	 	 	213,535	 	
 	 	 	 		 	 	 		 	 	 		 	
INCOME FROM CONTINUING OPERATIONS	 	 	230,576	 	 	 	206,198	 	 	 	327,367	 	
 	Income from discontinued operations – net of income taxes of $6,529 and $5,872	 	 	10,003	 	 	 	8,955	 	 	 	—	 	
 	Cumulative effect of a change in accounting for derivatives - net of income taxes of $9,892	 	 	—	 	 	 	—	 	 	 	(15,201	)	
 	Cumulative effect of a change in accounting for trading activities - net of income taxes of $43,123	 	 	—	 	 	 	(65,745	)	 	 	—	 	
 	 	 	 		 	 	 		 	 	 		 	
NET INCOME	 	$	240,579	 	 	$	149,408	 	 	$	312,166	 	
 	 	 	 		 	 	 		 	 	 		 	
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC	 	 	91,265	 	 	 	84,903	 	 	 	84,718	 	
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED	 	 	91,405	 	 	 	84,964	 	 	 	84,930	 	
EARNINGS PER WEIGHTED – AVERAGE COMMON SHARE OUTSTANDING	 	 	 	 	 	 	 	 	 	 	 	 	
 	Income from continuing operations – basic	 	$	2.53	 	 	$	2.43	 	 	$	3.86	 	
 	Net income – basic	 	 	2.64	 	 	 	1.76	 	 	 	3.68	 	
 	Income from continuing operations – diluted	 	 	2.52	 	 	 	2.43	 	 	 	3.85	 	
 	Net income – diluted	 	 	2.63	 	 	 	1.76	 	 	 	3.68	 	
DIVIDENDS DECLARED PER SHARE	 	$	1.725	 	 	$	1.625	 	 	$	1.525	 	
See Notes to Consolidated Financial Statements.
61 

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

 	 	 	 	December 31,	
 	 	 	 		
 	 	 	 	2003	 	2002	
 	 	 	 		 		
ASSETS	 	 	 	 	 	 	 	 	
CURRENT ASSETS	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	228,779	 	 	$	77,566	 	
 	Customer and other receivables	 	 	365,732	 	 	 	362,587	 	
 	Allowance for doubtful accounts	 	 	(9,223	)	 	 	(9,607	)	
 	Accrued utility revenues	 	 	88,629	 	 	 	94,504	 	
 	Materials and supplies (at average cost)	 	 	96,099	 	 	 	91,652	 	
 	Fossil fuel (at average cost)	 	 	28,367	 	 	 	28,185	 	
 	Deferred income taxes (Note 4)	 	 	—	 	 	 	4,094	 	
 	Assets from risk management and trading activities (Note 18)	 	 	97,630	 	 	 	102,664	 	
 	Real estate assets held for sale (Note 22)	 	 	—	 	 	 	42,339	 	
 	Other current assets	 	 	73,034	 	 	 	66,388	 	
 	 	 	 		 	 	 		 	
 	 	Total current assets	 	 	969,047	 	 	 	860,372	 	
 	 	 	 		 	 	 		 	
INVESTMENTS AND OTHER ASSETS	 	 	 	 	 	 	 	 	
 	Real estate investments — net (Notes 1 and 6)	 	 	343,322	 	 	 	384,427	 	
 	Assets from risk management and trading activities- long term (Note 18)	 	 	138,946	 	 	 	191,754	 	
 	Decommissioning trust accounts	 	 	240,645	 	 	 	194,440	 	
 	Other assets	 	 	88,816	 	 	 	76,843	 	
 	 	 	 		 	 	 		 	
 	 	Total investments and other assets	 	 	811,729	 	 	 	847,464	 	
 	 	 	 		 	 	 		 	
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9, 10 and 12)	 	 	 	 	 	 	 	 	
 	Plants in service and held for future use	 	 	9,925,344	 	 	 	9,058,900	 	
 	Less accumulated depreciation and amortization	 	 	3,160,675	 	 	 	2,917,552	 	
 	 	 	 		 	 	 		 	
 	 	Total	 	 	6,764,669	 	 	 	6,141,348	 	
 	Construction work in progress	 	 	554,876	 	 	 	777,542	 	
 	Intangible assets, net of accumulated amortization	 	 	108,534	 	 	 	109,815	 	
 	Nuclear fuel, net of accumulated amortization of $58,053 and $59,163	 	 	52,011	 	 	 	51,124	 	
 	 	 	 		 	 	 		 	
 	Net property, plant and equipment	 	 	7,480,090	 	 	 	7,079,829	 	
 	 	 	 		 	 	 		 	
DEFERRED DEBITS	 	 	 	 	 	 	 	 	
 	Regulatory assets (Notes 1, 3 and 4)	 	 	164,804	 	 	 	241,045	 	
 	Other deferred debits	 	 	110,708	 	 	 	110,447	 	
 	 	 	 		 	 	 		 	
 	 	Total deferred debits	 	 	275,512	 	 	 	351,492	 	
 	 	 	 		 	 	 		 	
TOTAL ASSETS	 	$	9,536,378	 	 	$	9,139,157	 	
 	 	 	 		 	 	 		 	
See Notes to Consolidated Financial Statements.
62 

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

 	 	 	 	 	 	December 31,	
 	 	 	 	 	 		
 	 	 	 	 	 	2003	 	2002	
 	 	 	 	 	 		 		
LIABILITIES AND EQUITY	 	 	 	 	 	 	 	 	
CURRENT LIABILITIES	 	 	 	 	 	 	 	 	
 	Accounts payable	 	$	293,427	 	 	$	332,441	 	
 	Accrued taxes	 	 	69,769	 	 	 	71,107	 	
 	Accrued interest	 	 	51,825	 	 	 	53,018	 	
 	Short-term borrowings (Note 5)	 	 	86,081	 	 	 	227,683	 	
 	Current maturities of long-term debt (Note 6)	 	 	425,480	 	 	 	280,888	 	
 	Customer deposits	 	 	49,783	 	 	 	42,190	 	
 	Deferred income taxes (Note 4)	 	 	631	 	 	 	—	 	
 	Liabilities from risk management and trading activities (Note 18)	 	 	92,755	 	 	 	111,329	 	
 	Real estate liabilities held for sale (Note 22)	 	 	—	 	 	 	28,855	 	
 	Other current liabilities	 	 	81,223	 	 	 	85,585	 	
 	 	 	 		 	 	 		 	
 	 	 	Total current liabilities	 	 	1,150,974	 	 	 	1,233,096	 	
 	 	 	 		 	 	 		 	
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 6)	 	 	2,897,725	 	 	 	2,743,741	 	
 	 	 	 		 	 	 		 	
DEFERRED CREDITS AND OTHER	 	 	 	 	 	 	 	 	
 	Deferred income taxes (Note 4)	 	 	1,329,253	 	 	 	1,209,074	 	
 	Regulatory liabilities (Notes 1, 3 and 4)	 	 	510,423	 	 	 	26,264	 	
 	Liability for asset retirements and removals (Note 12)	 	 	234,440	 	 	 	600,431	 	
 	Pension liability (Note 8)	 	 	188,041	 	 	 	183,880	 	
 	Liabilities from risk management and trading activities-long term (Note 18)	 	 	82,730	 	 	 	147,900	 	
 	Unamortized gain – sale of utility plant (Note 9)	 	 	54,909	 	 	 	59,484	 	
 	Other	 	 	258,104	 	 	 	249,134	 	
 	 	 	 		 	 	 		 	
 	 	 	Total deferred credits and other	 	 	2,657,900	 	 	 	2,476,167	 	
 	 	 	 		 	 	 		 	
COMMITMENTS AND CONTINGENCIES (NOTES 3, 11 AND 12)	 	 	 	 	 	 	 	 	
 	COMMON STOCK EQUITY (Note 7)	 	 	 	 	 	 	 	 	
 	Common stock, no par value; authorized 150,000,000 shares; issued 91,379,947 at end of 2003 and 2002	 	 	1,744,354	 	 	 	1,737,258	 	
 	Treasury stock at cost; 92,015 shares at end of 2003 and 124,830 shares at end of 2002	 	 	(3,273	)	 	 	(4,358	)	
 	 	 	 		 	 	 		 	
 	 	 	Total common stock	 	 	1,741,081	 	 	 	1,732,900	 	
 	 	 	 		 	 	 		 	
 	Accumulated other comprehensive income (loss):	 	 	 	 	 	 	 	 	
 	 	 	 	Minimum pension liability adjustment	 	 	(66,564	)	 	 	(71,264	)	
 	 	 	 	Derivative instruments	 	 	27,563	 	 	 	(20,020	)	
 	 	 	 		 	 	 		 	
 	 	 	Total accumulated other comprehensive loss	 	 	(39,001	)	 	 	(91,284	)	
 	 	 	 		 	 	 		 	
 	Retained earnings	 	 	1,127,699	 	 	 	1,044,537	 	
 	 	 	 		 	 	 		 	
 	 	 	Total common stock equity	 	 	2,829,779	 	 	 	2,686,153	 	
 	 	 	 		 	 	 		 	
TOTAL LIABILITIES AND EQUITY	 	$	9,536,378	 	 	$	9,139,157	 	
 	 	 	 		 	 	 		 	
See Notes to Consolidated Financial Statements.
63 

 
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)

 	 	 	Year Ended December 31,	
 	 	 		
 	 	 	2003	 	2002	 	2001	
 	 	 		 		 		
CASH FLOWS FROM OPERATING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	 	 	
Net Income	 	$	240,579	 	 	$	149,408	 	 	$	312,166	 	
Adjustment to reconcile net income to net cash provided by operating activities:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Gain on sale of discontinued operations	 	 	(10,003	)	 	 	(8,955	)	 	 	—	 	
 	Cumulative effect of accounting change, net of tax	 	 	—	 	 	 	65,745	 	 	 	15,201	 	
 	Depreciation and amortization	 	 	438,143	 	 	 	424,082	 	 	 	427,903	 	
 	Nuclear fuel amortization	 	 	28,757	 	 	 	31,185	 	 	 	28,362	 	
 	Allowance for equity funds used during construction	 	 	(14,240	)	 	 	—	 	 	 	—	 	
 	Deferred income taxes	 	 	81,756	 	 	 	191,135	 	 	 	(17,203	)	
 	Change in mark-to-market valuations	 	 	17,410	 	 	 	(18,146	)	 	 	(133,573	)	
 	Redhawk Units 3 and 4 cancellation charge	 	 	—	 	 	 	49,192	 	 	 	—	 	
Changes in current assets and liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Customer and other receivables	 	 	(3,529	)	 	 	40,343	 	 	 	146,581	 	
 	Accrued utility revenues	 	 	5,875	 	 	 	(18,373	)	 	 	(1,565	)	
 	Materials, supplies and fossil fuel	 	 	(4,629	)	 	 	(11,599	)	 	 	(16,867	)	
 	Other current assets	 	 	(6,646	)	 	 	(7,247	)	 	 	64	 	
 	Accounts payable	 	 	(34,303	)	 	 	54,592	 	 	 	(128,017	)	
 	Accrued taxes	 	 	(1,338	)	 	 	(36,041	)	 	 	7,483	 	
 	Accrued interest	 	 	(1,193	)	 	 	4,212	 	 	 	5,852	 	
 	Other current liabilities	 	 	4,918	 	 	 	32,366	 	 	 	3,761	 	
Proceeds from the sale of real estate assets	 	 	163,700	 	 	 	57,178	 	 	 	35,783	 	
Real estate investments	 	 	(71,618	)	 	 	(72,412	)	 	 	(80,603	)	
Increase in regulatory assets	 	 	(11,697	)	 	 	(11,029	)	 	 	(17,516	)	
Change in risk management and trading – assets	 	 	46,911	 	 	 	(11,700	)	 	 	(51,894	)	
Change in risk management and trading – liabilities	 	 	(11,613	)	 	 	(22,783	)	 	 	45,330	 	
Change in customer advances	 	 	7,270	 	 	 	(23,780	)	 	 	28,599	 	
Change in pension liability	 	 	19,074	 	 	 	(3,009	)	 	 	(30,205	)	
Change in other long-term assets	 	 	5,598	 	 	 	(23,554	)	 	 	14,746	 	
Change in other long-term liabilities	 	 	12,648	 	 	 	10,420	 	 	 	(23,345	)	
 	 	 		 	 	 		 	 	 		 	
Net cash flow provided by operating activities	 	 	901,830	 	 	 	841,230	 	 	 	571,043	 	
 	 	 		 	 	 		 	 	 		 	
CASH FLOWS FROM INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(693,475	)	 	 	(895,522	)	 	 	(1,055,574	)	
Capitalized interest	 	 	(29,444	)	 	 	(43,749	)	 	 	(47,862	)	
Proceeds from sale of assets from discontinued operations	 	 	27,193	 	 	 	28,917	 	 	 	—	 	
Other	 	 	(21,040	)	 	 	36,635	 	 	 	(16,481	)	
 	 	 		 	 	 		 	 	 		 	
Net cash flow used for investing activities	 	 	(716,766	)	 	 	(873,719	)	 	 	(1,119,917	)	
 	 	 		 	 	 		 	 	 		 	
CASH FLOWS FROM FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	 	 	 	 	
Issuance of long-term debt	 	 	656,850	 	 	 	674,919	 	 	 	995,447	 	
Short-term borrowings and payments – net	 	 	(173,303	)	 	 	(306,079	)	 	 	322,987	 	
Dividends paid on common stock	 	 	(157,417	)	 	 	(137,721	)	 	 	(129,199	)	
Repayment of long-term debt	 	 	(368,162	)	 	 	(351,545	)	 	 	(621,057	)	
Common stock equity issuance	 	 	—	 	 	 	199,238	 	 	 	—	 	
Other	 	 	8,181	 	 	 	2,624	 	 	 	(1,048	)	
 	 	 		 	 	 		 	 	 		 	
Net cash flow (used for) provided by financing activities	 	 	(33,851	)	 	 	81,436	 	 	 	567,130	 	
 	 	 		 	 	 		 	 	 		 	
NET INCREASE IN CASH AND CASH EQUIVALENTS	 	 	151,213	 	 	 	48,947	 	 	 	18,256	 	
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR	 	 	77,566	 	 	 	28,619	 	 	 	10,363	 	
 	 	 		 	 	 		 	 	 		 	
CASH AND CASH EQUIVALENTS AT END OF YEAR	 	$	228,779	 	 	$	77,566	 	 	$	28,619	 	
 	 	 		 	 	 		 	 	 		 	
Supplemental disclosure of cash flow information	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cash paid during the period for:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Income taxes paid/(refunded)	 	$	32,816	 	 	$	(17,918	)	 	$	223,037	 	
 	Interest paid, net of amounts capitalized	 	$	161,581	 	 	$	126,322	 	 	$	115,276	 	
See Notes to Consolidated Financial Statements.
64 

 
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(dollars in thousands)

 	 	Year Ended December 31,	
 	 		
 	 	2003	 	2002	 	2001	
 	 		 		 		
COMMON STOCK (Note 7)	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	$	1,737,258	 	 	$	1,536,924	 	 	$	1,537,920	 	
Issuance of common stock	 	 	—	 	 	 	199,238	 	 	 	—	 	
Other	 	 	7,096	 	 	 	1,096	 	 	 	(996	)	
 	 	 		 	 	 		 	 	 		 	
Balance at end of year	 	 	1,744,354	 	 	 	1,737,258	 	 	 	1,536,924	 	
 	 	 		 	 	 		 	 	 		 	
TREASURY STOCK (Note 7)	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	 	(4,358	)	 	 	(5,886	)	 	 	(5,089	)	
Purchase of treasury stock	 	 	—	 	 	 	(5,971	)	 	 	(16,393	)	
Reissuance of treasury stock used for stock compensation, net	 	 	1,085	 	 	 	7,499	 	 	 	15,596	 	
 	 	 		 	 	 		 	 	 		 	
Balance at end of year	 	 	(3,273	)	 	 	(4,358	)	 	 	(5,886	)	
 	 	 		 	 	 		 	 	 		 	
RETAINED EARNINGS	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	 	1,044,537	 	 	 	1,032,850	 	 	 	849,883	 	
Net income	 	 	240,579	 	 	 	149,408	 	 	 	312,166	 	
Common stock dividends	 	 	(157,417	)	 	 	(137,721	)	 	 	(129,199	)	
 	 	 		 	 	 		 	 	 		 	
Balance at end of year	 	 	1,127,699	 	 	 	1,044,537	 	 	 	1,032,850	 	
 	 	 		 	 	 		 	 	 		 	
ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	 	 	 	 	 	 	 	 	 	 	 	 	
Balance at beginning of year	 	 	(91,284	)	 	 	(64,565	)	 	 	—	 	
Minimum pension liability adjustment, net of tax of $3,700, $46,109 and $634	 	 	4,700	 	 	 	(70,298	)	 	 	(966	)	
Cumulative effect of a change in accounting for derivatives, net of tax of $47,404	 	 	—	 	 	 	—	 	 	 	72,274	 	
Unrealized gain/(loss) on derivative instruments, net of tax of $33,298, $28,820 and $71,720	 	 	51,089	 	 	 	43,939	 	 	 	(109,346	)	
Reclassification of realized gain to income, net of tax of $2,343, $237 and $17,399	 	 	(3,506	)	 	 	(360	)	 	 	(26,527	)	
 	 	 		 	 	 		 	 	 		 	
Balance at end of year	 	 	(39,001	)	 	 	(91,284	)	 	 	(64,565	)	
 	 	 		 	 	 		 	 	 		 	
TOTAL COMMON STOCK EQUITY	 	$	2,829,779	 	 	$	2,686,153	 	 	$	2,499,323	 	
 	 	 		 	 	 		 	 	 		 	
COMPREHENSIVE INCOME (LOSS)	 	 	 	 	 	 	 	 	 	 	 	 	
Net income	 	$	240,579	 	 	$	149,408	 	 	$	312,166	 	
Other comprehensive income (loss)	 	 	52,283	 	 	 	(26,719	)	 	 	(64,565	)	
 	 	 		 	 	 		 	 	 		 	
Comprehensive income	 	$	292,862	 	 	$	122,689	 	 	$	247,601	 	
 	 	 		 	 	 		 	 	 		 	
See Notes to Consolidated Financial Statements.
65 

 

PINNACLE WEST CAPTAL CORPORATION
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Consolidation and Nature of Operations
     The consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado (principally NAC). 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 the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. APS also generates, sells and delivers electricity to wholesale customers in the western United States. In early 2003, the marketing and trading division of Pinnacle West was moved to APS for future marketing and trading activities (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of APS’ generating assets to Pinnacle West Energy. See Note 3 for a discussion of the Track A Order. Pinnacle West Energy, which was formed in 1999, is the subsidiary through which we conduct our unregulated generation operations. APS Energy Services was formed in 1998 and provides competitive commodity energy and energy-related products to key customers in competitive markets in the western United States. SunCor is a developer of residential, commercial and industrial real estate projects in Arizona, New Mexico, Idaho and Utah. El Dorado is an investment firm, and its principal investment is in NAC, which is a company specializing in spent nuclear fuel technology.
Accounting Records and Use of Estimates
     Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.
Derivative Accounting
     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. 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 overall risk management program, we use such instruments to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
     We account for our derivative contracts in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires that
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PINNACLE WEST CAPTAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 hedge criteria are met, in common stock equity (as a component of other comprehensive income (loss)). SFAS No. 133 provides a scope exception for contracts that meet the normal purchases and sales criteria specified in the standard.
     Prior to the fourth quarter of 2002, we accounted for our trading activity at fair value, with changes in fair value reported in earnings as required by EITF 98-10 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” In the fourth quarter of 2002, we adopted EITF 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which rescinded EITF 98-10. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Energy trading contracts that do not meet the definition of a derivative are now accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received.
     See Note 18 for additional information about our derivative and energy trading accounting policies.
Mark-to-Market Accounting
     Under mark-to-market accounting, derivative contracts for the purchase or sale of energy commodities are reflected at fair market value, net of valuation adjustments, with resulting unrealized gains and losses recorded as current or long-term assets and liabilities from risk management and trading activities in 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. We convert quarterly and calendar year quotes into monthly prices based on historical relationships.
     For options, long-term contracts and other contracts for which price quotes are not available, we use models and other valuation methods. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. The primary valuation technique we use to calculate the fair value of contracts where price quotes are not available is based on the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at the more illiquid delivery points. We also value option contracts using a variation of the Black-Scholes option-pricing model.
     For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, and we discount to reflect net present value. We maintain certain valuation
67 

 

PINNACLE WEST CAPTAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 and local distribution companies. 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. See Note 18 for further discussion on credit risk.
     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.
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 the recovery of expected future costs in current customer rates.
     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.
     As part of the 1999 Settlement Agreement with the ACC (see Note 3), we continue to amortize certain regulatory assets over an eight-year period as follows (dollars in millions): 

1999	 	2000	 	2001	 	2002	 	2003	 	2004	 	Total	
	 		 		 		 		 		 		
$	164	 	 	$	158	 	 	$	145	 	 	$	115	 	 	$	86	 	 	$	18	 	 	$	686	 	
     The detail of regulatory assets is as follows (dollars in millions):
68 

 
PINNACLE WEST CAPTAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 	 	 	December 31,	
 	 	 		
 	 	 	2003	 	2002	
 	 	 		 		
Remaining balance recoverable under the 1999	 	 	 	 	 	 	 	 	
 	Settlement Agreement (a)	 	$	18	 	 	$	104	 	
Spent nuclear fuel storage (Note 11)	 	 	49	 	 	 	46	 	
Electric industry restructuring transition costs (Note 3)	 	 	46	 	 	 	40	 	
Deferred compensation	 	 	24	 	 	 	23	 	
Contributions in aid of construction	 	 	11	 	 	 	10	 	
Loss on reacquired debt (b)	 	 	12	 	 	 	9	 	
Other	 	 	5	 	 	 	9	 	
 	 	 	 		 	 	 		 	
 	Total regulatory assets	 	$	165	 	 	$	241	 	

 	(a)	 	The majority of our unamortized regulatory assets above relates to deferred income taxes (see Note 4) and rate synchronization cost deferrals (see “Rate Synchronization Cost Deferrals” below).	
 		
 	(b)	 	See “Reacquired Debt Costs” below.	
     The detail of regulatory liabilities is as follows (dollars in millions): 

 	 	 	December 31,	
 	 	 		
 	 	 	2003	 	2002	
 	 	 		 		
Removal costs (a)	 	$	480	 	 	$	—	 	
Deferred gains on utility property	 	 	20	 	 	 	20	 	
Deferred interest income (b)	 	 	8	 	 	 	—	 	
Other	 	 	2	 	 	 	6	 	
 	 	 		 	 	 		 	
 	Total regulatory liabilities	 	$	510	 	 	$	26	 	

 	(a)	 	See Note 12 for information on Asset Retirement Obligations.	
 		
 	(b)	 	See “ACC Financing Orders” in Note 3 for information on the “APS Loan”.	
Rate Synchronization Cost Deferrals
     As authorized by the ACC, operating costs (excluding fuel) and financing costs of Palo Verde Units 2 and 3 were deferred from the commercial operation dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the units were included in a rate order (April 1988 for Unit 2 and December 1991 for Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to accelerate the amortization of the deferrals over an eight-year period that will end June 30, 2004. Amortization of the deferrals is included in depreciation and amortization expense in the Consolidated Statements of Income.
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:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 	•	 	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. Prior to 2003, we charged removal costs, less salvage, to accumulated depreciation. Effective January 1, 2003, we applied the provisions of SFAS 143 (see Note 12).
     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, 2003 were as follows:

 	•	 	Fossil plant – 23 years;	
 		
 	•	 	Nuclear plant – 20 years;	
 		
 	•	 	Other generation – 29 years;	
 		
 	•	 	Transmission – 36 years;	
 		
 	•	 	Distribution – 23 years; and	
 		
 	•	 	Other – 9 years.	
     For the years 2001 through 2003, the depreciation rates, as prescribed by our regulators, ranged from a low of 1.51% to a high of 12.5%. The weighted-average rate was 3.35% for 2003, 3.35% for 2002 and 3.40% for 2001. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years.
El Dorado Investments
     El Dorado accounts for its investments using the consolidated (if controlled), equity (if significant influence) and cost (less than 20% ownership) methods. Beginning in the third quarter of 2002, El Dorado began consolidating the operations of NAC.
Capitalized Interest
     Capitalized interest represents the cost of debt funds used to finance construction projects. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. The rate used to calculate capitalized interest was a composite rate of 4.55% for 2003, 4.80% for 2002 and 6.13% for 2001. Capitalized interest ceases to accrue when construction is complete.
Allowance for Funds Used During Construction
     AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction of utility plant. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
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     AFUDC was calculated by using a composite rate of 8.55% for 2003. APS compounds AFUDC monthly and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
     In 2003, APS returned to the AFUDC method of capitalizing interest and equity costs associated with construction projects in a regulated utility. This is consistent with APS returning to a vertically-integrated utility, as evidenced by APS’ recent general rate case filing, which includes the request for rate recognition of generation assets. Previously, APS capitalized interest in accordance with SFAS No. 34, “Capitalization of Interest Cost.” Although AFUDC both increases the plant balance and results in higher current earnings during the construction period, AFUDC is realized in future revenues through depreciation provisions included in rates. This change increased earnings by $11 million in 2003 as compared to what it would have been under SFAS No. 34.
Electric Revenues
     We derive electric revenues from sales of electricity to our regulated Native Load customers and sales to other parties from our marketing and trading activities. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. However, the determination and billing of electricity sales to individual Native Load customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of electricity delivered to customers since the date of the last meter reading and billing and the corresponding unbilled revenue are estimated. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Revenues from our Native Load customers and non-derivative instruments are reported on a gross basis in our Consolidated Statements of Income.
     All gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis.
     We adopted 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 Issue No. 02-3,” effective October 1, 2003. EITF 03-11 provides guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. 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 netted these book-outs reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows (see Note 18 for additional information).
SunCor
     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
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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. SunCor recognizes income only after the assets’ title has passed. A single method of recognizing income is applied to all sales transactions within an entire home, land or commercial development project. 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 – Real Estate Activities – Discontinued Operations.
Percentage of Completion – NAC
     Certain NAC contract revenues are accounted for under the percentage-of-completion method. These revenues are reported in other revenue on the Consolidated Statements of Income. Revenues are recognized based upon total costs incurred to date compared to total costs expected to be incurred for each contract. Revisions in contract revenue and cost estimates are reflected in the accounting period when known. Provisions are made for the full amounts of anticipated losses in the periods in which they are first determined. Changes in job performance, job conditions and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and income, and are recognized in the period in which revisions are determined. Profit incentives are included in revenues when their realization is reasonably assured.
     Contract costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, tools, repairs and depreciation costs. General and administrative costs are charged to expense as incurred.
Cash and Cash Equivalents
     We consider all highly liquid investments purchased with an initial maturity of three months or less to be cash equivalents.
Nuclear Fuel
     APS charges nuclear fuel to fuel expense by using the unit-of-production method. The unit-of-production method is an amortization method based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
     APS also charges nuclear fuel expense for the permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel, and it charges APS $0.001 per kWh of nuclear generation. See Note 11 for information about spent nuclear fuel disposal and Note 12 for information on nuclear decommissioning costs.
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Income Taxes
     Income taxes are provided using the asset and liability approach prescribed by SFAS No. 109, “Accounting for Income Taxes.” We file our federal income tax return on a consolidated basis and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each subsidiary as though each 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. See Note 4.
Reacquired Debt Costs
     For debt related to the regulated portion of APS’ business, APS defers those gains and losses incurred upon early retirement and is seeking recovery in the APS general rate case (see Note 3). In accordance with the 1999 Settlement Agreement, APS is continuing to accelerate the amortization of reacquired debt costs over an eight-year period that will end June 30, 2004. All regulatory asset amortization is included in depreciation and amortization expense in the Consolidated Statements of Income.
Real Estate Investments
     Real estate investments primarily include SunCor’s land, home inventory and investments in joint ventures. Land includes acquisition costs, infrastructure costs, property taxes and capitalized interest directly associated with the acquisition and development of each project. Land under development and land held for future development are stated at accumulated cost, except that, to the extent that such land is believed to be impaired, it is written down to fair value. Land held for sale is stated at the lower of accumulated cost or estimated fair value less costs to sell. Home inventory consists of construction costs, improved lot costs, capitalized interest and property taxes on homes under construction. Home inventory is stated at the lower of accumulated cost or estimated fair value less costs to sell. Investments in joint ventures for which SunCor does not have a controlling financial interest are not consolidated but are accounted for using the equity method of accounting. In 2003, SunCor acquired two joint ventures for $10 million and consolidated $53 million of assets and $43 million of liabilities, which are included in the Consolidated Balance Sheets at December 31, 2003. The $10 million cash investment is included on the other investing line of the Consolidated Statements of Cash Flow at December 31, 2003. In addition, see Note 22 – Real Estate Activities – Discontinued Operations.
Stock-Based Compensation
     In 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” The fair value method of accounting is the preferred method. In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.”
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     The following chart compares our net income, stock compensation expense and earnings per share to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through 2003 (dollars in thousands, except per share amounts):

 	 	 	 	2003	 	2002	 	2001	
 	 	 	 		 		 		
Net Income as reported:	 	$	240,579	 	 	$	149,408	 	 	$	312,166	 	
Add: Stock compensation expense included in reported net income (net of tax):	 	 	1,288	 	 	 	300	 	 	 	—	 	
Deduct: Total stock	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	compensation expense determined under fair value method (net of tax)	 	 	(2,994	)	 	 	(1,695	)	 	 	(2,292	)	
 	 	 		 	 	 		 	 	 		 	
 	Pro forma net income	 	$	238,873	 	 	$	148,013	 	 	$	309,874	 	
 	 	 		 	 	 		 	 	 		 	
Earnings per share – basic:	 	 	 	 	 	 	 	 	 	 	 	 	
 	As reported	 	$	2.64	 	 	$	1.76	 	 	$	3.68	 	
 	Pro forma (fair value method)	 	$	2.62	 	 	$	1.74	 	 	$	3.66	 	
Earnings per share – diluted:	 	 	 	 	 	 	 	 	 	 	 	 	
 	As reported	 	$	2.63	 	 	$	1.76	 	 	$	3.68	 	
 	Pro forma (fair value method)	 	$	2.61	 	 	$	1.74	 	 	$	3.65	 	
     In order to calculate the fair value of the 2003, 2002 and 2001 stock option grants and the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options: 

 	 	2003	 	2002	 	2001	
 	 		 		 		
Risk-free interest rate	 	 	3.35	%	 	 	4.17	%	 	 	4.08	%	
Dividend yield	 	 	5.26	%	 	 	4.17	%	 	 	3.70	%	
Volatility	 	 	38.03	%	 	 	22.59	%	 	 	27.66	%	
Expected life (months)	 	 	60	 	 	 	60	 	 	 	60	 	
     See Note 16 for further discussion about our stock compensation plans.
Intangible Assets
     We have no goodwill recorded and have separately disclosed other intangible assets on our Consolidated Balance Sheets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets.” The intangible assets are amortized over their finite useful lives. The Company’s gross intangible assets (which are primarily capitalized software costs) were $237 million at December 31, 2003 and $214 million at December 31, 2002. The related accumulated amortization was $128 million at December 31, 2003 and $104 million at December 31, 2002. Amortization expense was
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$25 million in 2003, $21 million in 2002, and $22 million in 2001. Estimated amortization expense on existing intangible assets over the next five years is $28 million in 2004, $27 million in 2005, $25 million in 2006, $20 million in 2007, and $9 million in 2008. At December 31, 2003, the weighted average amortization period for intangible assets is 7 years.
2. Accounting Matters
     See the following Notes for information about new accounting standards and other accounting matters:

 		
 	•	 	Note 8 for amended disclosure requirements (SFAS No. 132) on retirement plans and other benefits;	
 		
 	•	 	Note 12 for a new accounting standard (SFAS No. 143) on asset retirement obligations;	
 		
 	•	 	Note 16 for a new accounting standard (SFAS No. 148) related to stock-based compensation;	
 		
 	•	 	Note 18 for EITF issues (EITF 02-3 and 03-11), DIG Issue No. C15, and a new accounting standard (SFAS No. 149) related to accounting for derivatives and energy contracts;	
 		
 	•	 	Note 20 for a new FASB interpretation (FIN No. 46R) related to VIEs;	
 		
 	•	 	Note 21 for a new FASB interpretation (FIN No. 45) on guarantees; and	
 		
 	•	 	Note 22 for a standard (SFAS No. 144) on accounting for the impairment or disposal of long-lived assets.	
3. Regulatory Matters
Electric Industry Restructuring
State
      1999 Settlement Agreement
     The following are the major provisions of the 1999 Settlement Agreement, as approved by the ACC:

 	•	 	APS has reduced rates for standard-offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. Based on the price reductions authorized in the 1999 Settlement Agreement, there were retail price decreases of approximately $24 million ($14 million after taxes), effective July 1, 1999;	
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 	 	 	approximately $28 million ($17 million after taxes), effective July 1, 2000; approximately $27 million ($16 million after taxes), effective July 1, 2001; approximately $28 million ($17 million after taxes), effective July 1, 2002; and approximately $29 million ($18 million after taxes), effective July 1, 2003. For customers having loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002.	
 		
 	•	 	Unbundled rates being charged by APS for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.	
 		
 	•	 	There is a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor APS is prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms; material changes in APS’ cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders.	
 		
 	•	 	APS will be permitted to defer for later recovery prudent and reasonable costs of complying with the Rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the “provider of last resort” and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below.	
 		
 	•	 	APS’ distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see “Retail Electric Competition Rules” below), including an additional 140 MW being made available to eligible non-residential customers. APS opened its distribution system to retail access for all customers on January 1, 2001. The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.	
 		
 	•	 	Prior to the 1999 Settlement Agreement, APS was recovering substantially all of its regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that APS has demonstrated that its allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). The 1999 Settlement	
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 	 	 	Agreement also states that APS will not be allowed to recover $183 million net present value (in 1999 dollars) of the $533 million. The 1999 Settlement Agreement provides that APS will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery of the $350 million due to sales volume variances. As discussed below under “APS General Rate Case and Retail Rate Adjustment Mechanisms,” APS is seeking to recover amounts written off by APS as a result of the 1999 Settlement Agreement.	
 		
 	•	 	The 1999 Settlement Agreement required APS to form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) its competitive electric assets and services no later than December 31, 2002. The 1999 Settlement Agreement provided that APS would be allowed to defer and later collect, beginning July 1, 2004, 67% of its costs to accomplish the required transfer of generation assets to an affiliate. However, as discussed below, in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing the Track A Order, an order preventing APS from transferring its generation assets. APS is seeking to recover all costs incurred by APS in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below.	
      Retail Electric Competition Rules
     The Rules approved by the ACC include the following major provisions:

 	•	 	They apply to virtually all Arizona electric utilities regulated by the ACC, including APS.	
 		
 	•	 	Effective January 1, 2001, retail access became available to all APS retail electricity customers.	
 		
 	•	 	Electric service providers that get CC&N’s from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.	
 		
 	•	 	Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services.	
 		
 	•	 	The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.	
 		
 	•	 	Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, APS received a waiver to allow transfer of its	
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 	 	 	competitive electric assets and services to affiliates no later than December 31, 2002. However, as discussed below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets.	
     Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, APS must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement.
     On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. We do not believe the ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of APS’ property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC appealed the ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not all, of the Rules as either violative of Arizona’s constitutional requirement that the ACC consider the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s constitutional and statutory powers. Other Rules were set aside for failure to submit such regulations to the Arizona Attorney General for approval as required by statute.
      Provider of Last Resort Obligation
     Although the Rules allow retail customers to have access to competitive providers of energy and energy services, APS is, under the Rules, the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows APS to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in APS’ cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS’ current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, APS may need to purchase additional supplemental power in the wholesale spot market. Unless APS is able to obtain an adjustment of its rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that APS would be able to fully recover the costs of this power. See “APS General Rate Case and Retail Rate Adjustment Mechanisms” below for a discussion of retail rate adjustment mechanisms that were the subject of ACC hearings in April 2003.
      Track A Order
     On September 10, 2002, the ACC issued the Track A Order, in which the ACC, among other things:
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 	•	 	reversed its decision, as reflected in the Rules, to require APS to transfer its generation assets either to an unrelated third party or to a separate corporate affiliate; and	
 		
 	•	 	unilaterally modified the 1999 Settlement Agreement, which authorized APS’ transfer of its generating assets, and directed APS to cancel its activities to transfer its generation assets to Pinnacle West Energy.	
     On November 15, 2002, APS filed appeals of the Track A Order in the Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals. Arizona Public Service Company vs. Arizona Corporation Commission , CV 2002-0222 32. Arizona Public Service Company vs. Arizona Corporation Commission , 1CA CC 02-0002. On December 13, 2002, APS and the ACC staff agreed to principles for resolving certain issues raised by APS in its appeals of the Track A Order. APS and the ACC are the only parties to the Track A Order appeals. The major provisions of the principles include, among other things, the following:

 	•	 	APS and the ACC staff agreed that it would be appropriate for the ACC to consider the following matters in APS’ general rate case, which was filed on June 27, 2003:	

 	•	 	the generating assets to be included in APS’ rate base, including the question of whether the PWEC Dedicated Assets should be included in APS’ rate base;	
 		
 	•	 	the appropriate treatment of the $234 million pretax asset write-off agreed to by APS as part of the 1999 Settlement Agreement; and	

 	•	 	the appropriate treatment of costs incurred by APS in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy.	
 		
 	•	 	Upon the ACC’s issuance of a final decision that is no longer subject to appeal approving APS’ request to provide $500 million of financing or credit support to Pinnacle West Energy or the Company, with appropriate conditions, APS’ appeals of the Track A Order would be limited to the issues described in the preceding bullet points, each of which would be presented to the ACC for consideration prior to any final judicial resolution. As noted below, the ACC issued the Financing Order on April 4, 2003. The Financing Order is final and no longer subject to appeal. As a result, APS’ appeals of the Track A Order are limited to the issues described in the preceding bullet points.	
     On August 27, 2003, APS, Pinnacle West and Pinnacle West Energy filed a lawsuit asserting damage claims relating to the Track A Order. Arizona Public Service Company et al. v. The State of Arizona ex rel ., Superior Court of the State of Arizona, County of Maricopa, No. CV2003-016372.
      Track B Order
     On March 14, 2003, the ACC issued the Track B Order, which required APS to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. For 2003,
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APS was required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of APS’ total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in APS’ retail load and APS’ retail energy sales. The Track B Order also confirmed that it was “not intended to change the current rate base status of [APS’] existing assets.”
     The order recognizes APS’ right to reject any bids that are unreasonable, uneconomical or unreliable. The ACC staff and an independent monitor participated in the Track B procurement process. The Track B Order also contains requirements relating to standards of conduct between APS and any affiliate of APS participating in the competitive solicitation, requires that APS treat bidders in a non-discriminatory manner and requires APS to file a protocol regarding short-term and emergency procurements. The order permits the provision by APS of corporate oversight, support and governance as long as such activities do not favor Pinnacle West Energy in the procurement process or provide Pinnacle West Energy with confidential APS bidding information that is not available to other bidders. The order directs APS to evaluate bids on cost, reliability and reasonableness. The decision requires bidders to allow the ACC to inspect their plants and requires assurances of appropriate competitive market conduct from senior officers of such bidders. Following the solicitation, the decision requires APS to prepare a report evaluating environmental issues relating to the procurement, and a series of workshops on environmental risk management will be commenced thereafter.
     APS issued requests for proposals in March 2003 and, by May 6, 2003, APS entered into contracts to meet all or a portion of its requirements for the years 2003 through 2006 as follows:

 	(1)	 	Pinnacle West Energy agreed to provide 1,700 MW in July through September of 2003 and in June through September of 2004, 2005 and 2006, by means of a unit contingent contract.	
 		
 	(2)	 	PPL EnergyPlus, LLC agreed to provide 112 MW in July through September of 2003 and 150 MW in June through September of 2004 and 2005, by means of a unit contingent contract.	
 		
 	(3)	 	Panda Gila River LP agreed to provide 450 MW in October of 2003 and 2004 and May of 2004 and 2005, and 225 MW from November 2003 through April 2004 and from November 2004 through April 2005, by means of firm call options.	
      ACC Financing Orders
     On April 4, 2003, the ACC issued the Financing Order authorizing APS to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate (the “APS Loan”), subject to the following principal conditions:

 	•	 	any debt issued by APS pursuant to the order must be unsecured;	
 		
 	•	 	the APS Loan must be callable and secured by the PWEC Dedicated Assets;	
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 	•	 	the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on APS debt that could be issued and sold on equivalent terms (including, but not limited to, maturity and security);	

 	•	 	the 264 basis points referred to in the previous bullet point will be capitalized as a deferred credit and used to offset retail rates in the future, with the deferred credit balance bearing an interest rate of six percent per annum;	
 		
 	•	 	the APS Loan must have a maturity date of not more than four years, unless otherwise ordered by the ACC;	
 		
 	•	 	any demonstrable increase in APS’ cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases;	
 		
 	•	 	APS must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce its common equity ratio below that threshold, unless otherwise waived by the ACC. The ACC will process any waiver request within sixty days, and for this sixty-day period this condition will be suspended. However, this condition, which will continue indefinitely, will not be permanently waived without an order of the ACC; and	
 		
 	•	 	certain waivers of the ACC’s affiliated interest rules previously granted to APS and its affiliates will be temporarily withdrawn and, during the term of the APS Loan, neither Pinnacle West nor Pinnacle West Energy may reorganize or restructure, acquire or divest assets, or form, buy or sell affiliates (each, a “Covered Transaction”), or pledge or otherwise encumber the Pinnacle West Energy assets without prior ACC approval, except that the foregoing restrictions will not apply to the following categories of Covered Transactions:	

 	•	 	Covered Transactions less than $100 million, measured on a cumulative basis over the calendar year in which the Covered Transactions are made;	
 		
 	•	 	Covered Transactions by SunCor of less than $300 million through 2005, consistent with SunCor’s anticipated accelerated asset sales activity during those years;	
 		
 	•	 	Covered Transactions related to the payment of ongoing construction costs for Pinnacle West Energy’s (a) West Phoenix Unit 5, located in Phoenix, and (b) Silverhawk plant, located near Las Vegas, with an expected commercial operation date in mid-2004; and	
 		
 	•	 	Covered Transactions related to the sale of 25% of the Silverhawk plant to SNWA pursuant to an agreement between SNWA and Pinnacle West Energy.	
     The ACC also ordered the ACC staff to conduct an inquiry into our and our affiliates’ compliance with the retail electric competition and related rules and decisions. On June 13, 2003,
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APS submitted its report on these matters to the ACC staff. The ACC has indicated that the preliminary investigation would be addressed in the pending general rate case (see below).
     On May 12, 2003, APS issued $500 million of debt pursuant to the Financing Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to us to fund the repayment of a portion of the debt we incurred to finance the construction of the PWEC Dedicated Assets. See Note 6.
     On November 22, 2002, the ACC issued an order approving APS’ request to permit APS to make short-term advances to Pinnacle West in the form of an interaffiliate line of credit in the amount of $125 million. As of December 31, 2003, there were no borrowings outstanding under this financing arrangement, and this authority expired on December 4, 2003.
APS General Rate Case and Retail Rate Adjustment Mechanisms
     As noted above, on June 27, 2003, APS filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in its annual retail electricity revenues, to become effective July 1, 2004. In this rate case, APS updated its cost of service and rate design.
      Major Components of the Request The major reasons for the request include:

 	•	 	complying with the provisions of the 1999 Settlement Agreement;	
 		
 	•	 	incorporating significant increases in fuel and purchased power costs, including results of purchases through the ACC’s Track B procurement process;	
 		
 	•	 	recognizing changes in APS’ cost of service, cost allocation and rate design;	
 		
 	•	 	obtaining rate recognition of the PWEC Dedicated Assets;	
 		
 	•	 	recovering $234 million written off by APS as a result of the 1999 Settlement Agreement; and	
 		
 	•	 	recovering restructuring and compliance costs associated with the ACC’s Rules.	
      Requested Rate Increase The requested rate increase totals $175.1 million, or 9.8%, and is comprised of the following items (dollars in millions): 

 	 	Annual Revenue	 	Percent	
 	 		 		
Increase in base rates	 	$	166.8	 	 	 	9.3	%	
Rules compliance charge	 	 	8.3	 	 	 	0.5	%	
 	 	 		 	 	 		 	
Total increase	 	$	175.1	 	 	 	9.8	%	
 	 	 		 	 	 		 	
      Test Year The filing is based on an adjusted historical test year ended December 31, 2002.
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      Cost of Capital The proposed weighted average cost of capital for the test year ended December 31, 2002 is 8.67%, including an 11.5% return on equity.
      Rate Base The request is based on a rate base of $4.2 billion, calculated using Original Cost Less Depreciation (“OCLD”) methodology. The OCLD rate base approximates the ACC-jurisdictional portion of the net book value of utility plant, net of accumulated depreciation and deferred taxes, as of December 31, 2002, except as set forth below.
     The requested rate base includes the PWEC Dedicated Assets, with a total combined capacity of approximately 1,800 MW. These assets were included at their estimated July 1, 2004 net book value. Upon approval of the request, the PWEC Dedicated Assets would be transferred to APS from Pinnacle West Energy.
     The filing also includes calculated amounts for Fair Value Rate Base and Replacement Cost New Depreciated (“RCND”) rate base. The ACC is required by the Arizona Constitution to make a finding of Fair Value Rate Base, which has traditionally been defined by the ACC as the arithmetic average of OCLD rate base and RCND rate base.
      Recovery of Previous $234 Million Write-Off The request includes recovery, over a fifteen year period, of the write-off of $234 million pretax of regulatory assets by APS as a result of the 1999 Settlement Agreement. See “1999 Settlement Agreement” above.
      Estimated Timeline APS has asked the ACC to approve the requested rate increase by July 1, 2004. The ACC ALJ has issued a procedural schedule setting a hearing date on the application of May 25, 2004. Based on the schedule and existing ACC regulations, we believe the ACC will be able to make a decision in this general rate case by the end of 2004.
     The general rate case also addresses the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized as a result of the 1999 Settlement Agreement, would allow APS to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the Rules.
     On November 4, 2003, the ACC approved the issuance of an order which authorizes a rate adjustment mechanism allowing APS to recover changes in purchased power costs (but not changes in fuel costs) incurred after July 1, 2004. The other rate adjustment mechanisms authorized in the 1999 Settlement Agreement (such as the costs associated with complying with the ACC electric competition rules) were also tentatively approved for subsequent implementation in the general rate case. The provisions of this order will not become effective until there is a final order in the general rate case, and the ACC further reserved the right to amend, modify or reconsider, in its entirety, this November 4 order during the rate case.
      Testimony As required by the procedural schedule, on February 3, 2004, the following parties filed their initial written testimony with the ACC on all issues except cost of service (i.e., cost allocation among customer classes) and rate design:

 	•	 	the ACC “litigation” staff;	
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 	•	 	the Arizona Residential Utility Consumers Office (“RUCO”), an office established by the Arizona legislature to represent the interests of residential utility consumers before the ACC; and	
 		
 	•	 	other approved rate case interveners.	
      ACC Staff Recommendations In its filed testimony, the ACC staff recommended, among other things, that the ACC:

 	•	 	decrease APS’ annual retail electricity revenues by at least $142.7 million, which would result in a rate decrease of approximately 8%, based on a 9% return on equity;	
 		
 	•	 	not allow the PWEC Dedicated Assets to be included in APS’ rate base;	
 		
 	•	 	not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement; and	
 		
 	•	 	not implement any adjustment mechanisms for fuel and purchased power.	
     The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings and access to capital markets. We believe that APS’ rate case requests are supported by, among other things, APS’ demonstrated need for the PWEC Dedicated Assets; APS’ need to attract capital at reasonable rates of return to support the required capital investment to ensure continued customer reliability in APS’ high-growth service territory; and the conditions in the western energy market. As a result, we believe it is unlikely that the ACC would adopt the ACC staff recommendations in their present form, although we can give no assurances in that regard.
     The ACC staff also submitted testimony indicating that APS and its affiliates had violated the “spirit, if not the letter” of the Rules, the Code of Conduct and the 1999 Settlement Agreement.
      RUCO Recommendations In its filed testimony, RUCO recommended, among other things, that the ACC:

 	•	 	decrease APS’ annual retail electricity revenues by $53.6 million, which would result in a rate decrease of approximately 2.84%, based on a 9.5% return on equity;	
 		
 	•	 	not allow the PWEC Dedicated Assets to be included in APS’ rate base;	
 		
 	•	 	not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement; and	
 		
 	•	 	not implement any adjustment mechanisms for fuel and purchased power.	
     APS believes that its rate request is necessary to ensure APS’ continued ability to reliably serve one of the fastest growing regions in the country and views any ultimate decision that would deny recovery of the Company’s investment in the PWEC Dedicated Assets as constituting a
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regulatory “taking.” APS will vigorously oppose the recommendations of the ACC staff, RUCO, and other parties offering similar recommendations.
      Request for Proposals
     In early December 2003, APS issued a request for proposals (“RFP”) for long-term power supply resources, and on January 8, 2004, an ACC Administrative Law Judge issued an order requiring, among other things, APS to file a summary of the proposals with the ACC. On January 27, 2004, APS filed a summary of the proposals with the ACC. APS is negotiating with certain of the parties that submitted proposals.
Federal
     In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.
     On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for Standard Market Design for wholesale electric markets. Voluminous comments and reply comments were filed on virtually every aspect of the proposed rule. On April 28, 2003, the FERC Staff issued an additional white paper on the proposed Standard Market Design. The white paper discusses several policy changes to the proposed Standard Market Design, including a greater emphasis on flexibility for regional needs. We cannot currently predict what, if any, impact there may be to the Company if the FERC adopts the proposed rule or any modifications proposed in the comments.
General
     The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.
4.     Income Taxes
     Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements. 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 related to income taxes on its Balance Sheets in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. APS amortizes this amount as the differences reverse. In accordance with ACC settlement agreements, APS is continuing to accelerate
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amortization of a regulatory asset related to income taxes over an eight-year period that will end June 30, 2004 (see Note 1). Accordingly, we are including this accelerated amortization in depreciation and amortization expense on our Consolidated Statements of Income.
     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. In 2002, we received an income tax refund of approximately $115 million related to our 2001 federal consolidated income tax return. In 2003, we resolved certain prior-year issues with the taxing authorities and recorded an $18 million tax benefit associated with tax credits and other reductions to income tax expense.
     The components of income tax expense for income from continuing operations are as follows (dollars in thousands): 

 	 	 	Year Ended December 31,	
 	 	 		
 	 	 	2003	 	2002	 	2001	
 	 	 		 		 		
Current:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Federal	 	$	22,875	 	 	$	(43,492	)	 	$	184,893	 	
 	State	 	 	929	 	 	 	(15,415	)	 	 	45,845	 	
 	 	 	 		 	 	 		 	 	 		 	
Total current	 	 	23,804	 	 	 	(58,907	)	 	 	230,738	 	
Deferred	 	 	81,756	 	 	 	191,135	 	 	 	(17,203	)	
 	 	 	 		 	 	 		 	 	 		 	
Total income tax expense	 	$	105,560	 	 	$	132,228	 	 	$	213,535	 	
 	 	 	 		 	 	 		 	 	 		 	
     The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands): 

 	 	 	Year Ended December 31,	
 	 	 		
 	 	 	2003	 	2002	 	2001	
 	 	 		 		 		
Federal income tax expense at 35% statutory rate	 	$	117,648	 	 	$	118,449	 	 	$	189,316	 	
Increases (reductions) in tax expense resulting from:	 	 	 	 	 	 	 	 	 	 	 	 	
 	State income tax net of federal income tax benefit	 	 	14,353	 	 	 	15,796	 	 	 	23,353	 	
 	Credits and favorable adjustments related to prior years resolved in 2003	 	 	(17,944	)	 	 	—	 	 	 	—	 	
 	Allowance for equity funds used during construction (see Note 1)	 	 	(5,616	)	 	 	—	 	 	 	—	 	
 	Other	 	 	(2,881	)	 	 	(2,017	)	 	 	866	 	
 	 	 		 	 	 		 	 	 		 	
Income tax expense	 	$	105,560	 	 	$	132,228	 	 	$	213,535	 	
 	 	 		 	 	 		 	 	 		 	
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     The following table sets forth the net deferred income tax liability recognized on the Consolidated Balance Sheets (dollars in thousands):

 	 	December 31,	
 	 		
 	 	2003	 	2002	
 	 		 		
Current asset/(liability)	 	$	(631	)	 	$	4,094	 	
Long term liability	 	 	(1,329,253	)	 	 	(1,209,074	)	
 	 	 		 	 	 		 	
Accumulated deferred income taxes - net	 	$	(1,329,884	)	 	$	(1,204,980	)	
 	 	 		 	 	 		 	
     The components of the net deferred income tax liability were as follows (dollars in thousands): 

 	 	 	 	December 31,	
 	 	 	 		
 	 	 	 	2003	 	2002	
 	 	 	 		 		
DEFERRED TAX ASSETS	 	 	 	 	 	 	 	 	
 	Pension liability	 	$	73,844	 	 	$	72,835	 	
 	Risk management and trading activities	 	 	59,293	 	 	 	43,542	 	
 	Regulatory liabilities:	 	 	 	 	 	 	 	 	
 	 	Federal excess deferred income taxes	 	 	18,936	 	 	 	20,887	 	
 	 	Other	 	 	33,542	 	 	 	9,818	 	
 	Deferred gain on Palo Verde Unit 2 sale leaseback	 	 	21,656	 	 	 	23,562	 	
 	Other	 	 	64,769	 	 	 	89,236	 	
 	 	 	 		 	 	 		 	
Total deferred tax assets	 	 	272,040	 	 	 	259,880	 	
 	 	 	 		 	 	 		 	
DEFERRED TAX LIABILITIES	 	 	 	 	 	 	 	 	
 	Plant-related	 	 	(1,448,730	)	 	 	(1,316,636	)	
 	Regulatory assets	 	 	(69,070	)	 	 	(101,522	)	
 	Risk management and trading activities	 	 	(84,124	)	 	 	(46,702	)	
 	 	 	 		 	 	 		 	
Total deferred tax liabilities	 	 	(1,601,924	)	 	 	(1,464,860	)	
 	 	 	 		 	 	 		 	
Accumulated deferred income taxes - net	 	$	(1,329,884	)	 	$	(1,204,980	)	
 	 	 	 		 	 	 		 	
5.     Lines of Credit and Short-Term Borrowings
     APS had committed lines of credit with various banks of $250 million at December 31, 2003 and 2002, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The current line matures in May 2004, and the document allows for a 364-day extension of the termination date without lender consent. The commitment fees at December 31, 2003 and 2002 for these lines of credit were 0.175% and 0.09% per annum. APS had no bank borrowings outstanding under these lines of credit at December 31, 2003 and 2002.
     APS had no commercial paper borrowings outstanding at December 31, 2003 and 2002. By Arizona statute, APS’ short-term borrowings cannot exceed 7% of its total capitalization unless approved by the ACC.
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     Pinnacle West had committed lines of credit of $275 million at December 31, 2003 and $475 million at December 31, 2002, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The current lines mature in November and December of 2004 and the $150 million facility allows for a 364-day extension of the termination date without lender consent. Pinnacle West had no outstanding borrowings at December 31, 2003 and $72 million was outstanding at December 31, 2002. The commitment fees ranged from 0.125% to 0.175% in 2003 and ranged from 0.10% to 0.15% in 2002. Pinnacle West had no commercial paper borrowings outstanding at December 31, 2003. Commercial paper borrowings outstanding were $24 million at December 31, 2002. The weighted average interest rate on commercial paper borrowings was 2.06% for the year ended December 31, 2002.
     All APS and Pinnacle West bank lines of credit and commercial paper agreements are unsecured.
     On November 22, 2002, the ACC approved APS’ request to permit APS to make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million. This interim loan matured in December 2003, and there were never any borrowings on this line.
     SunCor had revolving lines of credit totaling $120 million at December 31, 2003 and $140 million at December 31, 2002. The commitment fees were 0.125% in 2003 and 2002. SunCor had $50 million outstanding at December 31, 2003 and $126 million outstanding at December 31, 2002. The weighted-average interest rate was 4.50% at December 31, 2003 and was 3.75% at December 31, 2002. Interest for 2003 and 2002 was based on LIBOR plus 2% or prime plus 0.5%. The balance is included in short-term debt on the Consolidated Balance Sheets. SunCor had other short-term loans in the amount of $36 million at December 31, 2003 and $6 million outstanding at December 31, 2002. These loans are made up of multiple notes primarily with variable interest rates based on LIBOR plus 2.5% at December 31, 2003 and 2002. In addition, two notes acquired in 2003 had interest rates of 3.37% and 3.87%.
6.     Long-Term Debt
     Borrowings under the APS mortgage bond indenture are secured by substantially all utility plant. APS also has unsecured debt. 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, 2003 and 2002 (dollars in thousands):
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 	 	 	 	 	 	 	 	 	 	 	December 31,	
 	 	 	Maturity	 	Interest	 		
 	 	 	Dates (a)	 	Rates	 	2003	 	2002	
 	 	 		 		 		 		
APS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First mortgage bonds	 	 	2004	 	 	 	6.625	%	 	$	80,000	 	 	$	80,000	 	
 	 	 	2023	 	 	 	7.25	%(b)	 	 	—	 	 	 	54,150	 	
 	 	 	2025	 	 	 	8.0	%(c)	 	 	—	 	 	 	33,075	 	
 	 	 	2028	 	 	 	5.5	%	 	 	25,000	 	 	 	25,000	 	
 	 	 	2028	 	 	 	5.875	%	 	 	154,000	 	 	 	154,000	 	
Unamortized discount and premium	 	 	 	 	 	 	 	 	 	 	(8,631	)	 	 	(6,337	)	
Pollution control bonds	 	 	2024-2034	 	 	 	(d	)	 	 	386,860	 	 	 	386,860	 	
Pollution control bonds with senior notes (e)	 	 	2029	 	 	 	5.05	%	 	 	90,000	 	 	 	90,000	 	
Unsecured notes	 	 	2004	 	 	 	5.875	%	 	 	125,000	 	 	 	125,000	 	
Unsecured notes	 	 	2005	 	 	 	6.25	%	 	 	100,000	 	 	 	100,000	 	
Unsecured notes	 	 	2005	 	 	 	7.625	%	 	 	300,000	 	 	 	300,000	 	
Unsecured notes	 	 	2011	 	 	 	6.375	%	 	 	400,000	 	 	 	400,000	 	
Unsecured notes	 	 	2012	 	 	 	6.50	%	 	 	375,000	 	 	 	375,000	 	
Unsecured notes	 	 	2033	 	 	 	5.625	%	 	 	200,000	 	 	 	—	 	
Unsecured notes	 	 	2015	 	 	 	4.650	%	 	 	300,000	 	 	 	—	 	
Senior notes (f)	 	 	2006	 	 	 	6.75	%	 	 	83,695	 	 	 	83,695	 	
Capitalized lease obligations	 	 	2004-2012	 	 	 	(g	)	 	 	11,749	 	 	 	20,400	 	
 	 	 	 	 	 	 	 	 	 		 		
 	Subtotal	 	 	 	 	 	 	 	 	 	 	2,622,673	 	 	 	2,220,843	 	

SUNCOR	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes payable	 	 	2004-2008	 	 	 	(h	)	 	 	17,125	 	 	 	7,647	 	
Capitalized lease obligations	 	 	2004-2005	 	 	 	8.91	%	 	 	728	 	 	 	1,299	 	
 	 	 	 	 	 	 	 	 	 		 		
 	Subtotal	 	 	 	 	 	 	 	 	 	 	17,853	 	 	 	8,946	 	
 	 	 	 	 	 	 	 	 	 		 		
PINNACLE WEST	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Senior notes	 	 	2004-2006	 	 	 	(i	)	 	 	515,000	 	 	 	540,000	 	
Unamortized discount and premium	 	 	 	 	 	 	 	 	 	 	(270	)	 	 	(530	)	
Floating rate notes	 	 	2003	 	 	 	(j	)	 	 	—	 	 	 	250,000	 	
Floating senior notes	 	 	2005	 	 	 	(k	)	 	 	165,000	 	 	 	—	 	
Capitalized lease obligations	 	 	2004-2007	 	 	 	5.48	%	 	 	1,243	 	 	 	1,999	 	
 	 	 	 	 	 	 	 	 	 		 		
 	Subtotal	 	 	 	 	 	 	 	 	 	 	680,973	 	 	 	791,469	 	
 	 	 	 	 	 	 	 	 	 		 		
EL DORADO	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Construction loan	 	 	2005	 	 	 	1.22	%	 	 	1,600	 	 	 	2,600	 	
Capitalized lease obligations	 	 	2004-2005	 	 	 	(l	)	 	 	106	 	 	 	771	 	
 	 	 	 	 	 	 	 	 	 		 		
 	Subtotal	 	 	 	 	 	 	 	 	 	 	1,706	 	 	 	3,371	 	
 	 	 	 	 	 	 	 	 	 		 		
Total long-term debt	 	 	 	 	 	 	 	 	 	 	3,323,205	 	 	 	3,024,629	 	
 	Less current maturities	 	 	 	 	 	 	 	 	 	 	425,480	 	 	 	280,888	 	
 	 	 	 	 	 	 	 	 	 		 		
TOTAL LONG-TERM DEBT	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	LESS CURRENT MATURITIES	 	 	 	 	 	 	 	 	 	$	2,897,725	 	 	$	2,743,741	 	

(a)	 	This schedule does not reflect the timing of redemptions that may occur prior to maturity.	
 		
(b)	 	On August 15, 2003, APS redeemed at maturity $54 million of its First Mortgage Bonds, 7.25% Series due 2023.	
 		
(c)	 	On April 7, 2003, APS redeemed $33 million of its First Mortgage Bonds, 8.00% Series due 2025.	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(d)	 	The weighted-average rate was 1.51% at December 31, 2003 and 1.94% at December 31, 2002. Changes in short-term interest rates would affect the costs associated with this debt.	
 		
(e)	 	On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029, and loaned the proceeds to APS pursuant to a loan agreement. The bonds were issued to refinance $90 million of outstanding pollution control bonds. The bondholders were issued $90 million of first mortgage bonds (senior note mortgage bonds) as collateral.	
 		
(f)	 	APS currently has outstanding $84 million of first mortgage bonds (senior note mortgage bonds) issued to the senior note trustee as collateral for the senior notes, as well as the $90 million issue discussed in footnote (e) above. The senior note mortgage bonds have the same interest rate, interest payment dates, maturity and redemption provisions as the senior notes. APS’ payments of principal, premium and/or interest on the senior notes satisfy its corresponding payment obligations on the senior note mortgage bonds. As long as the senior note mortgage bonds secure the senior notes, the senior notes will effectively rank equally with the first mortgage bonds. When APS repays all of its first mortgage bonds, other than those that secure senior notes, the senior note mortgage bonds will no longer secure the senior notes and will cease to be outstanding.	
 		
(g)	 	The weighted average rate was 5.55% at December 31, 2003 and 5.78% at December 31, 2002. Capital leases are included in property, plant and equipment on the Consolidated Balance Sheets for both December 31, 2003 and December 31, 2002.	
 		
(h)	 	Multiple notes with variable interest rates based on the lenders’ prime plus 0.25%, lenders’ prime plus 1.75% and LIBOR plus 2.5%. There is also one note at a fixed rate of 7.96%.	
 		
(i)	 	Includes two series of notes: $300 million at 6.4% due in 2006 and $215 million at 4.5% due in 2004 as of December 31, 2002. In December 2003, we repaid the $25 million note. On January 29, 2004, we entered into a fixed-for-floating interest rate swap transaction on the $300 million 6.4% note. The transaction qualifies as a fair value hedge under SFAS No. 133.	
 		
(j)	 	The weighted average rate was 2.85% at December 31, 2002. Interest for 2002 was based on LIBOR plus 0.98%. In June 2003, we repaid the $250 million floating note.	
 		
(k)	 	The weighted average rate was 1.980% at December 31, 2003. Interest for 2003 was based on LIBOR plus 0.80%.	
 		
(l)	 	The weighted average rate was 7.9% at December 31, 2003 and 7.04% at December 31, 2002.	
     Pinnacle West’s and APS’ debt covenants related to their respective financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet the covenant requirement levels. The ratio of debt to total capitalization cannot exceed 65% for each of the Company and APS individually. At December 31, 2003, the ratio was approximately 54% for Pinnacle West. At December 31, 2003, the ratio was approximately 53% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for each of the Company and APS. Based on 2003 results, the coverages were approximately 4 times for the Company, 4 times for the APS bank agreements and 15 times for the APS mortgage indenture. 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.
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     Neither Pinnacle West’s nor APS’ financing agreements contain “ratings triggers” that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.
     All of Pinnacle West’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under other 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 other agreements. Pinnacle West’s and APS’ credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in our financial condition or financial prospects.
     The following is a list of payments due on total long-term debt and capitalized lease requirements through 2008:

 	•	 	$425 million in 2004;	
 		
 	•	 	$569 million in 2005;	
 		
 	•	 	$395 million in 2006;	
 		
 	•	 	$2 million in 2007;	
 		
 	•	 	$6 million in 2008; and	
 		
 	•	 	$1,935 million, thereafter.	
     APS’ first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment and other excluded assets). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. APS may pay dividends on its common stock if there is a sufficient amount “available” from retained earnings and the excess of cumulative book depreciation (since the mortgage’s inception) over mortgage depreciation, which is the cumulative amount of additional property pledged each year to address collateral depreciation. As of December 31, 2003, the amount “available” under the mortgage would have allowed APS to pay approximately $3 billion of dividends compared to APS’ current annual common stock dividends of $170 million.
     The mortgage currently constitutes a lien on substantially all of the property of APS. We anticipate that in early April 2004, all first mortgage bonds issued by APS under its existing mortgage and deed of trust, other than the first mortgage bonds securing APS’ senior notes, will have been paid and retired. At that time, APS’ obligation to make payment on the first mortgage bonds securing the senior notes will also be deemed to be satisfied and discharged and the senior note first mortgage bonds will cease to secure the senior notes. APS is then obligated to take all steps necessary to terminate its existing mortgage and deed of trust and cannot issue any additional first mortgage bonds under that mortgage.
7.     Common Stock and Treasury Stock
     Our common stock and treasury stock activity during each of the three years 2003, 2002 and 2001 is as follows (dollars in thousands):
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 	 	 	Common Stock	 	Treasury Stock	
 	 	 		 		
 	 	 	Shares	 	Amount	 	Shares	 	Amount	
 	 	 		 		 		 		
Balance at December 31, 2000	 	 	84,824,947	 	 	$	1,537,920	 	 	 	(109,638	)	 	$	(5,089	)	
 	Purchase of treasury stock	 	 	—	 	 	 	—	 	 	 	(334,600	)	 	 	(16,393	)	
 	Reissuance of treasury stock for stock compensation (net)	 	 	—	 	 	 	—	 	 	 	342,931	 	 	 	15,596	 	
 	Other	 	 	—	 	 	 	(996	)	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Balance at December 31, 2001	 	 	84,824,947	 	 	 	1,536,924	 	 	 	(101,307	)	 	 	(5,886	)	
 	Common stock issuance - December 23, 2002	 	 	6,555,000	 	 	 	199,238	 	 	 	—	 	 	 	—	 	
 	Purchase of treasury stock	 	 	—	 	 	 	—	 	 	 	(150,500	)	 	 	(5,971	)	
 	Reissuance of treasury stock for stock compensation (net)	 	 	—	 	 	 	—	 	 	 	126,977	 	 	 	7,499	 	
 	Other	 	 	—	 	 	 	1,096	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Balance at December 31, 2002	 	 	91,379,947	 	 	 	1,737,258	 	 	 	(124,830	)	 	 	(4,358	)	
 	Reissuance of treasury stock for stock compensation (net)	 	 	—	 	 	 	—	 	 	 	32,815	 	 	 	1,085	 	
 	Other	 	 	—	 	 	 	7,096	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Balance at December 31, 2003	 	 	91,379,947	 	 	$	1,744,354	 	 	 	(92,015	)	 	$	(3,273	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
8.     Retirement Plans and Other Benefits
     Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. Effective January 1, 2003, Pinnacle West sponsored a new account balance plan for all new employees in place of the defined benefit plan, and, as of April 1, 2003, the plan was offered as an alternative to the defined benefit plan for all existing employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all of our employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. Generally, we calculate the benefits based on age, years of service and pay.
     Pinnacle West also sponsors other postretirement benefits for the employees of Pinnacle West and our subsidiaries. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.
     In December 2003, FASB revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to enhance disclosures of relevant accounting information by
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providing additional information on plan assets, obligations, cash flows, and net cost. The revisions are reflected in this Note. Pinnacle West uses a December 31 measurement date for its plans.
     On December 8, 2003, the President signed the “Medicare Prescription Drug, Improvement and Modernization Act of 2003” (the Act). One feature of the Act is a government subsidy of prescription drug costs. We have not yet quantified the effect, if any, on accumulated projected benefit obligation or the net periodic postretirement benefit cost in our financial statements and accompanying notes. Specific accounting guidance for this subsidy, including transition rules, is pending.
     The following table provides details of the plan’s 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	
 	 	 		 		
 	 	 	2003	 	2002	 	2001	 	2003	 	2002	 	2001	
 	 	 		 		 		 		 		 		
Service cost-benefits earned during the period	 	$	37,662	 	 	$	30,333	 	 	$	27,640	 	 	$	15,858	 	 	$	12,036	 	 	$	9,438	 	
Interest cost on benefit obligation	 	 	76,951	 	 	 	71,242	 	 	 	66,549	 	 	 	30,163	 	 	 	25,235	 	 	 	21,585	 	
Expected return on plan assets	 	 	(65,046	)	 	 	(75,652	)	 	 	(77,340	)	 	 	(18,762	)	 	 	(21,116	)	 	 	(21,985	)	
Amortization of:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Transition (asset)/obligation	 	 	(3,227	)	 	 	(3,227	)	 	 	(3,227	)	 	 	3,005	 	 	 	4,001	 	 	 	7,698	 	
 	Prior service cost/(credit)	 	 	2,401	 	 	 	2,912	 	 	 	3,008	 	 	 	(125	)	 	 	(75	)	 	 	—	 	
 	Net actuarial loss/(gain)	 	 	18,135	 	 	 	1,846	 	 	 	907	 	 	 	9,714	 	 	 	3,072	 	 	 	(4,066	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net periodic benefit cost	 	$	66,876	 	 	$	27,454	 	 	$	17,537	 	 	$	39,853	 	 	$	23,153	 	 	$	12,670	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Portion of cost charged to expense	 	$	30,094	 	 	$	13,727	 	 	$	8,944	 	 	$	17,934	 	 	$	11,577	 	 	$	6,462	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
     The following table sets forth the plan’s change in the benefit obligations for the plan years 2003 and 2002 (dollars in thousands):
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 	 	 	Pension	 	Other Benefits	
 	 	 		 		
 	 	 	2003	 	2002	 	2003	 	2002	
 	 	 		 		 		 		
Benefit obligation at January 1	 	$	1,069,577	 	 	$	931,646	 	 	$	409,874	 	 	$	318,355	 	
Service cost	 	 	37,662	 	 	 	30,333	 	 	 	15,858	 	 	 	12,036	 	
Interest cost	 	 	76,951	 	 	 	71,242	 	 	 	30,163	 	 	 	25,235	 	
Benefit payments	 	 	(43,869	)	 	 	(35,230	)	 	 	(15,749	)	 	 	(10,473	)	
Actuarial losses	 	 	171,420	 	 	 	71,696	 	 	 	106,475	 	 	 	108,979	 	
Plan amendments	 	 	(4,113	)	 	 	(110	)	 	 	(6,440	)	 	 	(44,258	)(a)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Benefit obligation at December 31	 	$	1,307,628	 	 	$	1,069,577	 	 	$	540,181	 	 	$	409,874	 	

(a)	 	The plan was amended in January 2002 to increase the deductibles, out-of-pocket maximums and prescription drug co-pays. The plan was amended in June 2002 to increase the participants’ portion of premiums.	
     The following table sets forth the qualified defined benefit plan and other benefit plan changes in the fair value of plan assets for the years 2003 and 2002 (dollars in thousands): 

 	 	Pension	 	Other Benefits	
 	 		 		
 	 	2003	 	2002	 	2003	 	2002	
 	 		 		 		 		
Fair value of plan assets at January 1	 	$	720,807	 	 	$	764,873	 	 	$	223,474	 	 	$	237,810	 	
Actual gain/(loss) on plan assets	 	 	162,571	 	 	 	(36,966	)	 	 	46,071	 	 	 	(27,802	)	
Employer contributions	 	 	46,000	 	 	 	26,600	 	 	 	39,852	 	 	 	23,600	 	
Benefit payments	 	 	(42,067	)	 	 	(33,700	)	 	 	(15,346	)	 	 	(10,134	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Fair value of plan assets at December 31	 	$	887,311	 	 	$	720,807	 	 	$	294,051	 	 	$	223,474	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
     The following table shows a reconciliation of the funded status of the plans to the amounts recognized in the Consolidated Balance Sheets as of December 31, 2003 and 2002 (dollars in thousands): 

 	 	Pension	 	Other Benefits	
 	 		 		
 	 	2003	 	2002	 	2003	 	2002	
 	 		 		 		 		
Funded status at December 31	 	$	(420,317	)	 	$	(348,770	)	 	$	(246,130	)	 	$	(186,400	)	
Unrecognized net transition (asset)/ obligation	 	 	(7,099	)	 	 	(10,327	)	 	 	27,044	 	 	 	36,489	 	
Unrecognized prior service cost/(credit)	 	 	16,634	 	 	 	23,148	 	 	 	(1,547	)	 	 	(1,673	)	
Unrecognized net actuarial losses/(gains)	 	 	348,982	 	 	 	293,223	 	 	 	217,611	 	 	 	148,268	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Benefit liability recognized in the Consolidated Balance Sheet	 	$	(61,800	)	 	$	(42,726	)	 	$	(3,022	)	 	$	(3,316	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
     The following sets forth the details related to benefits included on the Consolidated Balance Sheets (dollars in thousands):
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 	 	Pension	 	Other Benefits	
 	 		 		
 	 	2003	 	2002	 	2003	 	2002	
 	 		 		 		 		
Accrued benefit cost	 	$	(61,800	)	 	$	(42,726	)	 	$	(3,022	)	 	$	(3,316	)	
Additional minimum liability	 	 	(126,241	)	 	 	(141,154	)	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Total liability	 	 	(188,041	)	 	 	(183,880	)	 	 	(3,022	)	 	 	(3,316	)	
Intangible asset	 	 	16,634	 	 	 	23,147	 	 	 	—	 	 	 	—	 	
Accumulated other comprehensive income (pretax)	 	 	109,607	 	 	 	118,007	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Net amount recognized	 	$	(61,800	)	 	$	(42,726	)	 	$	(3,022	)	 	$	(3,316	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
     The following table sets forth the other comprehensive income arising from the change in additional minimum liability for the years ended December 31, 2003 and 2002 (dollars in thousands): 

 	 	2003	 	2002	
 	 		 		
Decrease/(Increase) in minimum liability included in other comprehensive income — net of tax	 	$	4,700	 	 	$	(70,298	)	
     The following table sets forth the projected benefit obligation and the accumulated benefit obligation for pension plans in excess of plan assets for the plan years 2003 and 2002 (dollars in thousands): 

 	 	2003	 	2002	
 	 		 		
Projected benefit obligation	 	$	1,307,628	 	 	$	1,069,577	 	
 	 	 		 	 	 		 	
Accumulated benefit obligation	 	$	1,075,352	 	 	$	904,687	 	
Less fair value of plan assets	 	 	887,311	 	 	 	720,807	 	
 	 	 		 	 	 		 	
Pension liability	 	$	188,041	 	 	$	183,880	 	
 	 	 		 	 	 		 	
     Below are the weighted-average assumptions for both the pension and other benefits used to determine each respective benefit obligation and net periodic benefit cost: 

 	 	 	 	 	 	 	 	 	 	Benefit Costs	
 	 	Benefit Obligations	 	For the Years Ended	
 	 	As of December 31,	 	December 31,	
 	 		 		
 	 	2003	 	2002	 	2003	 	2002	
 	 		 		 		 		
Discount rate	 	 	6.10	%	 	 	6.75	%	 	 	6.75	%	 	 	7.50	%	
Rate of compensation increase	 	 	4.00	%	 	 	4.00	%	 	 	4.00	%	 	 	4.00	%	
Expected long-term return on plan assets	 	 	9.00	%	 	 	9.00	%	 	 	9.00	%	 	 	10.00	%	
Initial health care cost trend rate	 	 	8.00	%	 	 	8.00	%	 	 	8.00	%	 	 	7.00	%	
Ultimate health care cost trend rate	 	 	5.00	%	 	 	5.00	%	 	 	5.00	%	 	 	5.00	%	
Year ultimate health care trend rate is reached	 	 	2008	 	 	 	2007	 	 	 	2007	 	 	 	2006	 	
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     In selecting the pretax expected long-term rate of return on plan assets we consider past performance and economic forecasts for the types of investments held by the plan. For the year 2003, we decreased our pretax expected long-term rate of return on plan assets from 10% to 9%, as a result of continued declines in general equity and bond market conditions. For the year 2004 we are assuming a 9% rate of return on plan assets. This rate is reflective of the market returns earned historically on our target asset allocation. As recent history has demonstrated, markets may decline and increase dramatically. However, the long-term rate of return on plan assets of 9% is reasonable given our asset allocation in relation to historical and expected future performance.
     Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in the assumed initial and ultimate health care cost trend rates would have the following effects (dollars in millions): 

 	 	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	 	$	9	 	 	 	($7	)	
Effect on the accumulated other postretirement benefit obligation	 	$	95	 	 	 	($76	)	
Plan Assets
     Pinnacle West’s qualified pension plan asset allocation at December 31, 2003, and 2002 is as follows:

 	 	Percentage of Plan Assets	
 	 	at December 31,	
 	 		
 	 	2003	 	2002	 	Target Asset Allocation	
 	 		 		 		
Asset Category:	 	 	 	 	 	 	 	 	 	 	 	 	
Equity securities	 	 	65	%	 	 	56	%	 	 	50 - 70	%	
Debt securities	 	 	23	 	 	 	31	 	 	 	20 - 40	%	
Other	 	 	12	 	 	 	13	 	 	 	5 - 15	%	
 	 	 		 	 	 		 	 	 	 	 	
Total	 	 	100	%	 	 	100	%	 	 	 	 	
 	 	 		 	 	 		 	 	 	 	 	
     The Board of Directors has established an investment policy for the pension plan assets and has delegated oversight of the plan assets to an Investment Management Committee. The investment policy sets forth the objective of providing for future pension benefits by maximizing return consistent with a stated tolerance 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.
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     Pinnacle West’s other postretirement benefit plan asset allocation at December 31, 2003, and 2002, is as follows:

 	 	Percentage of Plan Assets	 	 	 	 	
 	 	at December 31,	 	 	 	 	
 	 		 	 	 	 	
 	 	2003	 	2002	 	Target Asset Allocation	
 	 		 		 		
Asset Category :	 	 	 	 	 	 	 	 	 	 	 	 	
Equity securities	 	 	71	%	 	 	62	%	 	 	60 - 80	%	
Fixed Income	 	 	25	 	 	 	34	 	 	 	20 - 35	%	
Other	 	 	4	 	 	 	4	 	 	 	1 - 6	%	
 	 	 		 	 	 		 	 	 	 	 	
Total	 	 	100	%	 	 	100	%	 	 	 	 	
 	 	 		 	 	 		 	 	 	 	 	
     The Investment Management Committee, described above, has also been delegated oversight of the plan assets for the postretirement benefit plans. The investment policy for other post retirement benefit plan assets is similar to that of the pension plan assets described above.
Contributions
     Under current law, we are required to contribute approximately $100 million to our pension plans in 2004 and expect to contribute approximately $50 million to our other postretirement benefit plans in 2004. If currently pending legislation is enacted, our required pension contribution in 2004 would decrease to the $25 to $50 million range.
Employee Savings Plan Benefits
     Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and subsidiaries. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account. Under this plan, the Company matches a percentage of the participants’ contributions in the form of Pinnacle West stock. After a five year vesting period, participants have an option to transfer the Company matching contributions out of the Pinnacle West Stock Fund to other investment funds within the plan. At December 31, 2003, approximately 23% of total plan assets were in Pinnacle West stock. We recorded expenses for this plan of approximately $5 million for each of the years 2003, 2002 and 2001.
Severance Charges
     In July 2002, we implemented a voluntary workforce reduction as part of our cost reduction program. We recorded $36 million before taxes in voluntary severance costs in 2002. No further charges are expected.
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
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amortized to operations and maintenance expense over 29.5 years, the original term of the leases. There are options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. Consistent with the ratemaking treatment, a regulatory asset is recognized for the difference between lease payments and rent expense calculated on a straight-line basis. See Note 20 for a discussion of VIEs, including the SPEs 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 $67 million in 2003, $67 million in 2002 and $59 million in 2001.
     The amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2004 to 2015.
     In accordance with the 1999 Settlement Agreement and previous settlement agreements, APS is continuing to accelerate amortization of the regulatory asset for leases over an eight-year period that will end June 30, 2004 (see Note 1). All regulatory asset amortization is included in depreciation and amortization expense in the Consolidated Statements of Income. The balance of this regulatory asset at December 31, 2003 was $5 million.
     Estimated future minimum lease payments for our operating leases are approximately as follows (dollars in millions): 

Year	 	 	 	 	
 	 	2004	 	$	73	 	
 	 	2005	 	 	70	 	
 	 	2006	 	 	68	 	
 	 	2007	 	 	66	 	
 	 	2008	 	 	66	 	
 	Thereafter	 	 	421	 	
 	 	 	 	 		 	
Total future lease commitments	 	$	764	 	
 	 	 	 	 		 	
10.     Jointly-Owned Facilities
     APS shares ownership of some of its generating and transmission facilities with other companies. The following table shows APS’ interest in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2003. APS’ share of operating and maintaining these facilities is included in the Consolidated Statements of Income in operations and maintenance expense (dollars in thousands):
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 	 	 	 	Percent	 	 	 	 	 	 	 	 	 	Construction	
 	 	 	 	Owned by	 	Plant in	 	Accumulated	 	Work in	
 	 	 	 	APS	 	Service	 	Depreciation	 	Progress	
 	 	 	 		 		 		 		
Generating facilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Palo Verde Nuclear Generating Station	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Units 1 and 3	 	 	29.1	%	 	$	1,880,218	 	 	$	(867,322	)	 	$	21,620	 	
 	Palo Verde Nuclear Generating Station Unit 2 (see Note 9)	 	 	17.0	%	 	 	681,744	 	 	 	(242,131	)	 	 	9,771	 	
 	Four Corners Steam Generating Station Units 4 and 5	 	 	15.0	%	 	 	154,111	 	 	 	(81,369	)	 	 	2,580	 	
 	Navajo Steam Generating Station Units 1, 2 and 3	 	 	14.0	%	 	 	242,987	 	 	 	(111,744	)	 	 	2,352	 	
 	Cholla Steam Generating Station Common Facilities (a)	 	 	62.4	%(b)	 	 	78,500	 	 	 	(44,379	)	 	 	1,338	 	
Transmission facilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	ANPP 500KV System	 	 	35.8	%(b)	 	 	68,457	 	 	 	(27,050	)	 	 	40	 	
 	Navajo Southern System	 	 	31.4	%(b)	 	 	26,903	 	 	 	(17,971	)	 	 	128	 	
 	Palo Verde — Yuma 500KV System	 	 	23.9	%(b)	 	 	9,583	 	 	 	(4,364	)	 	 	602	 	
 	Four Corners Switchyards	 	 	27.5	%(b)	 	 	2,852	 	 	 	(1,734	)	 	 	—	 	
 	Phoenix — Mead System	 	 	17.1	%(b)	 	 	36,418	 	 	 	(3,567	)	 	 	—	 	
 	Palo Verde — Estrella 500KV System	 	 	55.5	%(b)	 	 	70,972	 	 	 	(1,615	)	 	 	1,632	 	
 	Palo Verde SE Valley Project	 	 	15.0	%(b)	 	 	—	 	 	 	—	 	 	 	648	 	

(a)	 	PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned.	
 		
(b)	 	Weighted average of interests.	
11.     Commitments and Contingencies
Enron
     We recorded charges totaling $21 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. This amount is comprised of a $15 million reserve for the Company’s net exposure to Enron and its affiliates and additional expenses of $6 million primarily related to 2002 power contracts with Enron that were canceled. These charges take into consideration our rights of set-off with respect to the Enron related contractual obligations. The APS portion of the write-off was $13 million. The basis of the set-offs included, but was not limited to, provisions in the various contractual arrangements with Enron and its affiliates, including an International Swaps and Derivative Agreement (ISDA) between APS and Enron North America. The write-off is also net of the expected recovery based on secondary market quotes from the bond market. The amounts were written-off from the balances of the related assets and liabilities from risk management and trading activities on the Consolidated Balance Sheets. In February 2004, Enron filed an adversary proceeding against APS in bankruptcy court regarding differences in the valuation of trading positions involving APS. Enron North America v. Arizona Public Service Company , Adversary Proceeding No. 04-02366 (ALJ). APS will vigorously defend this action and does not believe it will have any material adverse impact on its anticipated exposure to Enron described above.
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Palo Verde Nuclear Generating Station
      Spent 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 Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. Arizona Public Service Company v. United States of America , United States Court of Federal Claims, 03-2832C.
     In February 2002, the Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a permanent repository for spent nuclear fuel. The President transmitted this recommendation to Congress and the State of Nevada vetoed the President’s recommendation. Congress approved the Yucca Mountain site, overriding the Nevada veto. It is now expected that the DOE will submit a license application to the NRC in late 2004. The State of Nevada has filed several lawsuits relating to the Yucca Mountain site. We cannot currently predict what further steps will be taken in this area.
     APS has existing fuel storage pools at Palo Verde and is operating a new facility for on-site dry storage of spent nuclear fuel. With the existing storage pools and the addition of the new facility, APS believes spent nuclear fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.
     Although some low-level waste has been stored on-site in a low-level waste facility, APS is currently shipping low-level waste to off-site facilities. APS currently believes interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.
     APS currently estimates it will incur $115 million (in 2003 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2003, APS had spent $7 million and recorded a liability of $42 million for on-site interim spent nuclear fuel storage costs related to nuclear fuel burned to date. APS has recorded a corresponding regulatory asset of $49 million and is seeking recovery of these costs through future rates (see “APS General Rate Case and Retail Rate Mechanisms” in Note 3).
     APS has reclassified prior year spent nuclear fuel costs of approximately $44 million previously included in accumulated amortization of nuclear fuel to the liability for asset retirements and removals on our Consolidated Balance Sheets at December 31, 2002. Upon adoption of SFAS No. 143 in 2003, APS reclassified this liability to a regulatory liability because no legal obligation for removal exists.
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     APS believes that scientific and financial aspects of the issues of spent nuclear fuel and low-level waste storage and disposal can be resolved satisfactorily. However, APS acknowledges that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which APS is less able to predict. APS expects to vigorously protect and pursue its rights related to this matter.
      Nuclear Insurance
     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $10 million per incident. 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 $9 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 outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
Purchased Power and Fuel Commitments
     APS and Pinnacle West are parties to various purchased power and fuel contracts with terms expiring from 2004 through 2025 that include required purchase provisions. We estimate the contract requirements to be approximately $209 million in 2004; $68 million in 2005; $66 million in 2006; $51 million in 2007; $51 million in 2008 and $461 million thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances.
     Of the various purchased power and fuel contracts mentioned above some of those contracts have take-or-pay provisions. The contracts APS has for the supply of its coal and nuclear fuel supply have take-or-pay provisions. The current take-or-pay coal contracts have terms that expire in 2016. The current take-or-pay nuclear fuel contracts expire in 2004 and had not been renewed as of December 31, 2003.
     The following table summarizes the estimated take-or-pay commitments for the existing terms (dollars in millions):
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 	 	 	 	 	 	 	 	 	 	Estimated	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Years Ending December 31,	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 		 	 	 	 	 	 	 	 	
 	 	2004	 	2005	 	2006	 	2007	 	2008	 	Thereafter	
 	 		 		 		 		 		 		
Coal	 	 	41	 	 	 	42	 	 	 	43	 	 	 	44	 	 	 	43	 	 	 	306	 	
Nuclear	 	 	11	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total take-or-pay commitments (a)	 	$	52	 	 	$	42	 	 	$	43	 	 	$	44	 	 	$	43	 	 	$	306	 	

(a)	 	Total take-or-pay commitments are approximately $530 million. The total net present value of these commitments is approximately $340 million.	
Coal Mine Reclamation Obligations
     APS must reimburse certain coal providers for amounts incurred for coal mine reclamation. Our coal mine reclamation obligation was $60 million at December 31, 2003 and $59 million at December 31, 2002 and is included in deferred credits-other in the Consolidated Balance Sheets.
     A regulatory asset has been established for amounts not yet recovered from ratepayers related to the coal obligations. In accordance with the 1999 Settlement Agreement with the ACC, APS is continuing to accelerate the amortization of the regulatory asset for coal mine reclamation over an eight-year period that will end June 30, 2004. Amortization is included in depreciation and amortization expense on the Consolidated Statements of Income.
California Energy Market Issues and Refunds in the Pacific Northwest
     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. APS does not anticipate material changes in its exposure and still believes, subject to the finalization of the revised proxy prices, that it will be entitled to a net refund.
     The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Court of Appeals (Ninth Circuit).
     Although the FERC ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity.
     On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its Staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions
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that allegedly violated certain provisions of the ISO tariff. APS and the FERC staff have settled this matter, and the settlement was approved by the FERC.
     SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the ISO. PG&E filed for bankruptcy protection in 2001.
     We are closely monitoring developments in the California energy market and the potential impact of these developments on us and our subsidiaries. Based on our evaluations, we previously reserved $10 million before income taxes for our credit exposure related to the California energy situation, $5 million of which was recorded in the fourth quarter of 2000 and $5 million of which was recorded in the first quarter of 2001. Our evaluations took into consideration our range of exposure of approximately zero to $38 million before income taxes and a review of likely recovery rates in bankruptcy situations.
     In the second quarter of 2002, PG&E filed its Modified Second Amended Disclosure Statement and the CPUC filed its Alternative Plan of Reorganization. Both plans generally indicated that PG&E would, at the close of bankruptcy proceedings, be able to pay in full all outstanding, undisputed debts. As a result of these developments, the probable range of our total exposure now is approximately zero to $27 million before income taxes, and our best estimate of the probable loss is now approximately $6 million before income taxes. Consequently, we reversed $4 million of the $10 million reserve in the second quarter of 2002. We cannot predict with certainty, however, the impact that any future resolution or attempted resolution, of the California energy market situation may have on us, our subsidiaries or the regional energy market in general.
      California Energy Market Litigation 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. State of California v. British Columbia Power Exchange et al ., Docket No. EL02-71-000. 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 has been dismissed by the FERC and the State of California is now appealing the matter to the Ninth Circuit Court of Appeals. In addition, the State of California and others have filed various claims, which have now been consolidated, against several power suppliers to California alleging antitrust violations. Wholesale Electricity Antitrust Cases I and II , Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and California independent system operator markets, including APS, attempting to expand those matters to such other participants. APS has not yet filed a responsive pleading in the matter, but APS believes the claims by Reliant and Duke as they relate to APS are without merit.
     APS was also named in a lawsuit regarding wholesale contracts in California, which has now been moved back to state court. James Millar, et al. v. Allegheny Energy Supply, et al ., San Francisco Superior Court, Case No. 407867. The First Amended Complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market, in violation of California
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unfair competition laws. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against APS and numerous other PX participants. Cal PX v. The State of California , Superior Court in and for the County of Sacramento, JCCP No. 4203. Various motions continue to be filed, and we currently believe these claims will have no material adverse impact on our financial position, results of operations or liquidity.
Citizens Power Service Agreement
     By letter dated March 7, 2001, Citizens, which owns a utility in Arizona, advised APS that it believes APS overcharged Citizens by over $50 million under a power service agreement. APS believes its charges under the agreement were fully in accordance with the terms of the agreement. In addition, in testimony filed with the ACC on March 13, 2002, Citizens acknowledged, based on its review, “if Citizens filed a complaint with the FERC, it probably would lose the central issue in the contract interpretation dispute.” APS and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, the Company and Citizens entered into a power sale agreement under which the Company will supply Citizens with future specified amounts of electricity and ancillary services through May 31, 2008. This new agreement does not address issues previously raised by Citizens with respect to charges under the original power service agreement through June 1, 2001. 
Construction Program
     Consolidated capital expenditures in 2004 are estimated to be (dollars in millions):

APS	 	$	426	 	
Pinnacle West Energy	 	 	61	 	
SunCor	 	 	83	 	
Other (primarily APS Energy Services and Pinnacle West)	 	 	11	 	
 	 	 		 	
 	Total	 	$	581	 	
 	 	 		 	
Natural Gas Supply
     APS and Pinnacle West Energy purchase the majority of their natural gas requirements for their gas-fired plants under contracts with a number of natural gas suppliers. Effective September 1, 2003, APS’ and Pinnacle West Energy’s natural gas supply is transported pursuant to a firm, contract demand service agreement with El Paso Natural Gas Company. Pursuant to the terms of a comprehensive settlement entered into in 1996, the rates charged for transportation are subject to a 10-year rate moratorium extending through December 31, 2005.
     Prior to September 1, 2003, APS’ and Pinnacle West Energy’s natural gas supply was transported pursuant to a firm, full requirements transportation service agreement. On July 9, 2003 the FERC issued an order that altered the contractual obligations and the rights of parties to the 1996 settlement by requiring all firm, full requirements contract holders to convert to contract demand service agreements effective September 1, 2003. This required conversion has imposed additional
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limitations on the former full requirements contract holders’ ability to nominate firm transportation capacity. In order for APS and Pinnacle West Energy to meet their natural gas supply and capacity requirements, they must make market purchases, which we expect to increase costs by approximately $5 million per year for natural gas supply and by approximately $14 million per year for capacity. APS and Pinnacle West Energy have sought appellate review of the FERC’s July 9 order and related issues on the grounds that the FERC decision to abrogate the full requirements contracts is arbitrary and capricious and is not supported by substantial evidence. Arizona Public Service Company and Pinnacle West Energy Corporation v. Federal Energy Regulatory Commission , United States Court of Appeals for the District of Columbia Circuit, No. 03-1209. This petition for review was consolidated with a petition filed by the ACC and other full requirements contract holders. Arizona Corporation Commission et al v. Federal Energy Regulatory Commission , United States Court of Appeals for the District of Columbia Circuit, No. 03-1206. We are continuing to analyze the market to determine the most favorable source and method of meeting our natural gas requirements.
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 consolidated financial statements, results of operations or liquidity.

12.	 	Asset Retirement Obligations	
     On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The standard requires that these liabilities be 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. Prior to January 1, 2003, we accrued asset retirement obligations over the life of the related asset through depreciation expense.
     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. The asset retirement obligations associated with our non-regulated assets are immaterial.
     On January 1, 2003 and in accordance with SFAS No. 143, APS recorded a liability of $219 million for its asset retirement obligations, including the accretion impacts; a $67 million increase in
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the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, APS recorded a net regulatory liability of $40 million for the asset retirement obligations related to its regulated assets. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. APS believes it can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143. The adoption of SFAS No. 143 did not have a material impact on our net income for the year ended December 31, 2003.
     APS has reclassified prior year removal costs of approximately $557 million previously included in accumulated depreciation to the liability for asset retirements and removals on our Consolidated Balance Sheets. In 2003, APS reclassified the portion of this liability for which no legal obligation for removal exists to a regulatory liability.
     In accordance with SFAS No. 71, APS will continue to accrue for removal costs for its regulated assets, even if there is no legal obligation for removal. At December 31, 2003, regulatory liabilities shown on our Consolidated Balance Sheets included approximately $480 million of estimated future removal costs that are not considered legal obligations.
     The following schedule shows the change in our asset retirement obligations during the twelve-month period ended December 31, 2003 (dollars in millions): 

Balance at January 1, 2003	 	$	219	 	
 	Changes attributable to:	 	 	 	 	
 	 	Liabilities incurred	 	 	—	 	
 	 	Liabilities settled	 	 	—	 	
 	 	Accretion expense	 	 	15	 	
 	 	Estimated cash flow revisions	 	 	—	 	
 	 	 		 	
Balance at December 31, 2003	 	$	234	 	
 	 	 		 	
     The following schedule shows the change in our pro forma liability for the years ended December 31, 2002 and 2001, as if we had recorded an asset retirement obligation based on the guidance in SFAS No. 143 (dollars in millions): 

 	 	 	2002	 	2001	
 	 	 		 		
Balance at beginning of year	 	$	204	 	 	$	190	 	
 	Accretion expense	 	 	15	 	 	 	14	 	
 	 	 		 	 	 		 	
Balance at end of year	 	$	219	 	 	$	204	 	
 	 	 		 	 	 		 	
     The pro forma effects on net income for 2002 and 2001 are immaterial.
     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income and domestic equity securities and classifies them as available for sale. The following
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table shows the cost and fair value of APS’ nuclear decommissioning trust fund assets which are on the Consolidated Balance Sheets at December 31, 2003 and December 31, 2002 (dollars in millions):

 	 	 	December 31, 2003	 	December 31, 2002	
 	 	 		 		
Trust fund assets – at cost	
 	Fixed income securities	 	$	124	 	 	$	113	 	
 	Domestic stock	 	 	74	 	 	 	68	 	
 	 	 		 	 	 		 	
Total	 	$	198	 	 	$	181	 	
 	 	 		 	 	 		 	
Trust fund assets – at fair value	
 	Fixed income securities	 	$	140	 	 	$	117	 	
 	Domestic stock	 	 	101	 	 	 	77	 	
 	 	 		 	 	 		 	
Total	 	$	241	 	 	$	194	 	

13.	 	Selected Quarterly Financial Data (Unaudited)	
     Consolidated quarterly financial information for 2003 and 2002 is as follows (dollars in thousands, except per share amounts): 

 	 	 	Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	Income From	 	 	 	 	
 	 	 	as Previously	 	Reclassification	 	 	 	 	 	 	 	 	 	Continuing	 	Net	
 	 	 	Disclosed (a)	 	Adjustment (b)	 	Operating Revenues	 	Operating Income	 	Operations	 	Income (d)	
 	 	 		 		 		 		 		 		
2003 Quarter ended:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	March 31,	 	$	603,962	 	 	$	51,319	 	 	$	552,643	 	 	$	69,255	 	 	$	20,153	 	 	$	25,298	 	
 	June 30,	 	 	757,483	 	 	 	74,181	 	 	 	683,302	 	 	 	132,482	 	 	 	54,889	 	 	 	56,142	 	
 	September 30,	 	 	946,570	 	 	 	98,867	 	 	 	847,703	 	 	 	198,850	 	 	 	109,538	 	 	 	110,048	 	
 	December 31,	 	 	734,204	 	 	 	—	 	 	 	734,204	 	 	 	81,466	 	 	 	45,996	 	 	 	49,091	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total	 	 	 	 	 	$	224,367	 	 	$	2,817,852	 	 	$	482,053	 	 	$	230,576	 	 	$	240,579	 	

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Income	 	 	 	 	
 	 	 	Operating Revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	(Loss) From	 	Net	
 	 	 	as Previously	 	Reclassification	 	 	 	 	 	 	 	 	 	Continuing	 	Income	
 	 	 	Disclosed (a)	 	Adjustment (b)(c)	 	Operating Revenues	 	Operating Income	 	Operations	 	(Loss) (d)	
 	 	 		 		 		 		 		 		
2002 Quarter ended:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	March 31,	 	$	499,844	 	 	$	16,365	 	 	$	483,479	 	 	$	118,736	 	 	$	53,251	 	 	$	53,757	 	
 	June 30,	 	 	593,516	 	 	 	18,962	 	 	 	574,554	 	 	 	155,832	 	 	 	68,803	 	 	 	75,365	 	
 	September 30,	 	 	871,390	 	 	 	103,450	 	 	 	767,940	 	 	 	212,491	 	 	 	100,713	 	 	 	100,916	 	
 	December 31, (f)	 	 	644,436	 	 	 	30,121	 	 	 	614,315	 	 	 	13,875	 	 	 	(16,569	)	 	 	(80,630	)(e)	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total	 	 	 	 	 	$	168,898	 	 	$	2,440,288	 	 	$	500,934	 	 	$	206,198	 	 	$	149,408	 	

(a)	 	Operating revenues previously disclosed in the March 31, 2003, June 30, 2003 and September 30, 2003 Quarterly Reports on Form 10-Q, except for the fourth quarter ended December 31, 2003, which was disclosed in a Pinnacle West Form 8-K dated January 29, 2004 and the fourth quarter ended December 31, 2002, which was disclosed in a Pinnacle West Form 8-K dated February 4, 2003.	
 		
(b)	 	Reclassification adjustment of $224 million in 2003 and $162 million in 2002 related to the adoption of EITF 03-11 (see Note 18).	
 		
(c)	 	Reclassification adjustment of $7 million in the fourth quarter of 2002 related to discontinued operations at SunCor (see Note 22).	
 		
(d)	 	Includes income from discontinued operations at SunCor (see Note 22).	
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(e)	 	Includes a $66 million after-tax charge for the cumulative effect of a change in accounting for trading activities (see Note 18).	
 		
(f)	 	The fourth quarter of 2002 included pretax losses of $38 million related to our investment in NAC, a $49 million pretax write-off related to the cancellation of Redhawk Units 3 and 4 and pretax severance costs of approximately $11 million.	
Income From Continuing
Operations – EPS:

 	 	 	2003	 	2002	
 	 	 		 		
 	 	 	Basic	 	Diluted	 	Basic	 	Diluted	
 	 	 		 		 		 		
Quarter ended:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	March 31,	 	$	0.22	 	 	$	0.22	 	 	$	0.63	 	 	$	0.63	 	
 	June 30,	 	 	0.60	 	 	 	0.60	 	 	 	0.81	 	 	 	0.81	 	
 	September 30,	 	 	1.20	 	 	 	1.20	 	 	 	1.19	 	 	 	1.19	 	
 	December 31,	 	 	0.50	 	 	 	0.50	 	 	 	(0.19	)	 	 	(0.19	)	
Net Income – EPS:

 	 	 	2003	 	2002	
 	 	 		 		
 	 	 	Basic	 	Diluted	 	Basic	 	Diluted	
 	 	 		 		 		 		
Quarter ended:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	March 31,	 	$	0.28	 	 	$	0.28	 	 	$	0.63	 	 	$	0.63	 	
 	June 30,	 	 	0.62	 	 	 	0.61	 	 	 	0.89	 	 	 	0.89	 	
 	September 30,	 	 	1.21	 	 	 	1.20	 	 	 	0.19	 	 	 	1.19	 	
 	December 31,	 	 	0.54	 	 	 	0.54	 	 	 	(0.95	)	 	 	(0.95	)	

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, 2003 and 2002 due to their short maturities.
     We hold investments in fixed income and domestic equity securities for purposes other than trading. The December 31, 2003 and 2002 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, 2003, the carrying value of our long-term debt (excluding capitalized lease obligations) was $3.32 billion, with an estimated fair value of $3.46 billion. The carrying value of our long-term debt (excluding capitalized lease obligations) was $3.00 billion on December 31, 2002, with an estimated fair value of $3.21 billion. The fair value estimates are based on quoted market prices of the same or similar issues.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

15.	 	Earnings Per Share	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	2003	 	2002	 	2001	
 	 	 		 		 		
The following table presents earnings per weighted average common share outstanding for the years ended December 31, 2003, 2002 and 2001:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Income from continuing operations	 	$	2.53	 	 	$	2.43	 	 	$	3.86	 	
 	Income from discontinued operations	 	 	0.11	 	 	 	0.10	 	 	 	—	 	
 	Cumulative effect of change in accounting	 	 	—	 	 	 	(0.77	)	 	 	(0.18	)	
 	 	 	 		 	 	 		 	 	 		 	
Earnings per share – basic	 	$	2.64	 	 	$	1.76	 	 	$	3.68	 	
 	 	 	 		 	 	 		 	 	 		 	
Diluted earnings per share:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Income from continuing operations	 	$	2.52	 	 	$	2.43	 	 	$	3.85	 	
 	Income from discontinued operations	 	 	0.11	 	 	 	0.10	 	 	 	—	 	
 	Cumulative effect of change in accounting	 	 	—	 	 	 	(0.77	)	 	 	(0.17	)	
 	 	 	 		 	 	 		 	 	 		 	
Earnings per share – diluted	 	$	2.63	 	 	$	1.76	 	 	$	3.68	 	
 	 	 	 		 	 	 		 	 	 		 	
     Dilutive stock options increased average common shares outstanding by approximately 140,000 shares in 2003, 61,000 shares in 2002 and 212,000 shares in 2001. Total average common shares outstanding for the purposes of calculating diluted earnings per share were 91,405,134 shares in 2003, 84,963,921 shares in 2002 and 84,930,140 shares in 2001.
     Options to purchase 2,291,646 shares of common stock were outstanding at December 31, 2003 but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares. Options to purchase shares of common stock that were not included in the computation of diluted earnings per share were 1,629,958 at December 31, 2002 and 212,562 at December 31, 2001.

16.	 	Stock-Based Compensation	
     Pinnacle West offers stock-based compensation plans for officers and key employees of the Company and our subsidiaries.
     In May 2002, shareholders approved the 2002 Long-Term Incentive Plan (2002 plan), which allows Pinnacle West to grant performance shares, stock ownership incentive awards and non-qualified and performance-accelerated stock options to key employees. The Company has reserved 6 million shares of common stock for issuance under the 2002 plan. No more than 1.8 million shares may be issued in relation to performance share awards and stock ownership incentive awards. The plan also provides for the granting of new non-qualified stock options at a price per share not less than the fair market value of the common stock at the time of grant. The stock options vest over three years, unless certain performance criteria are met, which can accelerate the vesting period. The term of the option cannot be longer than 10 years and the option cannot be repriced during its term.
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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
     The 1994 plan and the 1985 plan each include outstanding options but no new options will be granted under either plan. Options vest one-third of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The 1994 plan also provided for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents. Following the approval of the 2002 plan, no further grants have been made under the 1994 plan, except for awards for the annual award of up to 20,000 shares of stock to satisfy stock award obligations under employment contracts to certain executives.
     In the third quarter of 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123. The fair value method of accounting is the preferred method. In accordance with the transition requirements of SFAS No. 123, we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in APB No. 25. We recorded approximately $2.1 million in stock option expense before income taxes in our Consolidated Statements of Income in 2003 and approximately $0.5 million in 2002. This amount may not be reflective of the stock option expense we will record in future years because stock options typically vest over several years and additional grants are generally made each year.
     In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” The standard amends SFAS No. 123 to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based compensation. The standard also amends the disclosure requirements of SFAS No. 123. SFAS No. 148 is effective for fiscal years ending after December 15, 2002. We adopted the disclosure requirements in 2002. See Note 1 for our pro forma disclosures on stock-based compensation and our weighted-average assumptions used to calculate the fair value of our stock options.
     Total stock-based compensation cost, including stock option cost, was $6 million in 2003, $5 million in 2002 and $3 million in 2001.
     The following table is a summary of the status of our stock option plans as of December 31, 2003, 2002 and 2001 and changes during the years ending on those dates:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 	 	 	 	 	 	2003 Weighted	 	 	 	 	 	2002 Weighted	 	 	 	 	 	2001 Weighted	
 	 	2003	 	Average	 	2002	 	Average	 	2001	 	Average	
 	 	Shares	 	Exercise Price	 	Shares	 	Exercise Price	 	Shares	 	Exercise Price	
 	 		 		 		 		 		 		
Outstanding at beginning of year	 	 	2,185,129	 	 	$	39.96	 	 	 	1,832,725	 	 	$	39.52	 	 	 	1,569,171	 	 	$	37.55	 	
Granted	 	 	621,875	 	 	 	32.29	 	 	 	603,900	 	 	 	38.37	 	 	 	444,200	 	 	 	42.55	 	
Exercised	 	 	(62,366	)	 	 	26.09	 	 	 	(163,381	)	 	 	28.25	 	 	 	(162,229	)	 	 	28.53	 	
Forfeited	 	 	(46,392	)	 	 	37.61	 	 	 	(88,115	)	 	 	41.54	 	 	 	(18,417	)	 	 	41.67	 	
 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	
Outstanding at end of year	 	 	2,698,246	 	 	 	38.56	 	 	 	2,185,129	 	 	 	39.96	 	 	 	1,832,725	 	 	 	39.52	 	
 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	
Options exercisable at year-end	 	 	1,787,622	 	 	 	40.35	 	 	 	1,155,357	 	 	 	39.66	 	 	 	926,315	 	 	 	37.41	 	
 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	
Weighted average fair value of options granted during the year	 	 	 	 	 	$	7.37	 	 	 	 	 	 	$	6.16	 	 	 	 	 	 	$	8.84	 	
     The following table summarizes information about our stock options at December 31, 2003: 

 	 	 	 	 	 	 	Weighted	 	Weighted Average	 	 	 	 	 	Weighted	
 	 	 	 	 	 	 	Average	 	Remaining	 	 	 	 	 	Average	
Exercise	 	Options	 	Exercise	 	Contract	 	Options	 	Exercise	
Prices Per Share	 	Outstanding	 	Price	 	Life (Years)	 	Exercisable	 	Price	
	 		 		 		 		 		
$	18.71 – 23.39	 	 	10,584	 	 	$	19.00	 	 	 	0.8	 	 	 	10,584	 	 	$	19.00	 	
 	23.39 – 28.07	 	 	48,417	 	 	 	27.40	 	 	 	2.3	 	 	 	48,417	 	 	 	27.40	 	
 	28.07 – 32.75	 	 	647,400	 	 	 	32.23	 	 	 	8.7	 	 	 	49,625	 	 	 	31.50	 	
 	32.75 – 37.42	 	 	220,994	 	 	 	34.70	 	 	 	5.4	 	 	 	220,994	 	 	 	34.70	 	
 	37.42 – 42.10	 	 	759,333	 	 	 	38.86	 	 	 	6.7	 	 	 	579,854	 	 	 	38.95	 	
 	42.10 – 46.78	 	 	1,011,518	 	 	 	43.96	 	 	 	6.1	 	 	 	878,148	 	 	 	44.17	 	
 	 	 		 	 	 	 	 	 	 	 	 	 	 		 	 	 	 	 	
 	 	 	2,698,246	 	 	 	 	 	 	 	 	 	 	 	1,787,622	 	 	 	 	 	
 	 	 		 	 	 	 	 	 	 	 	 	 	 		 	 	 	 	 	
     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, 2003, 2002 and 2001: 

 	 	2003	 	 	 	 	 	2002	 	 	 	 	 	2001	 	 	 	 	
 	 	Shares	 	2003 Grant Price	 	Shares	 	2002 Grant Price	 	Shares	 	2001 Grant Price	
 	 		 		 		 		 		 		
Restricted stock	 	 	4,000	 	 	$	32.20	(a)	 	 	6,000	 	 	$	38.84	(a)	 	 	95,450	 	 	$	42.84	(a)	
Performance share awards	 	 	119,085	 	 	 	32.29	(b)	 	 	115,975	 	 	 	38.37	(b)	 	 	—	 	 	 	—	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

 	•	 	our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses and related activities, and includes electricity generation, transmission and distribution;	
 		
 	•	 	our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services. In early 2003, we moved our marketing and trading activities to APS from Pinnacle West (existing wholesale contracts remained at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of APS’ generating assets to Pinnacle West Energy; and	
 		
 	•	 	our real estate segment, which consists of SunCor’s real estate development and investment activities.	
     The amounts in our other segment include activity principally related to El Dorado’s investment in NAC, as well as the parent company and other subsidiaries. See Note 18 for information about reclassifications related to the adoption of EITF 03-11. Financial data for the years ended December 31, 2003, 2002 and 2001 by business segments is provided as follows (dollars in millions):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 	 	 	Business Segments for the Year Ended December 31, 2003	
 	 	 		
 	 	 	Regulated	 	Marketing and	 	 	 	 	 	Other (principally	 	 	 	 	
 	 	 	Electricity	 	Trading	 	Real Estate	 	NAC)	 	Total	
 	 	 		 		 		 		 		
Operating revenues	 	$	1,978	 	 	$	392	 	 	$	362	 	 	$	86	 	 	$	2,818	 	
Purchased power and fuel costs	 	 	517	 	 	 	345	 	 	 	—	 	 	 	—	 	 	 	862	 	
Other operating expenses	 	 	625	 	 	 	34	 	 	 	306	 	 	 	71	 	 	 	1,036	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Operating margin	 	 	836	 	 	 	13	 	 	 	56	 	 	 	15	 	 	 	920	 	
Depreciation and amortization	 	 	428	 	 	 	1	 	 	 	6	 	 	 	3	 	 	 	438	 	
Interest expense	 	 	172	 	 	 	—	 	 	 	2	 	 	 	1	 	 	 	175	 	
Other expense/(income)	 	 	(4	)	 	 	—	 	 	 	(25	)	 	 	—	 	 	 	(29	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Pretax margin	 	 	240	 	 	 	12	 	 	 	73	 	 	 	11	 	 	 	336	 	
Income taxes	 	 	70	 	 	 	3	 	 	 	28	 	 	 	4	 	 	 	105	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Income from continuing operations	 	 	170	 	 	 	9	 	 	 	45	 	 	 	7	 	 	 	231	 	
Income from discontinued operations – net of income taxes of $6 (see Note 22)	 	 	—	 	 	 	—	 	 	 	10	 	 	 	—	 	 	 	10	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net income	 	$	170	 	 	$	9	 	 	$	55	 	 	$	7	 	 	$	241	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total assets	 	$	8,761	 	 	$	324	 	 	$	424	 	 	$	27	 	 	$	9,536	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Capital expenditures	 	$	686	 	 	$	9	 	 	$	72	 	 	$	—	 	 	$	767	 	

 	 	 	Business Segments for the Year Ended December 31, 2002	
 	 	 		
 	 	 	Regulated	 	Marketing and	 	 	 	 	 	Other (principally	 	 	 	 	
 	 	 	Electricity	 	Trading	 	Real Estate	 	NAC)	 	Total	
 	 	 		 		 		 		 		
Operating revenues	 	$	1,890	 	 	$	287	 	 	$	201	 	 	$	62	 	 	$	2,440	 	
Purchased power and fuel costs	 	 	377	 	 	 	155	 	 	 	—	 	 	 	—	 	 	 	532	 	
Other operating expenses	 	 	659	 	 	 	34	 	 	 	185	 	 	 	105	 	 	 	983	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Operating margin	 	 	854	 	 	 	98	 	 	 	16	 	 	 	(43	)	 	 	925	 	
Depreciation and amortization	 	 	416	 	 	 	2	 	 	 	4	 	 	 	2	 	 	 	424	 	
Interest expense	 	 	141	 	 	 	—	 	 	 	2	 	 	 	1	 	 	 	144	 	
Other expense/(income)	 	 	19	 	 	 	—	 	 	 	(7	)	 	 	7	 	 	 	19	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Pretax margin	 	 	278	 	 	 	96	 	 	 	17	 	 	 	(53	)	 	 	338	 	
Income taxes	 	 	108	 	 	 	38	 	 	 	7	 	 	 	(21	)	 	 	132	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Income (loss) from continuing operations	 	 	170	 	 	 	58	 	 	 	10	 	 	 	(32	)	 	 	206	 	
Income from discontinued operations – net of income taxes of $6 (see Note 22)	 	 	—	 	 	 	—	 	 	 	9	 	 	 	—	 	 	 	9	 	
Cumulative effect of change in accounting for trading activities – net of income taxes of $43	 	 	—	 	 	 	(66	)	 	 	—	 	 	 	—	 	 	 	(66	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net income (loss)	 	$	170	 	 	$	(8	)	 	$	19	 	 	$	(32	)	 	$	149	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total assets	 	$	8,185	 	 	$	414	 	 	$	504	 	 	$	36	 	 	$	9,139	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Capital expenditures	 	$	893	 	 	$	19	 	 	$	72	 	 	$	—	 	 	$	984	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 	 	 	Business Segments for the Year Ended December 31, 2001	
 	 	 		
 	 	 	Regulated	 	Marketing and	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	Electricity	 	Trading	 	Real Estate	 	Other	 	Total	
 	 	 		 		 		 		 		
Operating revenues	 	$	1,984	 	 	$	470	 	 	$	169	 	 	$	12	 	 	$	2,635	 	
Purchased power and fuel costs	 	 	583	 	 	 	153	 	 	 	—	 	 	 	—	 	 	 	736	 	
Other operating expenses	 	 	598	 	 	 	33	 	 	 	154	 	 	 	11	 	 	 	796	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Operating margin	 	 	803	 	 	 	284	 	 	 	15	 	 	 	1	 	 	 	1,103	 	
Depreciation and amortization	 	 	423	 	 	 	1	 	 	 	4	 	 	 	—	 	 	 	428	 	
Interest expense	 	 	125	 	 	 	—	 	 	 	3	 	 	 	—	 	 	 	128	 	
Other expense/(income)	 	 	4	 	 	 	—	 	 	 	3	 	 	 	—	 	 	 	7	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Pretax margin	 	 	251	 	 	 	283	 	 	 	5	 	 	 	1	 	 	 	540	 	
Income taxes	 	 	99	 	 	 	112	 	 	 	2	 	 	 	—	 	 	 	213	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Income before accounting change	 	 	152	 	 	 	171	 	 	 	3	 	 	 	1	 	 	 	327	 	
Cumulative effect of change in accounting for derivatives – net of income taxes of $10	 	 	(15	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(15	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net income	 	$	137	 	 	$	171	 	 	$	3	 	 	$	1	 	 	$	312	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Capital expenditures	 	$	1,004	 	 	$	23	 	 	$	80	 	 	$	22	 	 	$	1,129	 	

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 and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. 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 commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
     Effective January 1, 2001, we adopted SFAS No. 133. 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 hedge criteria is met, in common stock equity (as a component of other comprehensive income (loss)). We use cash flow hedges to limit our exposure to cash flow variability on forecasted transactions. Hedge effectiveness is related to the degree to which the derivative contract and the hedged item are correlated. It is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. We exclude the time value of certain options from our assessment of hedge effectiveness. Any change in the fair value resulting from ineffectiveness, or the amount by which the derivative contract and the hedged commodity are not directly correlated, is recognized immediately in net income.
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     In 2001, we recorded a $15 million after-tax charge in net income and a $72 million after-tax credit in common stock equity (as a component of other comprehensive income (loss)), both as cumulative effects of a change in accounting for derivatives. The charge primarily resulted from electricity option contracts. The credit resulted from unrealized gains on cash flow hedges.
     During 2002, the EITF discussed EITF 02-3 and reached a consensus on certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25, 2002 for any new contracts, and on January 1, 2003 for existing contracts, with early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. We recorded a $66 million after-tax charge in net income as a cumulative effect adjustment for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that did not meet the accounting definition of a derivative. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Energy 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. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Consolidated Statements of Income on a net basis. Derivative instruments used for non-trading activities are accounted for in accordance with SFAS No. 133.
     Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Consolidated Balance Sheets. For non-trading derivative instruments that qualify for cash flow hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of other comprehensive income (loss)). Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. 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. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Certain of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered. Derivatives associated with trading activities are adjusted to fair value through income.
     EITF 02-3 requires that derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Previous guidance under EITF 98-10 permitted physically-settled energy trading contracts to be reported either gross or net in the income statement. Beginning in the third quarter of 2002, we netted all of our energy trading activities on the Consolidated Statements of Income and restated prior year amounts for all periods presented. Reclassification of such trading activity to a net basis of reporting resulted in reductions in both
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     revenues and purchased power and fuel costs, but did not have any impact on our financial condition, net income or cash flows.
     We adopted 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 Issue No. 02-3,” effective October 1, 2003. EITF 03-11 provided guidance on whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported on a net or gross basis and concluded such classification is a matter of judgment that depends on the relevant facts and circumstances. 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 netted these book-outs, reducing both revenues and purchased power and fuel costs in 2003, 2002 and 2001, but this did not impact our financial condition, net income or cash flows. Following are the net reclassifications to our previously reported amounts (dollars in thousands): 

 	 	 	2003	 	2002	 	2001	
 	 	 		 		 		
Regulated Electricity	 	$	40,069	 	 	$	122,632	 	 	$	577,783	 	
Marketing and Trading	 	 	184,298	 	 	 	39,052	 	 	 	181,447	 	
 	 	 		 	 	 		 	 	 		 	
 	Total	 	$	224,367	 	 	$	161,684	 	 	$	759,230	 	
 	 	 		 	 	 		 	 	 		 	
     In November 2003, the FASB revised its derivative guidance in DIG Issue No. C15, “Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity.” Effective January 1, 2004, the new guidance changes the criteria for the normal purchases and sales scope exception for electricity contracts. We do not expect this guidance to have a material impact on our financial statements.
     In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The provisions of SFAS No. 149 that relate to previously issued SFAS No. 133 derivatives implementation guidance should continue to be applied in accordance with the effective dates of the original implementation guidance. In general, other provisions are applied prospectively to contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The impact of this standard was immaterial to our financial statements.
     The changes in the fair value of our hedged positions included in the Consolidated Statements of Income for the years ended December 31, 2003 and 2002 are comprised of the following (dollars in thousands):
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 	 	2003	 	2002	
 	 		 		
Gains on the ineffective portion of derivatives qualifying for hedge accounting	 	$	8,237	 	 	$	13,682	 	
Gains (losses) from the change in options’ time value excluded from measurement of effectiveness			181				(2,484	)	
Losses from the discontinuance of cash flow hedges	 	 	—	 	 	 	(8,820	)	

     As of December 31, 2003, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is approximately five years. During the year ending December 31, 2004, we estimate that a net gain of $8 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions.
     Our assets and liabilities from risk management and trading activities are presented in two categories, consistent with our business segments:

 	•	 	Regulated Electricity – non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and	
 		
 	•	 	Marketing and Trading – both non-trading and trading derivative instruments of our competitive business segment.	
     The following table summarizes our assets and liabilities from risk management and trading activities at December 31, 2003 and 2002 (dollars in thousands): 

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Net Asset/	
December 31, 2003	 	Current Assets	 	Investments	 	Current Liabilities	 	Other Liabilities	 	(Liability)	
	 		 		 		 		 		
Regulated Electricity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Mark-to-Market	 	$	44,079	 	 	$	5,900	 	 	$	(47,268	)	 	$	(3,028	)	 	$	(317	)	
 	Options	 	 	—	 	 	 	12,101	 	 	 	—	 	 	 	—	 	 	 	12,101	 	
Marketing	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	and Trading:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Mark-to-Market	 	 	53,551	 	 	 	116,363	 	 	 	(37,023	)	 	 	(63,398	)	 	 	69,493	 	
 	Emission allowances – at cost	 	 	—	 	 	 	4,582	 	 	 	(8,464	)	 	 	(16,304	)	 	 	(20,186	)	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total	 	$	97,630	 	 	$	138,946	 	 	$	(92,755	)	 	$	(82,730	)	 	$	61,091	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
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 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Net Asset/	
December 31, 2002	 	Current Assets	 	Investments	 	Current Liabilities	 	Other Liabilities	 	(Liability)	
	 		 		 		 		 		
Regulated Electricity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Mark-to-Market	 	$	41,522	 	 	$	6,971	 	 	$	(60,819	)	 	$	(36,678	)	 	$	(49,004	)	
 	Options	 	 	—	 	 	 	24,651	 	 	 	—	 	 	 	—	 	 	 	24,651	 	
Marketing	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	and Trading:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Mark-to-Market	 	 	61,142	 	 	 	121,189	 	 	 	(50,510	)	 	 	(74,841	)	 	 	56,980	 	
 	Emission allowances – at cost	 	 	—	 	 	 	38,943	 	 	 	—	 	 	 	(36,381	)	 	 	2,562	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total	 	$	102,664	 	 	$	191,754	 	 	$	(111,329	)	 	$	(147,900	)	 	$	35,189	 	
 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
     Cash or collateral may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties is $1 million at December 31, 2003 and $5 million at December 31, 2002, and is included in investments and other assets on the Consolidated Balance Sheet. Collateral provided to us by counterparties is $12 million at December 31, 2003 and $22 million at December 31, 2002, and is included in other deferred credits on the Consolidated Balance Sheet.
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, including two counterparties for which a worst case exposure represents approximately 37% of our $237 million of risk management and trading assets as of December 31, 2003. Our risk management process assesses and monitors the financial exposure of these and all other counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, including the counterparties noted above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 “Mark-to-Market Accounting” for a discussion of our credit valuation adjustment policy.
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19.	 	Other Income and Other Expense	
     The following table provides detail of other income and other expense for the years ended December 31, 2003, 2002 and 2001 (dollars in thousands):

 	 	 	Year Ended December 31,	
 	 	 		
 	 	 	2003	 	2002	 	2001	
 	 	 		 		 		
Other income:	 	 	 	 	 	 	 	 	 	 	 	 	
 	SunCor joint venture earnings (a)	 	$	24,740	 	 	$	7,355	 	 	$	3,687	 	
 	Interest income	 	 	4,412	 	 	 	4,332	 	 	 	6,763	 	
 	Investment gains	 	 	3,649	 	 	 	—	 	 	 	—	 	
 	Environmental insurance recovery	 	 	—	 	 	 	—	 	 	 	12,349	 	
 	Miscellaneous	 	 	2,762	 	 	 	3,223	 	 	 	3,617	 	
 	 	 	 		 	 	 		 	 	 		 	
Total other income	 	$	35,563	 	 	$	14,910	 	 	$	26,416	 	
 	 	 	 		 	 	 		 	 	 		 	
Other expense:	 	 	 	 	 	 	 	 	 	 	 	 	
 	Non-operating costs (b)	 	$	(16,481	)	 	$	(19,430	)	 	$	(16,807	)	
 	Investment losses (c)	 	 	—	 	 	 	(10,439	)	 	 	(5,126	)	
 	Non-operating costs – SunCor	 	 	—	 	 	 	—	 	 	 	(7,000	)	
 	Miscellaneous	 	 	(4,093	)	 	 	(3,786	)	 	 	(4,644	)	
 	 	 	 		 	 	 		 	 	 		 	
Total other expense	 	$	(20,574	)	 	$	(33,655	)	 	$	(33,577	)	

(a)	 	Primarily related to the sale at SunCor of a land interest and profit participation agreement in the fourth quarter of 2003 for $18 million. In 2002, SunCor received $2.5 million for the profit participation.	
 		
(b)	 	As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations).	
 		
(c)	 	Primarily related to El Dorado’s investment losses in NAC prior to consolidation in the third quarter of 2002.	

20.	 	Variable Interest Entities	
     In 2003, we adopted FIN No. 46R, “Consolidation of Variable Interest Entities,” as it applies to special-purpose entities. FIN No. 46R requires that we consolidate a VIE if we have a majority of the risk of loss from the VIE’s activities or we are entitled to receive a majority of the VIE’s residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. In 1986, APS entered into agreements with three separate SPE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. See Note 9 for further information about the sale leaseback transactions. Based on our assessment of FIN No. 46R, we are not required to consolidate the Palo Verde VIEs. Certain provisions of FIN No. 46R have a future effective date. We do not expect these provisions to have a material impact on our financial statements.
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     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of December 31, 2003, APS would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.

21.	 	Guarantees	
     On January 1, 2003, we adopted FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN No. 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees. It also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure provisions were effective for the year ended December 31, 2002. The initial recognition and measurement provisions of FIN No. 45 were effective on a prospective basis to guarantees issued or modified after December 31, 2002.
     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees related to Pinnacle West Energy consist of equipment and performance guarantees related to our generation construction program, transmission service guarantees for West Phoenix Units 4 and 5 and long-term service agreement guarantees for new power plants. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products and enable El Dorado to support the activities of NAC. Non-performance or payment under the original contract by our unregulated subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Consolidated Balance Sheets related to Pinnacle West’s guarantees on behalf of its subsidiaries. Our guarantees have no recourse (except NAC) or collateral provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at December 31, 2003 are as follows (dollars in millions): 

 	 	 	Guarantees	 	Surety Bonds	
 	 	 		 		
 	 	 	 	 	 	 	Term	 	 	 	 	 	Term	
 	 	 	Amount	 	(in years)	 	Amount	 	(in years)	
 	 	 		 		 		 		
Parental:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Pinnacle West Energy	 	$	86	 	 	1 to 2	 	$	—	 	 	 	—	 	
 	APS Energy Services	 	 	16	 	 	1 to 2	 	 	35	 	 	 	2	 	
 	El Dorado (NAC)	 	 	40	 	 	1 to 3	 	 	—	 	 	 	—	 	
 	 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	
Total	 	$	142	 	 	 	 	 	 	$	35	 	 	 	 	 	
 	 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	
     At December 31, 2003, we had entered into approximately $41 million of letters of credit which support various construction agreements. These letters of credit expire in 2004 and 2005. We intend to provide from either existing or new facilities for the extension, renewal or substitution of
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the letters of credit to the extent required. At December 31, 2003, Pinnacle West has approximately $4 million of letters of credit related to workers’ compensation expiring in 2004.
     APS has entered into various agreements that require letters of credit for financial assurance purposes. At December 31, 2003, 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. These letters of credit have expiration dates in 2004 and 2005. APS has also entered into approximately $109 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 2005. Additionally, APS has approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2004. 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 provide indemnifications relating to liabilities arising from or related to certain of our agreements. APS has provided indemnifications to 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 and therefore, the overall maximum amount of the obligation under such indemnifications 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 indemnifications is likely and therefore no related liability has been recorded.

22.	 	Real Estate Activities – Discontinued Operations	
     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 our Consolidated Statements of Income in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Among other guidance, SFAS No. 144 prescribes accounting for discontinued operations and defines certain activities as discontinued operations. We adopted SFAS No. 144 effective January 1, 2002 and determined that activities that would have required discontinued operations reporting in 2002 and 2001 were immaterial.
     In 2003, SunCor sold its water utility company, which resulted in an after-tax gain of $8 million ($14 million pretax). The amounts of the gain on the sale and operating income of the water utility company in 2003 and 2002 are classified as discontinued operations on our Consolidated Statements of Income. The amounts related to 2001 were immaterial for reclassification.
     In the second quarter of 2002, SunCor sold a retail center, but maintained a continuing involvement through a management contract. In the first quarter of 2003, this management contract was canceled. As a result, the after-tax gain of $6 million ($10 million pre-tax) recorded in operations in 2002 related to this property was reclassified as discontinued operations on our Consolidated Statements of Income. The income from discontinued operations in the year ended December 31, 2002 primarily reflects this sale. The amounts related to 2001 were immaterial for reclassification.
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     In the fourth quarter of 2003, SunCor sold a retail center, which resulted in an after-tax gain of $2 million ($3 million pretax). The gain on the sale and the operating income related to this property in 2003 are classified as discontinued operations on our Consolidated Statements of Income. There were no prior-year operations related to this retail center. The amounts related to 2001 were immaterial for reclassification.
     The following table provides SunCor’s revenue and income before income taxes related to properties classified as discontinued operations on our consolidated statements of income for the years ended December 31, 2003 and 2002 (dollars in thousands): 

 	 	2003	 	2002	
 	 		 		
Revenue	 	$	70,580	 	 	$	35,307	 	
Income before taxes	 	$	16,532	 	 	$	14,827	 	
     The following tables provide the amounts related to properties of discontinued operations which were reclassified to assets and liabilities held for sale on the Consolidated Balance Sheets at December 31, 2003 and 2002 (dollars in thousands): 

 	 	 	2003	 	2002	
 	 	 		 		
Real estate investments-net	 	$	—	 	 	$	39,849	 	
Other	 	 	—	 	 	 	2,490	 	
										
 	Real estate assets held for sale	 	$	—	 	 	$	42,339	 	

 	 	 	2003	 	2002	
 	 	 		 		
Customer deposits	 	$	—	 	 	$	13,648	 	
Long-term debt less current maturities	 	 	—	 	 	 	12,454	 	
Other	 	 	—	 	 	 	2,753	 	
 	 	 		 	 	 		 	
 	Real estate liabilities held for sale	 	$	—	 	 	$	28,855	 	
 	 	 		 	 	 		 	
See Note 17 for information related to the real estate segment.
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 	 	PINNACLE WEST CAPITAL CORPORATION		
 	 	SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS		
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Column A	 	Column B	 	Column C	 	Column D	 	Column E	
 	 	 	 	 	 	 	Additions	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 		 	 	 	 	 	 	 	 	
 	 	 	Balance at	 	Charged to	 	Charged	 	 	 	 	 	Balance	
 	 	 	beginning	 	cost and	 	to other	 	 	 	 	 	at end of	
Description	 	of period	 	expenses	 	accounts	 	Deductions	 	Period	
	 		 		 		 		 		
 	 	 	 	 	 	 	(dollars in thousands)	 	 	 	 	 	 	 	 	
Real Estate Valuation Reserves:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	2003	 	$	1,661	 	 	$	—	 	 	$	—	 	 	$	1,661	(a)	 	$	—	 	
 	2002	 	 	2,000	 	 	 	—	 	 	 	—	 	 	 	339	(a)	 	 	1,661	 	
 	2001	 	 	2,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,000	 	
Reserve for uncollectibles:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	2003	 	$	9,607	 	 	$	3,715	 	 	$	—	 	 	$	4,099	 	 	$	9,223	 	
 	2002	 	 	14,334	 	 	 	(21	)	 	 	—	 	 	 	4,706	 	 	 	9,607	 	
 	2001	 	 	7,580	 	 	 	13,394	 	 	 	—	 	 	 	6,640	 	 	 	14,334	 	
Reserve for contract losses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	2003	 	$	13,000	 	 	$	—	 	 	$	—	 	 	$	13,000	 	 	$	—	 	
 	2002	 	 	—	 	 	 	13,000	(b)	 	 	—	 	 	 	—	 	 	 	13,000	 	

(a)	 	Represents pro-rata allocations for sale of land.	
 		
(b)	 	Contract losses related to NAC.	
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
     None.  
ITEM 9A. CONTROLS AND PROCEDURES
     (a)  Evaluation of Disclosure Controls and Procedures
     The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this report have been designed and are functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
     (b)  Change in Internal Control over Financial Reporting
     No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.  
PART III 
ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT
     Reference is hereby made to “Election of Directors” and to “Section 16(a) Beneficial Ownership Reporting Compliance” in the Company’s Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 19, 2004 (the “2004 Proxy Statement”) and to the Supplemental Item – “Executive Officers of the Registrant” in Part I of this report.
     The Company 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 the Company’s Chief Executive Officer, Chief Financial Officer, Controller, Treasurer, and officers holding substantially equivalent positions at the Company’s subsidiaries. The Code of Ethics for Financial Professionals is posted on the Company website at www.pinnaclewest.com. The Company intends to satisfy the requirements under Item 10 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 the Company’s website.  
ITEM 11. EXECUTIVE COMPENSATION
     Reference is hereby made to “The Board and its Committees – How are Directors compensated?”; “Performance Graph”; and “Executive Compensation” in the 2004 Proxy Statement.
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ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Security Ownership of Certain Beneficial Owners and Management
     Reference is hereby made to “Election of Directors – How many shares of Pinnacle West stock are owned by management and large shareholders?” in the 2004 Proxy Statement. 
Securities Authorized For Issuance Under Equity Compensation Plans
     The following table sets forth information as of December 31, 2003 with respect to our compensation plans and individual compensation arrangements under which our equity securities were authorized for issuance to directors, officers, employees, consultants and certain other persons and entities in exchange for the provision to us of goods or services.

 	 	 	 	 	 	 	 	 	 	 	Number of securities	
 	 	 	Number of	 	 	 	 	 	remaining available for	
 	 	 	securities to be	 	Weighted-average	 	future issuance under	
 	 	 	issued upon exercise	 	exercise price of	 	equity compensation	
 	 	 	of outstanding	 	outstanding	 	plans (excluding	
 	 	 	options, warrants	 	options, warrants	 	securities reflected in	
 	 	 	and rights	 	and rights	 	column (a))	
Plan category	 	(a)	 	(b)	 	(c)	
	 		 		 		
Equity compensation plans approved by security holders	 	 	2,698,246	 	 	$	38.56	 	 	 	4,619,227	 	
Equity compensation plans not approved by security holders	 	 	—	 	 	$	—	 	 	 	163,100	 	
 	 	 		 	 	 		 	 	 		 	
 	Total	 	 	2,698,246	 	 	$	38.56	 	 	 	4,782,327	 	
 	 	 		 	 	 		 	 	 		 	
Equity Compensation Plans Approved By Security Holders
     The Company has four equity compensation plans that were approved by its shareholders: the Pinnacle West Capital Corporation Stock Option and Incentive Plan, under which no new options may be granted; the Pinnacle West Capital Corporation Directors Stock Option Plan, under which no new options may be granted; the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan, under which no new options and a limited number of other stock awards may be granted; and the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan. See Note 16 for additional information regarding these plans.
Equity Compensation Plans Not Approved By Security Holders
     The Company has one equity compensation plan, the Pinnacle West Capital Corporation 2000 Director Equity Plan (the “2000 Plan”), for which the approval of shareholders was not required.
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     Number of Shares Subject to the 2000 Plan. The total number of shares of the Company’s common stock granted under the 2000 Plan may not exceed 200,000. In the case of a significant corporate event, such as a reorganization, merger or consolidation, the 2000 Plan provides for adjustment of the above limit, the number of shares to be awarded automatically to eligible non-employee directors and the number of shares of the Company’s common stock non-employee directors are required to own to receive an annual grant of common stock under the 2000 Plan.
     Eligibility for Participation. Only non-employee directors may participate in the 2000 Plan. A non-employee director is an individual who is a director of the Company but who is not also an employee of the Company or any of its subsidiaries.
     Terms of Awards. The 2000 Plan provides for: (1) annual grants of common stock to eligible non-employee directors, (2) discretionary grants of common stock to eligible non-employee directors and (3) grants of nonqualified stock options to eligible non-employee directors.
      Annual Grants of Stock
     Each individual who is a non-employee director as of July 1 of a calendar year, and who meets requirements of ownership of the Company’s common stock set forth below, will receive 900 shares of the Company’s common stock for such calendar year. In the first calendar year in which a non-employee director is eligible to participate in the 2000 Plan, he or she must own at least 900 shares of the Company’s common stock as of December 31 of the same calendar year to receive a grant of 900 shares of the Company’s common stock. If the non-employee director owns 900 shares of common stock as of June 30, he or she will receive a grant of 900 shares of common stock as of July 1 of the same calendar year. If the non-employee director does not own 900 shares of the Company’s common stock as of June 30, but acquires the necessary shares on or before December 31 of the same year, he or she will receive a grant of 900 shares of common stock within a reasonable time after the Company verifies that the requisite number of shares has been acquired. In each subsequent year, the number of shares of the Company’s common stock the non-employee director must own to receive a grant of 900 shares of common stock will increase by 900 shares, until reaching a maximum of 4,500 shares. In each of the subsequent years, the non-employee director must own the requisite number of shares of the Company’s common stock as of June 30 of the relevant calendar year.
      Discretionary Grants of Stock
     The Human Resources Committee of the Board of Directors, excluding those members who are not “Non-Employee Directors” under SEC Rule 16b-3(b)(3) the Committee administers the 2000 Plan and may grant shares of the Company’s common stock to non-employee directors in its discretion. No discretionary grants of common stock have been made under the 2000 Plan.
      Grants of Nonqualified Stock Options
     The Committee can grant nonqualified stock options under the 2000 Plan. The terms and the conditions of the option grant, including the exercise price per share, which may not be less than fair market value on the date of grant, will be set by the Committee in a written award agreement. The Committee will determine the time or times at which any such options may be exercised in whole or in part. The Committee will also determine the performance or other conditions, if any, that must be satisfied before all or part of an option may be exercised. Any such options granted to a participant
126 

 

will expire on the tenth anniversary date of the date of grant, unless the option is earlier terminated, forfeited or surrendered pursuant to a provision of the 2000 Plan or the applicable award agreement. Notwithstanding the foregoing, if a participant ceases to be a Company director for any reason, including death or disability, any such options held by that participant will expire on the second anniversary of the date on which the participant ceased to be a Company director, unless otherwise provided in the applicable award agreement. Unless the Committee provides otherwise, no such options may be sold, transferred, pledged, assigned or otherwise alienated, other than by will, the laws of descent and distribution, or under any other circumstances allowed by the Committee. No options have been granted under the 2000 Plan.  
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
     Reference is hereby made to “Executive Compensation – Human Resources Committee Interlocks and Insider Participation” and “Employment and Severance Arrangements” in the 2004 Proxy Statement. 
ITEM 14. PRINCIPAL ACCOUNTANT
FEES AND SERVICES
     Reference is hereby made to “Audit Matters – What Fees Were Paid to Our Independent Accountants in 2003 and 2002?” and “– What are the Audit Committee’s pre-approval policies?” in the 2004 Proxy Statement.
127 

 
PART IV 
ITEM 15. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Financial Statement Schedules
     See the Index to Consolidated Financial Statements and Financial Statement Schedule in Part II, Item 8.
Exhibits Filed

Exhibit No.	 	 	 	Description	
	 	 	 		
3.1	 	—	 	Pinnacle West Capital Corporation Bylaws, amended as of January 21, 2004	
 	 	 	 	 	
10.1 a	 	—	 	2004 Officer Variable Incentive Plan	
 	 	 	 	 	
10.2 a	 	—	 	2004 CEO Variable Incentive Plan	
 	 	 	 	 	
10.3	 	—	 	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 19, 2003	
 	 	 	 	 	
10.4	 	—	 	Amendment No. 7 to the Decommissioning Trust Agreement (PVNGS Unit 2), dated as of December 19, 2003	
 	 	 	 	 	
10.5	 	—	 	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 19, 2003	
 	 	 	 	 	
10.6 a	 	—	 	Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	
 	 	 	 	 	
10.7 a	 	—	 	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, amended and restated as of January 1, 2003	
 	 	 	 	 	
12.1	 	—	 	Ratio of Earnings to Fixed Charges	
 	 	 	 	 	
21.1	 	—	 	Subsidiaries of the Company	
 	 	 	 	 	
23.1	 	—	 	Consent of Deloitte & Touche LLP	
 	 	 	 	 	
31.1	 	—	 	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	 	—	 	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	 	—	 	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	 	—	 	Risk Factors	
128 

 

     In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below: 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
3.2	 	Articles of Incorporation, restated as of July 29, 1988	 	19.1 to the Company’s September 1988 Form 10-Q Report	 	1-8962	 	11-14-88	
 	 	 	 	 	 	 	 	 	
4.1	 	Mortgage and Deed of Trust Relating to APS’ First Mortgage Bonds, together with forty-eight indentures supplemental thereto	 	4.1 to APS’ September 1992 Form 10-Q Report	 	1-4473	 	11-9-92	
 	 	 	 	 	 	 	 	 	
4.2	 	Forty-ninth
Supplemental
Indenture	 	4.1 to APS’ 1992 Form 10-K Report	 	1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
4.3	 	Fiftieth
Supplemental
Indenture	 	4.2 to APS’ 1993 Form 10-K Report	 	1-4473	 	3-30-94	
 	 	 	 	 	 	 	 	 	
4.4	 	Fifty-first
Supplemental
Indenture	 	4.1 to APS’ August 1, 1993 Form 8-K Report	 	1-4473	 	9-27-93	
 	 	 	 	 	 	 	 	 	
4.5	 	Fifty-second
Supplemental
Indenture	 	4.1 to APS’ September 30, 1993 Form 10-Q Report	 	1-4473	 	11-15-93	
 	 	 	 	 	 	 	 	 	
4.6	 	Fifty-third
Supplemental
Indenture	 	4.5 to APS’ Registration Statement No. 33-61228 by means of February 23, 1994 Form 8-K Report	 	1-4473	 	3-1-94	
 	 	 	 	 	 	 	 	 	
4.7	 	Fifty-fourth
Supplemental
Indenture	 	4.1 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report	 	1-4473	 	11-22-96	
 	 	 	 	 	 	 	 	 	
4.8	 	Fifty-fifth
Supplemental
Indenture	 	4.8 to APS’ Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report	 	1-4473	 	4-9-97	
129 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
4.9	 	Fifty-sixth
Supplemental
Indenture	 	4.1 to the Company’s 2002 Form 10-K Report	 	1-8962	 	3-31-03	
 	 	 	 	 	 	 	 	 	
4.10	 	Fifty-seventh
Supplemental
Indenture	 	4.2 to the Company’s 2002 Form 10-K Report	 	1-8962	 	3-31-03	
 	 	 	 	 	 	 	 	 	
4.11	 	Fifty-eighth
Supplemental
Indenture	 	10.1 to the Company’s June 2003 Form 10-Q Report	 	1-8962	 	8-14-03	
 	 	 	 	 	 	 	 	 	
4.12	 	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	 	1-4473	 	3-30-94	
 	 	 	 	 	 	 	 	 	
4.13	 	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	 	1-4473	 	1-11-95	
 	 	 	 	 	 	 	 	 	
4.14	 	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	 	1-4473	 	1-11-95	
 	 	 	 	 	 	 	 	 	
4.15	 	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	 	1-4473	 	11-22-96	
 	 	 	 	 	 	 	 	 	
4.16	 	First Supplemental
Indenture	 	4.6 to APS’ Registration Statements Nos. 33-61228, 33-55473, 33-64455 and 333-15379 by means of November 19, 1996 Form 8-K Report	 	1-4473	 	11-22-96	
130 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
4.17	 	Second Supplemental
Indenture	 	4.10 to APS’ Registration Statement Nos. 33-55473, 33-64455 and 333-15379 by means of April 7, 1997 Form 8-K Report	 	1-4473	 	4-9-97	
 	 	 	 	 	 	 	 	 	
4.18	 	Third Supplemental
Indenture	 	10.2 to the Company’s March 2003 Form 10-Q Report	 	1-8962	 	5-15-03	
 	 	 	 	 	 	 	 	 	
4.19	 	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 the Company’s Registration Statement No. 333-53150	 	1-8962	 	1-25-01	
 	 	 	 	 	 	 	 	 	
4.20	 	First Supplemental Indenture dated as of March 15, 2001	 	4.2 to the Company’s Registration Statement No. 333-52476	 	1-8962	 	3-26-01	
 	 	 	 	 	 	 	 	 	
4.21	 	Second Supplemental Indenture dated as of November 1, 2003	 	4.20 to the Company’s Registration Statement No. 333-101457 by means of November 6, 2003 Form 8-K Report	 	1-8962	 	11-12-03	
 	 	 	 	 	 	 	 	 	
4.22	 	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 the Company’s Registration Statement No. 333-53150	 	1-8962	 	1-25-01	
 	 	 	 	 	 	 	 	 	
4.23	 	Specimen Certificate of Pinnacle West Capital Corporation Common Stock, no par value	 	4.2 to the Company’s 1988 Form 10-K Report	 	1-8962	 	3-31-89	
131 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
4.24	 	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 the Company’s 1987 Form 10-K Report	 	1-8962	 	3-30-88	
 	 	 	 	 	 	 	 	 	
4.25	 	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	 	1-4473	 	1-16-98	
 	 	 	 	 	 	 	 	 	
4.26	 	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	 	1-4473	 	1-16-98	
 	 	 	 	 	 	 	 	 	
4.27	 	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	 	1-4473	 	2-22-99	
 	 	 	 	 	 	 	 	 	
4.28	 	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	 	1-4473	 	11-5-99	
 	 	 	 	 	 	 	 	 	
4.29	 	Fourth Supplemental Indenture dated as of August 1, 2000	 	4.1 to Registration Statement No. 333-58445 and 333-94277 by means of August 2, 2000 Form 8-K	 	1-4473	 	8-4-00	
 	 	 	 	 	 	 	 	 	
4.30	 	Fifth Supplemental Indenture dated as of October 1, 2001	 	Report 4.1 to APS’ September 2001 Form 10-Q	 	1-4473	 	11-6-01	
132 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
4.31	 	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	 	1-4473	 	2-28-01	
 	 	 	 	 	 	 	 	 	
4.32	 	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	 	1-8962	 	5-9-03	
 	 	 	 	 	 	 	 	 	
4.33	 	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 the Company’s March 22, 1999 Form 8-K Report	 	1-8962	 	4-19-99	
 	 	 	 	 	 	 	 	 	
4.34	 	Amendment to Rights Agreement, effective as of January 1, 2002	 	4.1 to March 2002 Form 10-Q Report	 	1-8962	 	5-15-02	
133 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.8	 	Two separate Decommissioning Trust Agreements (relating to PVNGS Units 1 and 3, respectively), each dated July 1, 1991, between APS and Mellon Bank, N.A., as Decommissioning Trustee	 	10.2 to APS’ September 1991 Form 10-Q Report	 	1-4473	 	11-14-91	
 	 	 	 	 	 	 	 	 	
10.9	 	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	 	1-4473	 	3-30-95	
 	 	 	 	 	 	 	 	 	
10.10	 	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	 	1-4473	 	3-30-95	
 	 	 	 	 	 	 	 	 	
10.11	 	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	 	1-4473	 	3-28-97	
 	 	 	 	 	 	 	 	 	
10.12	 	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	 	1-4473	 	3-28-97	
134 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.13	 	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 the Company’s 1991 Form 10-K Report	 	1-8962	 	3-26-92	
 	 	 	 	 	 	 	 	 	
10.14	 	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	 	1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
10.15	 	Amendment No. 2 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994	 	10.2 to APS’ 1994 Form 10-K Report	 	1-4473	 	3-30-95	
 	 	 	 	 	 	 	 	 	
10.16	 	Amendment No. 3 to Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of November 1, 1994	 	10.1 to APS’ June 1996 Form 10-Q Report	 	1-4473	 	8-9-96	
135 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.17	 	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	 	1-4473	 	3-28-97	
 	 	 	 	 	 	 	 	 	
10.18	 	Amendment No. 5 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of June 30, 2000	 	10.1 to Pinnacle West’s March 2002 Form 10-Q Report	 	1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
10.19	 	Amendment No. 3 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of March 18, 2002	 	10.2 to Pinnacle West’s March 2002 Form 10-Q Report	 	1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
10.20	 	Amendment No. 6 to the Amended and Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of March 18, 2002	 	10.3 to Pinnacle West’s March 2002 Form 10-Q Report	 	1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
10.21	 	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	 	1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
10.22	 	Asset Purchase and Power Exchange Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990 and as of July 18, 1991	 	10.1 to APS’ June 1991 Form 10-Q Report	 	1-4473	 	8-8-91	
136 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.23	 	Long-Term Power Transaction Agreement dated September 21, 1990 between APS and PacifiCorp, as amended as of October 11, 1990, and as of July 8, 1991	 	10.2 to APS’ June 1991 Form 10-Q Report	 	1-4473	 	8-8-91	
 	 	 	 	 	 	 	 	 	
10.24	 	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	 	1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.25	 	Restated Transmission Agreement between PacifiCorp and APS dated April 5, 1995	 	10.4 to APS’ 1995 Form 10-K Report	 	1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.26	 	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	 	1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.27	 	Reciprocal Transmission Service Agreement between APS and PacifiCorp dated as of March 2, 1994	 	10.6 to APS’ 1995 Form 10-K Report	 	1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.28	 	Contract, dated July 21, 1984, with DOE providing for the disposal of nuclear fuel and/or high -level radioactive waste, ANPP	 	10.31 to the Company’s Form S-14 Registration Statement	 	2-96386	 	3-13-85	
137 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.29	 	Indenture of Lease with Navajo Tribe of Indians, Four Corners Plant	 	5.01 to APS’ Form S-7 Registration Statement	 	2-59644	 	9-1-77	
 	 	 	 	 	 	 	 	 	
10.30	 	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	 	2-59644	 	9-1-77	
 	 	 	 	 	 	 	 	 	
10.31	 	Amendment and Supplement No. 1 to Supplemental and Additional Indenture of Lease Four Corners, dated April 25, 1985	 	10.36 to the Company’s Registration Statement on Form 8-B Report	 	1-8962	 	7-25-85	
 	 	 	 	 	 	 	 	 	
10.32	 	Application and Grant of multi-party rights-of-way and easements, Four Corners Plant Site	 	5.04 to APS’ Form S-7 Registration Statement	 	2-59644	 	9-1-77	
 	 	 	 	 	 	 	 	 	
10.33	 	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 the Company’s Registration Statement on Form 8-B	 	1-8962	 	7-25-85	
 	 	 	 	 	 	 	 	 	
10.34	 	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	 	2-59644	 	9-1-77	
 	 	 	 	 	 	 	 	 	
10.35	 	Four Corners Project Co-Tenancy Agreement Amendment No. 6	 	10.7 to the Company’s 2000 Form 10-K Report	 	1-8962	 	3-14-01	
138 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.36	 	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 the Company’s Registration Statement on Form 8-B	 	1-8962	 	7-25-85	
 	 	 	 	 	 	 	 	 	
10.37	 	Indenture of Lease, Navajo Units 1, 2, and 3	 	5(g) to APS’ Form S-7 Registration Statement	 	2-36505	 	3-23-70	
 	 	 	 	 	 	 	 	 	
10.38	 	Application of Grant of rights-of-way and easements, Navajo Plant	 	5(h) to APS Form S-7 Registration Statement	 	2-36505	 	3-23-70	
 	 	 	 	 	 	 	 	 	
10.39	 	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	 	2-394442	 	3-16-71	
10.40	 	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	 	1-4473	 	3-8-89	
139 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.41	 	Amendment No. 13, dated as of April 22, 1991, to Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, among APS, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, Public Service Company of New Mexico, El Paso Electric Company, Southern California Public Power Authority, and Department of Water and Power of the City of Los Angeles	 	10.1 to APS’ March 1991 Form 10-Q Report	 	1-4473	 	5-15-91	
 	 	 	 	 	 	 	 	 	
10.42	 	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 the Company’s June 2000 Form 10-Q Report	 	1-8962	 	8-14-00	
140 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.43 c	 	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	 	33-9480	 	10-24-86	
 	 	 	 	 	 	 	 	 	
10.44 c	 	Amendment No. 1, dated as of November 1, 1986, to Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its capacity as Owner Trustee, as Lessor, and APS, as Lessee	 	10.5 to APS’ September 1986 Form 10-Q Report by means of Amendment No. on December 3, 1986 Form 8	 	1-4473	 	12-4-86	
 	 	 	 	 	 	 	 	 	
10.45 c	 	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	 	1-4473	 	3-8-89	
 	 	 	 	 	 	 	 	 	
10.46 c	 	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	 	1-4473	 	3-30-93	
141 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.47	 	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	 	1-4473	 	1-20-87	
 	 	 	 	 	 	 	 	 	
10.48	 	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	 	1-4473	 	8-24-87	
 	 	 	 	 	 	 	 	 	
10.49	 	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	 	1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
10.50 a	 	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated, dated December 7, 1999	 	10.13 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.51 a	 	First Amendment to the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan	 	10.4 to Pinnacle West’s 2001 Form 10-K Report	 	1-8962	 	3-27-02	
142 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.52 a	 	Second Amendment to the Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan	 	10.5 to Pinnacle West’s 2001 Form 10-K Report	 	1-8962	 	3-27-02	
 	 	 	 	 	 	 	 	 	
10.53 a	 	Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans dated August 1, 1996	 	10.14 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.54 a	 	First Amendment dated December 7, 1999 to the Trust for the Pinnacle West Capital Corporation, Arizona Public Service Company and SunCor Development Company Deferred Compensation Plans	 	10.15 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.55 a	 	Directors’ Deferred Compensation Plan, as restated, effective January 1, 1986	 	10.1 to APS’ June 1986 Form 10-Q Report	 	1-4473	 	8-13-86	
 	 	 	 	 	 	 	 	 	
10.56 a	 	Second Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993	 	10.2 to APS’ 1993 Form 10-K Report	 	1-4473	 	3-30-94	
 	 	 	 	 	 	 	 	 	
10.57 a	 	Third Amendment to the Arizona Public Service Company Directors’ Deferred Compensation Plan, effective as of May 1, 1993	 	10.1 to APS’ September 1994 Form 10-Q Report	 	1-4473	 	11-10-94	
143 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.58 a	 	Fourth Amendment dated December 28, 1999 to the Arizona Public Service Company Directors Deferred Compensation Plan	 	10.8 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.59 a	 	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	 	1-4473	 	3-8-89	
 	 	 	 	 	 	 	 	 	
10.60 a	 	Third Amendment to the Arizona Public Service Company Deferred Compensation Plan, effective as of January 1, 1993	 	10.3 to APS’ 1993 Form 10-K Report	 	1-4473	 	3-30-94	
 	 	 	 	 	 	 	 	 	
10.61 a	 	Fourth Amendment to the Arizona Public Service Company Deferred Compensation Plan effective as of May 1, 1993	 	10.2 to APS’ September 1994 Form 10-Q Report	 	1-4473	 	11-10-94	
 	 	 	 	 	 	 	 	 	
10.62 a	 	Fifth Amendment to the Arizona Public Service Company Deferred Compensation Plan	 	10.3 to APS’ 1996 Form 10-K Report	 	1-4473	 	3-28-97	
 	 	 	 	 	 	 	 	 	
10.63 a	 	Sixth Amendment to Arizona Public Service Company Deferred Compensation Plan	 	10.8 to the Company’s 2000 Form 10-K Report	 	1-8962	 	3-14-01	
144 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.64 a	 	First Amendment effective as of January 1, 1999, to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	 	10.7 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.65 a	 	Second Amendment effective January 1, 2000 to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	 	10.10 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.66 a	 	Third Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	 	10.3 to the Company’s March 2003 Form 10-Q Report	 	1-8962	 	5-15-03	
 	 	 	 	 	 	 	 	 	
10.67 a	 	Schedules of William J. Post and Jack E. Davis to Arizona Public Service Company Deferred Compensation Plan, as amended	 	10.2 to Pinnacle West Form 10-K Report	 	1-8962	 	3-31-03	
145 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.68 a	 	Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan as amended and restated effective January 1, 1996	 	10.10 to APS’ 1995 Form 10-K Report	 	1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.69 a	 	Pinnacle West Capital Corporation and Arizona Public Service Company Directors’ Retirement Plan, effective as of January 1, 1995	 	10.7 to APS’ 1994 Form 10-K Report	 	1-4473	 	3-30-95	
 	 	 	 	 	 	 	 	 	
10.70 a	 	Letter Agreement dated July 28, 1995 between Arizona Public Service Company and Armando B. Flores	 	10.16 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.71 a	 	Letter Agreement dated as of January 1, 1996 between APS and Robert G. Matlock & Associates, Inc. for consulting services	 	10.8 to APS’ 1995 Form 10-K Report	 	1-4473	 	3-29-96	
 	 	 	 	 	 	 	 	 	
10.72 a	 	Letter Agreement dated December 21, 1993, between APS and William L. Stewart	 	10.7 to APS’ 1994 Form 10-K Report	 	1-4473	 	3-30-96	
 	 	 	 	 	 	 	 	 	
10.73 a	 	Letter Agreement dated August 16, 1996 between APS and William L. Stewart	 	10.8 to APS’ 1996 Form 10-K Report	 	1-4473	 	3-28-97	
 	 	 	 	 	 	 	 	 	
10.74 a	 	Letter Agreement between APS and William L. Stewart	 	10.2 to APS’ September 1997 Form 10-Q Report	 	1-4473	 	11-12-97	
146 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.75 a	 	Letter Agreement dated December 13, 1999 between APS and William L. Stewart	 	10.9 to 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.76 a	 	Amendment to Letter Agreement, effective as of January 1, 2002, between APS and William L. Stewart	 	10.1 to June 2002 Form 10-Q Report	 	1-8962	 	8-13-02	
 	 	 	 	 	 	 	 	 	
10.77 a	 	Letter Agreement dated October 3, 1997 between Arizona Public Service Company and James M. Levine	 	10.17 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.78 a	 	Employment Agreement dated February 27, 2003 between APS and James M. Levine	 	10.1 to the Company’s March 2003 Form 10-Q Report	 	1-8962	 	5-15-03	
 	 	 	 	 	 	 	 	 	
10.79 a	 	Summary of James M. Levine Retirement Benefits	 	10.2 to March 2002 Form 10-Q Report	 	1-8962	 	5-15-02	
 	 	 	 	 	 	 	 	 	
10.80 a	 	Employment Agreement, effective as of October 1, 2002, between APS and James M. Levine	 	10.1 to November 2002 Form 10-Q Report	 	1-8962	 	11-14-02	
 	 	 	 	 	 	 	 	 	
10.81 a	 	Letter Agreement dated June 28, 2001 between Pinnacle West Capital Corporation and Steve Wheeler	 	10.4 to the Company’s 2002 Form 10-K Report	 	1-8962	 	3-31-03	
 	 	 	 	 	 	 	 	 	
10.82 ad	 	Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries	 	10.1 to June 1999 Form 10-Q Report	 	1-8962	 	8-16-99	
147 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.83 a	 	Pinnacle West Capital Corporation Stock Option and Incentive Plan	 	10.1 to APS’ 1992 Form 10-K Report	 	1-4473	 	3-30-93	
10.84 a	 	First Amendment dated December 7, 1999 to the Pinnacle West Capital Corporation Stock Option and Incentive Plan	 	10.11 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.85 a	 	Pinnacle West Capital Corporation 1994 Long- Term Incentive Plan, effective as of March 23, 1994	 	A to the Proxy Statement for the Plan Report for the Company’s 1994 Annual Meeting of Shareholders	 	1-8962	 	4-16-94	
 	 	 	 	 	 	 	 	 	
10.86 a	 	First Amendment dated December 7, 1999 to the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan	 	10.12 to the Company’s 1999 Form 10-K Report	 	1-8962	 	3-30-00	
 	 	 	 	 	 	 	 	 	
10.87 a	 	Pinnacle West
Capital Corporation
2002 Long-Term
Incentive Plan	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
10.88 a	 	Pinnacle West
Capital Corporation
Director Equity
Participation Plan	 	B to the Proxy Statement for the Plan Report for the Company’s 1994 Annual Meeting of Shareholders	 	1-8962	 	4-16-94	
 	 	 	 	 	 	 	 	 	
10.89 a	 	Pinnacle West
Capital Corporation
2000 Director
Equity Plan	 	99.1 to the Company’s Registration Statement on Form S-8 (No. 333-40796)	 	1-8962	 	7-3-00	
 	 	 	 	 	 	 	 	 	
10.90	 	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	 	1-4473	 	3-19-92	
148 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
10.91a	 	APS Director Equity
Plan	 	10.1 to September 1997 Form 10-Q Report	 	1-4473	 	11-12-97	
 	 	 	 	 	 	 	 	 	
10.92	 	Territorial Agreement between the Company and Salt River Project	 	10.1 to APS’ March 1998 Form 10-Q Report	 	1-4473	 	5-15-98	
 	 	 	 	 	 	 	 	 	
10.93	 	Power Coordination Agreement between the Company and Salt River Project	 	10.2 to APS’ March 1998 Form 10-Q Report	 	1-4473	 	5-15-98	
 	 	 	 	 	 	 	 	 	
10.94	 	Memorandum of Agreement between the Company and Salt River Project	 	10.3 to APS’ March 1998 Form 10-Q Report	 	1-4473	 	5-15-98	
 	 	 	 	 	 	 	 	 	
10.95	 	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	 	1-4473	 	6-26-98	
 	 	 	 	 	 	 	 	 	
99.4	 	Collateral Trust Indenture among PVNGS II Funding Corp., Inc., APS and Chemical Bank, as Trustee	 	4.2 to APS’ 1992 Form 10-K Report	 	1-4473	 	3-30-93	
99.5	 	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	 	1-4473	 	3-30-93	
149 

 
\ 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
99.6 c	 	Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	 	28.1 to APS’ September 1992 Form 10-Q Report	 	1-4473	 	11-9-92	
 	 	 	 	 	 	 	 	 	
99.7 c	 	Amendment No. 1 dated as of November 1, 1986, to Participation Agreement, dated as of August 1, 1986, among PVNGS Funding Corp., Inc., Bank of America National Trust and Savings Association, State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee, APS, and the Equity Participant named therein	 	10.8 to APS’ September 1986 Form 10-Q Report by means of Amendment No. 1, on December 3, 1986 Form 8	 	1-4473	 	12-4-86	
150 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
99.8 c	 	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	 	1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.9 c	 	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	 	33-9480	 	10-24-86	
151 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
99.10 c	 	Supplemental Indenture No. 1, dated as of November 1, 1986 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease, dated as of August 1, 1986, between State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee	 	10.6 to APS’ September 1986 Form 10-Q Report by means of Amendment No. 1 on December 3, 1986 Form 8	 	1-4473	 	12-4-86	
 	 	 	 	 	 	 	 	 	
99.11 c	 	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	 	28.14 to APS’ 1992 Form 10-K Report	 	1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.12 c	 	Assignment,	 	28.3 to APS’ Form S-3	 	33-9480	 	10-24-86	
 	 	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	 	Registration Statement	 	 	 	 	
152 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
99.13 c	 	Amendment No. 1, dated as of November 1, 1986, to Assignment, Assumption and Further Agreement, dated as of August 1, 1986, between APS and State Street Bank and Trust Company, as successor to The First National Bank of Boston, as Owner Trustee	 	10.10 to APS’ September 1986 Form 10-Q Report by means of Amendment No. l on December 3, 1986 Form 8	 	1-4473	 	12-4-86	
 	 	 	 	 	 	 	 	 	
99.14 c	 	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	 	1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.15	 	Participation Agreement, dated as of December 15, 1986, among PVNGS Funding Report Corp., Inc., State Street Bank and Trust Company, as successor to The First National Bank of Boston, in its individual capacity and as Owner Trustee, Chemical Bank, in its individual capacity and as Indenture Trustee under a Trust Indenture, APS, and the Owner Participant named therein	 	28.2 to APS’ September 1992 Form 10-Q Report	 	1-4473	 	11-9-92	
153 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
99.16	 	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	 	1-4473	 	8-10-87	
 	 	 	 	 	 	 	 	 	
99.17	 	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	 	1-4473	 	3-30-93	
154 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
99.18	 	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	 	1-4473	 	1-20-87	
 	 	 	 	 	 	 	 	 	
99.19	 	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	 	1-4473	 	8-24-87	
155 

 

Exhibit No.	 	Description	 	Originally Filed as Exhibit:	 	File No. b	 	Date Effective	
	 		 		 		 		
99.20	 	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	 	1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.21	 	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	 	1-4473	 	1-20-87	
 	 	 	 	 	 	 	 	 	
99.22	 	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	 	1-4473	 	3-30-93	
 	 	 	 	 	 	 	 	 	
99.23 c	 	Indemnity Agreement dated as of March 17, 1993 by APS	 	28.3 to APS’ 1992 Form 10-K Report	 	1-4473	 	3-30-93	
156 

 

 	 	 	 	 	 	 	 	 	
Exhibit No.
	 	Description
	 	Originally Filed as Exhibit:
	 	File No. b
	 	Date Effective
	
99.24	 	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	 	1-4473	 	8-10-87	
 	 	 	 	 	 	 	 	 	
99.25	 	Rate Reduction Agreement dated December 4, 1995 between APS and the ACC Staff	 	10.1 to APS’ December 4, 1995 Form 8-K Report	 	1-4473	 	12-14-95	
 	 	 	 	 	 	 	 	 	
99.26	 	ACC Order dated April 24, 1996	 	10.1 to APS’ March 1996 Form 10-Q Report	 	1-4473	 	5-14-96	
 	 	 	 	 	 	 	 	 	
99.27	 	Arizona Corporation Commission Order, Decision No. 59943, dated December 26, 1996, including the Rules regarding the introduction of retail competition in Arizona	 	99.1 to APS’ 1996 Form 10-K Report	 	1-4473	 	3-28-97	
 	 	 	 	 	 	 	 	 	
99.28	 	Arizona Corporation Commission Order, Decision No. 61973, dated October 6, 1999, approving APS’ Settlement Agreement	 	10.1 to APS’ September 1999 10-Q Report	 	1-4473	 	11-15-99	
 	 	 	 	 	 	 	 	 	
99.29	 	Addendum to Settlement Agreement	 	10.1 to the Company’s September 2000 Form 10-Q Report	 	1-8962	 	11-14-00	
 	 	 	 	 	 	 	 	 	
99.30	 	Arizona Corporation Commission Order, Decision No. 61969, dated September 29, 1999, including the Retail Electric Competition Rules	 	10.2 to APS’ September 1999 Form 10-Q Report	 	1-4473	 	11-15-99	
157

 

 	 	 	 	 	 	 	 	 	
 Exhibit No.
	 	Description
	 	Originally Filed as Exhibit:
	 	File No. b
	 	Date Effective
	
99.31	 	Track ‘A’ Appeals Issues – Principles for Resolution	 	99.1 to the Company’s November 15, 2002 Form 8-K	 	1-8962	 	12-16-02	
 	 	 	 	 	 	 	 	 	
99.32	 	ACC Opinion and Order dated September 10, 2002, Decision No. 65154 (Track A Order)	 	99.1 to the Company’s September 10, 2002 Form 8-K Report	 	1-8962	 	9-17-02	
 	 	 	 	 	 	 	 	 	
99.33	 	ACC Decision No. 65796 dated April 4, 2003 (Financing Order)	 	99.3 to the Company’s March 2003 Form 10-Q Report	 	1-8962	 	5-15-03	

      a Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
      b 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.
      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.
Reports on Form 8-K
     During the quarter ended December 31, 2003, and the period ended March 15, 2004, the Company filed the following Reports on Form 8-K:
     Report dated September 30, 2003 containing exhibits comprised of financial information, earnings variance explanations and an earnings news release (Item 7 and Item 9).
     Report dated October 6, 2003 regarding earnings outlook and slides presented at analysts and investors meetings (Item 5, Item 7 and Item 9).
     Report dated November 5, 2003 containing a financial statement reclassification and relating to the ACC approval of the issuance of a rate adjustment mechanism order. This Current Report on Form 8-K includes the consolidated balance sheets of Pinnacle West as of December 31, 2002 and
158

 

2001, 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, 2002. Schedule II – Valuation and Qualifying Accounts is also included (Item 5).
     Report dated November 6, 2003 comprised of exhibits to Registration Statement No. 333-101457 (Item 7).
     Report dated December 31, 2003 containing exhibits comprised of financial information, earnings variance explanations and an earnings news release (Item 7 and Item 9).
     Report dated January 8, 2004 regarding a delay in the schedule for the hearing for APS’ pending general rate case (Item 5 and Item 7).
     Report dated January 27, 2004 regarding APS’ Summary of Responses Received to its Power Supply Resource Request for Proposals dated December 3, 2003 (Item 5 and Item 7).
     Report dated January 30, 2004 containing exhibits comprised of a slide presentation for use at an analyst conference (Item 7 and Item 9).
     Report dated February 3, 2004 regarding the ACC Staff’s and RUCO’s initial written testimony filed with the ACC (Item 5).
159

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

 	PINNACLE WEST CAPITAL CORPORATION
                 (Registrant)	
Date: March 15, 2004	 	 	
 	 	/s/ William J. Post	
 		
 	 	(William J. Post, Chairman of the	
 	 	Board of Directors and Chief	
 	 	Executive Officer)	
     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
	 	Title
	 	Date
	
/s/ William J. Post
(William J. Post, Chairman of the Board of Directors and Chief Executive Officer)	 	Principal Executive Officer and Director	 	March 15, 2004	
 	 	 	 	 	
/s/ Jack E. Davis

(Jack E. Davis, President and Chief Operating Officer)	 	Director	 	March 15, 2004	
 	 	 	 	 	
/s/ Donald E. Brandt

(Donald E. Brandt, Executive Vice President and) Chief Financial Officer)	 	Principal Accounting Officer and Principal Financial Officer	 	March 15, 2004	
160

 

 	 	 	 	 	
Signature
	 	Title
	 	Date
	
/s/ Edward N. Basha, Jr.

(Edward N. Basha, Jr.)	 	Director	 	March 15, 2004	
 	 	 	 	 	
/s/ Michael L. Gallagher

(Michael L. Gallagher)	 	Director	 	March 15, 2004	
 	 	 	 	 	
/s/ Pamela Grant

(Pamela Grant)	 	Director	 	March 15, 2004	
 	 	 	 	 	
/s/ Roy A. Herberger, Jr.

(Roy A. Herberger, Jr.)	 	Director	 	March 15, 2004	
 	 	 	 	 	
/s/ Martha O. Hesse

(Martha O. Hesse)	 	Director	 	March 15, 2004	
 	 	 	 	 	
/s/ William S. Jamieson, Jr.

(William S. Jamieson, Jr.)	 	Director	 	March 15, 2004	
 	 	 	 	 	
/s/ Humberto S. Lopez

(Humberto S. Lopez)	 	Director	 	March 15, 2004	

(Robert G. Matlock)	 	Director	 	 	
 	 	 	 	 	
/s/ Kathryn L. Munro

(Kathryn L. Munro)	 	Director	 	March 15, 2004	
 	 	 	 	 	
/s/ Bruce J. Nordstrom

(Bruce J. Nordstrom)	 	Director	 	March 15, 2004	
 	 	 	 	 	
/s/ William L. Stewart

(William L. Stewart)	 	Director	 	March 15, 2004	
161

 
INDEX TO EXHIBITS 

Exhibit No.	 	Description	
	 		
3.1	 	—	 	Pinnacle West Capital Corporation Bylaws, amended as of January 21, 2004	
 	 	 	 	 	
10.1 a	 	—	 	2004 Officer Variable Incentive Plan	
 	 	 	 	 	
10.2 a	 	—	 	2002 CEO Variable Incentive Plan	
 	 	 	 	 	
10.3	 	—	 	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of December 19, 2003	
 	 	 	 	 	
10.4	 	—	 	Amendment No. 7 to the Decommissioning Trust Agreement (PVNGS Unit 2), dated as of December 19, 2003	
 	 	 	 	 	
10.5	 	—	 	Amendment No. 4 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of December 19, 2003	
 	 	 	 	 	
10.6 a	 	—	 	Fourth Amendment to the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan	
 	 	 	 	 	
10.7 a	 	—	 	Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, amended and restated as of January 1, 2003	
 	 	 	 	 	
12.1	 	—	 	Ratio of Earnings to Fixed Charges	
 	 	 	 	 	
21.1	 	—	 	Subsidiaries of the Company	
 	 	 	 	 	
23.1	 	—	 	Consent of Deloitte & Touche LLP	
 	 	 	 	 	
31.1	 	—	 	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	 	—	 	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	 	—	 	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	 	—	 	Risk Factors	

  

 

a Management contract or compensatory plan or arrangement to be filed as an exhibit pursuant to Item 14(c) of Form 10-K.
For a description of the Exhibits incorporated in this filing by reference, see Part IV, Item 14.

EXHIBIT 3.1
BYLAWS
OF
PINNACLE WEST CAPITAL CORPORATION
 (AMENDED AS OF JANUARY 21, 2004)
I. REFERENCES; SENIORITY
1.01. REFERENCES. Any reference herein made to law will be deemed to refer to the law of the State of Arizona, including any applicable provision or provisions of Chapters 1-17 and Chapter 23 of Title 10, Arizona Revised Statutes (or its successor), as at any given time in effect. Any reference herein made to the Articles will be deemed to refer to the applicable provision or provisions of the Articles of Incorporation of the Company, and all amendments thereto, as at any given time on file with the Arizona Corporation Commission (this reference to that Commission being intended to include any successor to the incorporating and related functions being performed by that Commission at the date of the initial adoption of these Bylaws).
1.02. SENIORITY. Except as indicated in Part X of these Bylaws, the law and the Articles (in that order of precedence) will in all respects be considered senior and superior to these Bylaws, with any inconsistency to be resolved in favor of the law and the Articles (in that order of precedence), and with these Bylaws to be deemed automatically amended from time to time to eliminate any such inconsistency which may then exist.
1.03. SHAREHOLDERS OF RECORD. Except as otherwise required by law and subject to any procedure established by the Company pursuant to Arizona Revised Statutes Section 10-723 (or any comparable successor provision), the word "shareholder" as used herein shall mean one who is a holder of record of shares in the Company.
II. SHAREHOLDERS MEETINGS
2.01. ANNUAL MEETINGS. An annual meeting of shareholders shall be held for the election of directors at such date, time and place, either within or without the State of Arizona, as may be designated by resolution of the Board of Directors from time to time. Any other proper business may be transacted at the annual meeting. A special meeting may be called and held in lieu of an annual meeting pursuant to the provisions of Section 2.02 below, and the same proceedings (including the election of directors) may be conducted thereat as at a regular meeting. Any director elected at any annual meeting, or special meeting in lieu of an annual meeting, will continue in office until the election of his or her successor, subject to his or her (a) earlier resignation pursuant to Section 6.01 below, (b) removal pursuant to Section 3.13 below, or (c) death or disqualification.
2.02. SPECIAL MEETINGS. Except as otherwise required by law, special meetings of the shareholders may be held whenever and wherever called by the Chairman of the Board, the President, or a majority of the Board of Directors, but such special meetings may not be called by any other person or persons. Business transacted at any special meeting of shareholders shall be limited to the purposes stated in the notice.
2.03. NOTICE. Notice of any meeting of the shareholders will be given as provided by law to each shareholder entitled to vote at such meeting and, if required by law, to each other shareholder of the Company. Any such notice may be waived as provided by law.
2.04. RIGHT TO VOTE. For each meeting of the shareholders, the Board of Directors will fix in advance a record date as contemplated by law, and the shares of stock and the shareholders "entitled to vote" (as that or any similar term is herein used) at any meeting of the shareholders will be determined as of the applicable record date. The Secretary (or in his or her absence an Assistant Secretary) will see to the making and production of any record of shareholders entitled to vote or otherwise entitled to notice of shareholders meetings, in either case which is required by law. Any voting entitlement may be exercised through proxy, or in such other manner as specifically provided by law, in accordance with the applicable law. In the event of contest, the burden of proving the validity of any undated or irrevocable proxy will rest with the person seeking to exercise the same. A telegram, cablegram, or facsimile appearing to have been transmitted by a shareholder (or by his or her duly authorized attorney-in-fact) or other means of voting by telephone or electronic transmission may be accepted as a sufficiently written and executed proxy if otherwise permitted by law.
2.05. NOTICE OF SHAREHOLDER BUSINESS AND NOMINATIONS.
(a) Annual Meetings of Shareholders. (1) Nominations of persons for election to the Board of Directors of the Company and the proposal of business to be considered by the shareholders may be made at an annual meeting of shareholders only (i) pursuant to the Company's notice of meeting (or any supplement thereto), (ii) by or at the direction of the Board of Directors or
(iii) by any shareholder of the Company who was a shareholder at the time the respective notice provided for in this Section 2.05 is delivered to the Secretary of the Company, who is entitled to vote at the meeting and who complies with the notice procedures set forth in this Section 2.05.
(2) For nominations or other business to be properly brought before an annual meeting by a shareholder pursuant to clause (iii) of paragraph (a)(1) of this
Section 2.05, the shareholder must have given timely notice thereof in writing to the Secretary of the Company and any such proposed business other than the nominations of persons for election to the Board of Directors must constitute a proper matter for shareholder action. To be timely, a shareholder notice shall be delivered to the Secretary at the principal executive offices of the Company not later than the close of business (a) with respect to business to be brought before the meeting, on the ninetieth day or not earlier than the close of business on the one hundred twentieth day prior to the first anniversary of the preceding year's annual meeting (provided, however, that in the event that the date of the annual meeting has been changed by more than thirty days from such anniversary date, notice by the shareholder must be so delivered not later than the close of business on the tenth day following the day on which public announcement of the date of such meeting was mailed or public
- 2 -
disclosure of the annual meeting was made, whichever first occurs), and (b) with respect to nominations of persons to be elected to the Board of Directors, the one-hundred and eightieth day prior to the date of the meeting at which the election is to occur. In no event shall the public announcement of an adjournment or postponement of an annual meeting commence a new time period (or extend any time period) for the giving of a shareholder's notice as described above. Such shareholder's notice shall set forth: (a) as to each person whom the shareholder proposes to nominate for election as a director, all information relating to such person that is required to be disclosed in solicitations of proxies for election of directors in an election contest, or is otherwise required, in each case pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and Rule 14a-11 thereunder (and such person's written consent to being named in the proxy statement as a nominee and to serving as a director if elected); (b) as to any other business that the shareholder proposes to bring before the meeting, a brief description of the business desired to be brought before the meeting, the text of the proposal or business (including the text of any resolutions proposed for consideration and, in the event that such business includes a proposal to amend the Bylaws of the Company, the language for the proposed amendment), the reasons for conducting such business at the meeting, and any material interest in such business of such shareholder and the beneficial owner, if any, on whose behalf the proposal is made; and (c) as to the shareholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made, (i) the name and address of such shareholder, as they appear on the Company's books, and of such beneficial owner, (ii) the class and number of shares of capital stock of the Company that are owned beneficially and of record by such shareholder and such beneficial owner, (iii) a representation that the shareholder is a holder of record of stock of the Company entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to propose such business or nomination, and (iv) a representation whether the shareholder or the beneficial owner, if any, intends or is part of a group that intends (a) to deliver a proxy statement and/or form of proxy to holders of at least the percentage of the Company's outstanding capital stock required to approve or adopt the proposal or elect the nominee and/or (b) otherwise to solicit proxies from shareholders in support of such proposal or nomination. The Company may require any proposed nominee to furnish such other information as it may reasonably require to determine the eligibility of such proposed nominee to serve as a director of the Company.
(b) Special Meetings of Shareholders. Only such business shall be conducted at a special meeting of shareholders as shall have been brought before the meeting pursuant to the Company's notice of meeting.
- 3 -
(c) General. (1) Only such persons who are nominated in accordance with the procedures set forth in this
Section 2.05 shall be eligible to be elected at an annual or special meeting of shareholders of the Company to serve as directors and only such business shall be conducted at a meeting of shareholders as shall have been brought before the meeting in accordance with the procedures set forth in this
Section 2.05. Except as otherwise provided by law, the Chairman of the meeting shall have the power and duty (a) to determine whether a nomination or any business proposed to be brought before the meeting was made or proposed, as the case may be, in accordance with the procedures set forth in this
Section 2.05 (including whether the shareholder or beneficial owner, if any, on whose behalf the nomination or proposal is made solicited (or is part of a group that solicited) or did not so solicit, as the case may be, proxies in support of such shareholder's nominee or proposal in compliance with such shareholder's representation as required by clause (a)(2)(c)(iv) of this Section 2.05) and (b) if any proposed nomination or business was not made or proposed in compliance with this Section 2.05, to declare that such nomination shall be disregarded or that such proposed business shall not be transacted.
(2) For purposes of this Section 2.05, "public announcement" shall mean disclosure in a press release reported by the Dow Jones News Service, Associated Press or comparable national news service or in a document publicly filed by the Company with the Securities and Exchange Commission pursuant to
Section 13, 14 or 15(d) of the Exchange Act.
(3) Notwithstanding the foregoing provisions of this
Section 2.05, a shareholder shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section 2.05. Nothing in this Section 2.05 shall be deemed to affect any rights (a) of shareholders to request inclusion of proposals in the Company's proxy statement pursuant to Rule 14a-8 of the Exchange Act or (b) of the holders of any series of Preferred Stock to elect directors pursuant to any applicable provisions of the Articles.
2.06. RIGHT TO ATTEND. Except only to the extent of persons designated by the Board of Directors or the Chairman of the meeting to assist in the conduct of the meeting (as referred to in Sections 2.08 and 2.09 below) and except as otherwise permitted by the Board or such Chairman, the persons entitled to attend any meeting of shareholders may be confined to (i) shareholders entitled to vote thereat and other shareholders entitled to notice of the meeting and (ii) the persons upon whom proxies valid for purposes of the meeting have been conferred or their duly appointed substitutes (if the related proxies confer a power of substitution); provided, however, that the Board of Directors or the Chairman of the meeting may establish rules limiting the number of persons referred to in clause (ii) as being entitled to attend on behalf of any shareholder so as to preclude such an excessively large representation of such shareholder at the meeting as, in the judgment of the Board or such Chairman, would be unfair to other shareholders represented at the meeting or be unduly disruptive of the orderly conduct of
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business at such meeting (whether such representation would result from fragmentation of the aggregate number of shares held by such shareholder for the purpose of conferring proxies, from the naming of an excessively large proxy delegation by such shareholder or from employment of any other device). A person otherwise entitled to attend any such meeting will cease to be so entitled if, in the judgment of the Chairman of the meeting, such person engages thereat in disorderly conduct impeding the proper conduct of the meeting in the interests of all shareholders as a group.
2.07. QUORUM. Except as otherwise provided by law, the Articles or these Bylaws, at each meeting of shareholders the presence in person or by proxy of the holders of a majority in voting power of the outstanding shares of stock entitled to vote at the meeting shall be necessary and sufficient to constitute a quorum.
2.08. ELECTION INSPECTORS. The Board of Directors, in advance of any shareholders meeting may appoint an election inspector or inspectors to act at such meeting (and any adjournment thereof). If an election inspector or inspectors are not so appointed, the Chairman of the meeting may or, upon the request of any person entitled to vote at the meeting will, make such appointment. If any person appointed as an inspector fails to appear or to act, a substitute may be appointed by the Chairman of the meeting. If appointed, the election inspector or inspectors (acting through a majority of them if there be more than one) will determine the number of shares outstanding, the authenticity, validity and effect of proxies, the credentials of persons purporting to be shareholders or persons named or referred to in proxies, and the number of shares represented at the meeting in person and by proxy; they will receive and count votes, ballots and consents and announce the results thereof; they will hear and determine all challenges and questions pertaining to proxies and voting; and, in general, they will perform such acts as may be proper to conduct elections and voting with complete fairness to all shareholders. No such election inspector need be a shareholder of the Company.
2.09. ORGANIZATION AND CONDUCT OF MEETINGS. Each shareholders meeting will be called to order and thereafter chaired by the Chairman of the Board if there then is one; or, if not, or if the Chairman of the Board is absent or so requests, then by the President; or if both the Chairman of the Board and the President are unavailable, then by such other officer of the Company or such shareholder as may be appointed by the Board of Directors. The Secretary (or in his or her absence an Assistant Secretary) of the Company will act as secretary of each shareholders meeting; if neither the Secretary nor an Assistant Secretary is in attendance, the Chairman of the meeting may appoint any person (whether a shareholder or not) to act as secretary thereat. After calling a meeting to order, the Chairman thereof may require the registration of all shareholders intending to vote in person, and the filing of all proxies, with the election inspector or inspectors, if one or more have been appointed (or, if not, with the secretary of the meeting). After the announced time for such filing of proxies has ended, no further proxies or changes, substitutions or revocations of proxies will be accepted. If directors are to be elected, a tabulation of the proxies so filed will, if any person entitled to vote in such election so requests, be announced at the meeting (or adjournment thereof) prior to the closing of the election polls.
Absent a showing of bad faith on his or her part, the Chairman of a meeting will, among other things, have absolute authority to determine the order of business to be conducted at such
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meeting and to establish rules for, and appoint personnel to assist in, preserving the orderly conduct of the business of the meeting (including any informal, or question and answer, portions thereof). Rules, regulations or procedures regarding the conduct of the business of a meeting, whether adopted by the Board of Directors or prescribed by the Chairman of the meeting, may include, without limitation, the following: (i) the establishment of an agenda or order of business for the meeting; (ii) rules and procedures for maintaining order at the meeting and the safety of those present; (iii) limitations on attendance at or participation in the meeting to shareholders of record of the Company, their duly authorized and constituted proxies (subject to Section 2.06) or such other persons as the Chairman of the meeting shall determine; (iv) restrictions on entry to the meeting after the time fixed for the commencement thereof; and (v) limitations on the time allotted to questions or comments by participants. Unless and to the extent determined by the Board of Directors or the Chairman of the meeting, meetings of shareholders shall not be required to be held in accordance with the rules of parliamentary procedure. Any informational or other informal session of shareholders conducted under the auspices of the Company after the conclusion of or otherwise in conjunction with any formal business meeting of the shareholders will be chaired by the same person who chairs the formal meeting, and the foregoing authority on his or her part will extend to the conduct of such informal session.
2.10. VOTING. The number of shares voted on any matter submitted to the shareholders which is required to constitute their action thereon or approval thereof will be determined in accordance with applicable law, the Articles, and these Bylaws, if applicable. No ballot or change of vote will be accepted after the polls have been declared closed following the ending of the announced time for voting.
2.11. SHAREHOLDER APPROVAL OR RATIFICATION. The Board of Directors may submit any contract or act for approval or ratification at any duly constituted meeting of the shareholders, the notice of which either includes mention of the proposed submittal or is waived as provided in Section 2.03 above. Except as otherwise required by law (e.g., Arizona Revised Statutes Section 10-863), if any contract or act so submitted is approved or ratified by a majority of the votes cast thereon at such meeting, the same will be valid and as binding upon the Company and all of its shareholders as it would be if approved and ratified by each and every shareholder of the Company.
2.12. CONTROL SHARE ACT. The provisions of Section 10-2721 through and including Section 10-2727 of the Arizona Revised Statutes shall not apply to the Company.
2.13. ADJOURNMENTS. Any meeting of shareholders, annual or special, may adjourn from time to time to reconvene at the same or some other place, and notice need not be given of any such adjourned meeting if the time and place thereof are announced at the meeting at which the adjournment is taken. At the adjourned meeting the Company may transact any business that might have been transacted at the original meeting. If the adjournment is for more than one hundred and twenty days, or if after the adjournment a new record date is fixed for the adjourned meeting, notice of the adjourned meeting shall be given to each shareholder of record entitled to vote at the meeting.
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III. BOARD OF DIRECTORS
3.01. MEMBERSHIP. The Board of Directors of the corporation shall consist of not less then nine (9) nor more than twenty-one (21) shareholders of the Company or of any parent corporation thereof (except that it shall not be a requirement that any member of the initial Board of Directors be a shareholder of the Company or of any parent corporation thereof), and shall be divided into three classes in the manner provided in the Articles (Art. Fifth). The Board will have the exclusive power to increase or decrease its size within such limits. Any vacancy occurring in the Board, whether by reason of death, resignation, disqualification or otherwise, may be filled by the directors as contemplated by law and as provided in the Articles (Art. Fifth). Any such increase in the size of the Board, and the filling of any vacancy created thereby, will require action by a majority of the whole membership of the Board as comprised immediately before such increase.
3.02. QUALIFICATIONS. In order to qualify as a director, a person must be the owner of one or more shares of the capital stock of the Company or of any parent corporation thereof at the time of assuming office (except as may otherwise be provided in these Bylaws or in the Articles) and for so long thereafter as such person remains in office. A person will cease to qualify as a director if he or she (i) is in good faith determined by a majority of the other directors then in office to be physically or mentally incapable of competent performance as a director for a period, starting with inception of the incapacity, that has extended or is likely to extend for more than six months or
(ii) has failed to attend six successive regular meetings of the Board (as determined in accordance with Section 3.03 below) unless and to the extent such failure is waived by a majority of the other directors then in office; however, disqualification pursuant to clause (i) or (ii) of this sentence will not preclude the subsequent election or appointment of such person as a director by the shareholders or the Board if a majority of the directors in office immediately prior to the submission of such person for election or appointment shall determine that his or her prior incapacity or principal reason for prior non-attendance no longer exists. A person will not qualify for election or appointment as a director, whether initially or on re-election and whether by the shareholders at their annual meeting or by the Board of Directors as contemplated in Section 3.01 above, if such person's 72nd birthday occurs on or has occurred before the date of such election, appointment or re-election. A person who has been a full-time employee of the Company within twelve months prior to the date of any election will not qualify for election as a director on that date unless he or she then remains a full-time employee of the Company or unless the Board of Directors specifically authorizes the election of such person (but it is not intended that any such authorization will extend a person's service on the Board beyond the age limitation set out in the preceding sentence). A person who has qualified by age or employment status for his or her most recent election as a director may serve throughout the term for which such person was elected, notwithstanding the occurrence of his or her 72nd birthday or cessation of full-time employment by the Company between the date of such election and the end of such term, subject, however, to his or her otherwise remaining qualified for such office.
3.03. REGULAR MEETINGS. A regular annual meeting of the directors is to be held as soon as practicable after the adjournment of each annual shareholders meeting either at the place of the shareholders meeting or at such other place as the directors elected at the shareholders meeting may have been informed of at or before the time of their election. Regular meetings,
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other than the annual ones, may be held at such intervals at such places and at such times as the Board of Directors may provide.
3.04. SPECIAL MEETINGS. Special meetings of the Board of Directors may be held whenever and wherever called for by the Chairman of the Board, the President or the number of directors which would be required to constitute a quorum.
3.05. NOTICE. No notice need be given of regular meetings of the Board of Directors. Notice of the time and place (but not necessarily the purpose or all of the purposes) of any special meeting will be given to each director in person or by telephone, or via mail, telegram, facsimile, or other electronic transmission addressed in the manner appearing on the Company's records. Notice to any director of any such special meeting will be deemed given sufficiently in advance when (i) if given by mail, the same is deposited in the United States mail at least four days before the meeting date, with postage thereon prepaid,
(ii) if given by telegram, the same is delivered to the telegraph office for fast transmittal at least 48 hours prior to the convening of the meeting, (iii) if given by facsimile or other electronic transmission, the same is received by the director or an adult member of his or her office staff or household, at least 24 hours prior to the convening of the meeting, or (iv) if personally delivered or given by telephone, the same is handed, or the substance thereof is communicated over the telephone to the director or to an adult member of his or her office staff or household, at least 24 hours prior to the convening of the meeting. Any such notice may be waived as provided by law. No call or notice of a meeting of directors will be necessary if each of them waives the same in writing or by attendance. Any meeting, once properly called and noticed (or as to which call and notice have been waived as aforesaid) and at which a quorum is formed, may be adjourned to another time and place by a majority of those in attendance.
3.06. QUORUM; VOTING. A quorum for the transaction of business at any meeting or adjourned meeting of the directors will consist of a majority of those then in office. Any matter submitted to a meeting of the directors will be resolved by a majority of the votes cast thereon, except as otherwise required by these Bylaws (Sections 3.01 and 3.02 above and Section 3.07 below), by law or by any applicable Article. However, in case of an equality of votes, the Chairman of the meeting will have a second or deciding vote. Where action by a majority of the whole membership is required, such requirement will be deemed to relate to a majority of the directors in office at the time the action is taken. In computing any such majority, whether for purposes of determining the presence of a quorum or the adequacy of the vote on any proposed action, any unfilled vacancies at the time existing in the membership of the Board will be excluded from the computation.
3.07. EXECUTIVE COMMITTEE. The Board of Directors may, by resolution adopted by a majority of the whole Board, name three or more of its members as an Executive Committee. Such Executive Committee will have and may exercise the powers of the Board of Directors in the management of the business and affairs of the Company while the Board is not in session, except only as precluded by law or where action other than by a majority of the votes cast is required by these Bylaws, or the law (all as referred to in Section 3.06 above), and subject to such limitations as may be included in any applicable resolution passed by a majority of the whole membership of the Board. A majority of those named to the Executive Committee will constitute a quorum.
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3.08. OTHER COMMITTEES. The Board of Directors may designate one or more additional committees, each committee to consist of one or more of the directors of the Company. The Board of Directors may designate one or more directors as alternate members of any committee, who may replace any absent or disqualified member at any meeting of the committee. Any such committee, to the extent permitted by law and to the extent provided in the resolution of the Board of Directors, shall have and may exercise all the powers and authority of the Board of Directors in the management of the business and affairs of the Company, and may authorize the seal of the Company to be affixed to all papers that may require it.
3.09. COMMITTEE FUNCTIONING. Notice requirements and related waiver provisions for meetings of the Executive Committee and other committees of the Board will be the same as those set forth in Section 3.05 above for meetings of the Board of Directors. Except as provided in the next two succeeding sentences, a majority of those named to the Executive Committee or any other committee of the Board will constitute a quorum at any meeting thereof (with the effect of departure of committee members from a meeting and the computation of a majority of committee members to be in accordance with the applicable policies of Section 3.06 above), and any matter submitted to a meeting of any such committee will be resolved by a majority of the votes cast thereon. No distinction will be made among ex-officio or other members of any such committee for quorum, voting or other purposes, except that the membership of any committee (including the Executive Committee), in performing any function vested in it as herein contemplated, may be deemed to exclude any officer or employee of the Company, in either case, or other person having a direct or indirect personal interest in any proposed exercise of such function, whose exclusion for that purpose is deemed appropriate by a majority of the other members of such committee proposing to perform such function. All committees are to keep regular minutes of the transactions of their meetings.
3.10. ACTION BY TELEPHONE OR CONSENT. Any meeting of the Board or any committee thereof may be held by conference telephone or similar communications equipment as permitted by law, in which case any required notice of such meeting may generally describe the arrangements (rather than the place) for the holding thereof, and all other provisions herein contained or referred to will apply to such meeting as though it were physically held at a single place. Action may also be taken by the Board or any committee thereof without a meeting if the members thereof consent in writing thereto as contemplated by law.
3.11. PRESUMPTION OF ASSENT. A director of the Company who is present at a meeting of the Board of Directors, or of any committee when corporate action is taken is deemed to have assented to the action taken unless either (i) the director objects at the beginning of the meeting or promptly on the director's arrival to holding it or transacting business at the meeting; (ii) the director's dissent or abstention from the action taken is entered in the minutes of the meeting; or (iii) the director delivers written notice of the director's dissent or abstention to the presiding officer of the meeting before its adjournment or to the Company before 5:00 P.M. on the next business day after the meeting. The right of dissent or abstention is not available to a director who votes in favor of the action taken.
3.12. COMPENSATION. By resolution of the Board, the directors may be paid their expenses, if any, of attendance at each meeting of the Board of Directors, or of any committee, and may be paid a fixed sum for attendance at each such meeting and/or a stated salary as a
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director or committee member. No such payment will preclude any director from serving the Company in any other capacity and receiving compensation therefor.
3.13. REMOVAL. Any director or the entire Board of Directors may be removed with or without cause, only at a special meeting of shareholders called for that purpose, by the affirmative vote of sixty-six and two-thirds percent (66 2/3%) of the issued and outstanding shares of stock then entitled to vote on the election of directors, except that if less than the entire Board of Directors is to be removed, no one of the directors may be removed if the votes cast against the director's removal would be sufficient to elect the director if then cumulatively voted at an election for the class of directors of which the director is a part.
IV. OFFICERS - GENERAL
4.01. ELECTIONS AND APPOINTMENTS. The directors may elect or appoint one or more of the officers of the Company contemplated in Part V below. Any such election or appointment will regularly take place at the annual meeting of the directors, but elections of officers may be held at any other meeting of the Board. A person elected or appointed to any office will continue to hold that office until the election or appointment of his or her successor, subject to action earlier taken pursuant to Section 4.04 or 6.01 below. Any person may hold more than one office.
4.02. ADDITIONAL APPOINTMENTS. In addition to the officers contemplated in Part V below, the Board of Directors may create other corporate positions, and appoint persons thereto, with such authority to perform such duties as may be prescribed from time to time by the Board of Directors, by the President or by the superior officer of any person so appointed. Notwithstanding such additional appointments, only those persons whose offices are described in Part V are to be considered an officer of the Company unless the resolution or other Board action appointing such person expressly states that such person is to be considered an officer of the Company. Each of such persons (in the order designated by the Board or the superior officer of such person) will be vested with all of the powers and charged with all of the duties of his or her superior officer in the event of such superior officer's absence or disability.
4.03. BONDS AND OTHER REQUIREMENTS. The Board of Directors may require any officer or other appointee to give bond to the Company (with sufficient surety, and conditioned upon the faithful performance of the duties of his or her office or position) and to comply with such other conditions as may from time to time be required of him or her by the Board.
4.04. REMOVAL OR DELEGATION. Provided that a majority of the whole membership thereof concurs therein, the Board of Directors may remove any officer of the Company as provided by law and declare his or her office or offices vacant or abolished or, in the case of the absence or disability of any officer or for any other reason considered sufficient, may temporarily delegate his or her powers and duties to any other officer or to any director. Similar action may be taken by the Board of Directors in regard to appointees designated pursuant to Section 4.02 above.
4.05. SALARIES. Officer salaries may from time to time be fixed by the Board of Directors or (except as to his or her own) be left to the discretion of the Chief Executive Officer
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or the President. No officer will be prevented from receiving a salary by reason of the fact that he or she is also a director of the Company.
V. SPECIFIC OFFICERS, FUNCTIONS AND POWERS
5.01. CHAIRMAN OF THE BOARD. The Board of Directors may elect a Chairman to serve as a general executive officer of the Company and, if specifically designated as such by the Board, as the Chief Executive Officer of the Company. If elected, the Chairman will preside at all meetings of the directors and be vested with such other powers and duties as the Board may from time to time delegate to him or her.
5.02. CHIEF EXECUTIVE OFFICER. Subject to the control of the Board of Directors exercised as hereinafter provided, the Chief Executive Officer of the Company will supervise its business and affairs and the performance of their respective duties by all other officers, by appointees designated pursuant to
Section 4.02 above, and by such additional appointees to such additional positions (corporate, divisional or otherwise) as the Chief Executive Officer may designate, with authority on his or her part to delegate the foregoing duty of supervision to such extent and to such person or persons as may be determined by the Chief Executive Officer. Except as otherwise indicated from time to time by resolution of the Board of Directors, its management of the business and affairs of the Company will be implemented through the office of the Chief Executive Officer.
5.03. PRESIDENT AND VICE PRESIDENTS. Unless specified to the contrary by resolution of the Board of Directors, the President will be the Chief Executive Officer of the Company. In addition to the supervisory functions above set forth on the part of the Chief Executive Officer or in lieu thereof if a contrary specification is made by the Board relative to the Chief Executive Officer, the President will be vested with such powers and duties as the Board may from time to time designate. Vice Presidents may be elected by the Board of Directors to perform such duties as may be designated by the Board or be assigned or delegated to them by their respective superior officers. The Board may identify (i) one or more Vice Presidents as "Executive" or "Senior" Vice Presidents and (ii) the President or any Vice President as "General Manager" of the Company and the title of any Vice President may include words indicative of his or her particular area of responsibility and authority. Vice Presidents will succeed to the responsibilities and authority of the President, in the event of his or her absence or disability, in the order consistent with their respective titles or regular duties or as specifically designated by the Board of Directors.
5.04. TREASURER AND SECRETARY. The Treasurer and Secretary each will perform all such duties normally associated with his or her office (including, in the case of the Secretary, the giving of notice and the preparation and retention of minutes of corporate proceedings and the custody of corporate records and the seal of the Company) as are not assigned to a Vice President of the Company, along with such other duties as may be designated by the Board or be assigned or delegated to them by their respective superior officers. The Board may appoint one or more Assistant Treasurers or Assistant Secretaries, each of whom (in the order designated by the Board or their respective superior officers) will be vested with all of the powers and charged with all of the duties of the Treasurer or the Secretary (as the case may be) in the event of his or her absence or disability.
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5.05. SPECIFIC POWERS. Except as may otherwise be specifically provided in a resolution of the Board of Directors, any of the officers referred to in this Part V will be a proper officer to authenticate records of the Company and to sign on behalf of the Company any deed, bill of sale, assignment, option, mortgage, pledge, note, bond, debenture, evidence of indebtedness, application, consent (to service of process or otherwise), agreement, indenture or other instrument of importance to the Company. Any such officer may represent the Company at any meeting of the shareholders or members of any corporation, association, partnership, joint venture or other entity in which this Company then has an interest, and may vote such interest in person or by proxy appointed by him or her, provided that the Board of Directors may from time to time confer the foregoing authority upon any other person or persons.
VI. RESIGNATIONS AND VACANCIES
6.01. RESIGNATIONS. Any director, committee member or officer may resign from his or her office at any time by written notice as specified in accordance with Arizona Revised Statutes Sections 10-807 and 10-843. The acceptance of a resignation will not be required to make it effective.
6.02. VACANCIES. If the office of any director, committee member or officer becomes vacant by reason of his or her death, resignation, disqualification, removal or otherwise, the Board of Directors may choose a successor to hold office for the unexpired term.
VII. INDEMNIFICATION AND RATIFICATION
7.01. INDEMNIFICATION. In order to induce qualified persons to serve the Company (and any other corporation, joint venture, partnership, trust or other enterprise at the request of the Company) as directors and officers, the Company shall indemnify any and all of its directors and officers, or former directors and officers to the fullest extent permitted by applicable law as it presently exists or may hereafter be amended.
7.02. RATIFICATION; SPECIAL COMMITTEE. Any transaction involving the Company, any of its subsidiary corporations or any of its directors, officers, employees or agents which at any time is questioned in any manner or context (including a shareholders derivative suit), on the ground of lack of authority, conflict of interest, misleading or omitted statement of fact or law, nondisclosure, miscomputation, improper principles or practices of accounting, inadequate records, defective or irregular execution or any similar ground, may be investigated and/or ratified (before or after judgment), or an election may be made not to institute or pursue a claim or legal proceedings on account thereof or to accept or approve a negotiated settlement with respect thereto (before or after the institution of legal proceedings), by the Board of Directors or by a special committee thereof comprised of one or more disinterested directors (that is, a director or directors who did not participate in the questioned transaction with actual knowledge of the questioned aspect or aspects thereof). Such a special committee may be validly formed and fully empowered to act, in accordance with the purposes and duties assigned thereto, by resolution or resolutions of the Board of Directors, notwithstanding (i) the inclusion of Board members who are not disinterested as aforesaid among those who form a quorum at the meeting or meetings at which one or more members of such special committee are elected or appointed to the Board or to such special committee or at which such committee is formed or empowered, or
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their inclusion among the directors who vote upon or otherwise participate in taking any of the foregoing actions, or (ii) the taking of any of such actions by the disinterested members of the Board (or a majority of such members) whose number is not sufficient to constitute a quorum or a majority of the membership of the full Board. Any such special committee so comprised will, to the full extent consistent with its purposes and duties as expressed in such resolution or resolutions, have all of the authority and powers of the full Board and its Executive Committee (the same as though it were the full Board and/or its Executive Committee in carrying out such purposes and duties) and will function in accordance with Section 3.09 above. No other provisions of these Bylaws which may at any time appear to conflict with any provisions of this Section 7.02, and no defect or irregularity in the formation, empowering or functioning of any such special committee, will serve to impede, impair or bring into question any action taken or purported to be taken by such committee or the validity of any such action. Any ratification of a transaction pursuant to this Section 7.02 will have the same force and effect as if the transaction has been duly authorized originally. Any such ratification, and any election made pursuant to this Section 7.02 with respect to claims, legal proceedings or settlements, will be binding upon the Company and its shareholders and will constitute a bar to any claim or the execution of any judgment in respect of the transaction involved in such ratification or election.
VIII. SEAL
8.01. FORM THEREOF. The seal of the Company will have inscribed thereon the name of the Company, the state and year of its incorporation and the words "SEAL".
IX. STOCK CERTIFICATES
9.01. FORM THEREOF. Each certificate representing stock of the Company will be in such form conforming to law as may from time to time be approved by the Board of Directors, and will bear the manual facsimile signatures and seal of the Company as required or permitted by law.
9.02. OWNERSHIP. The Company will be entitled to treat the registered owner of any share as the absolute owner thereof and accordingly, will not be bound to recognize any beneficial, equitable or other claim to, or interest in, such share on the part of any other person, whether or not it has notice thereof, except as may expressly be provided by Chapter 8 of Title 47, Arizona Revised Statutes (or its successor), as at the time in effect, or other applicable law.
9.03. TRANSFERS. Transfer of stock will be made on the books of the Company only upon surrender of the certificate therefor, duly endorsed by an appropriate person, with such assurance of the genuineness and effectiveness of the endorsement as the Company may require, all as contemplated by Chapter 8 of Title 47, Arizona Revised Statutes (or its successor), as at the time in effect, and/or upon submission of any affidavit, other document or notice which the Company considers necessary.
9.04. LOST CERTIFICATES. In the event of the loss, theft or destruction of any certificate representing capital stock of this Company, the Company may issue (or, in the case of any such stock as to which a transfer agent and/or registrar have been appointed, may direct such transfer agent and/or registrar to countersign, register and issue) a replacement certificate in lieu of that
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alleged to be lost, stolen or destroyed, and cause the same to be delivered to the owner of the stock represented thereby, provided that the owner shall have submitted such evidence showing the circumstances of the alleged loss, theft or destruction, and his or her ownership of the certificate as the Company considers satisfactory, together with any other factors which the Company considers pertinent, and further provided that an indemnity agreement and/or indemnity bond shall have been provided in form and amount satisfactory to the Company and to its transfer agent and/or registrar, if applicable.
X. EMERGENCY BYLAWS
10.01. EMERGENCY CONDITIONS. The emergency Bylaws provided in this Part X will be as effective in the event of an emergency as prescribed in Arizona Revised Statutes Section 10-207.D. To the extent not inconsistent with the provisions of this Part X, these Bylaws will remain in effect during such emergency and upon its termination these emergency Bylaws will cease to be operative.
10.02. BOARD MEETINGS. During any such emergency, a meeting of the Board of Directors or any of its committees may be called by any officer or director of the Company. Notice of the time and place of the meeting will be given by the person calling the same to those of the directors whom it may be feasible to reach by any available means of communication. Such notice will be given so much in advance of the meeting as circumstances permit in the judgment of the person calling the same. At any Board or committee meeting held during any such emergency, a quorum will consist of a majority of those who could reasonably be expected to attend the meeting if they were willing to do so, but in no event more than a majority of those to whom notice of such meeting is required to have been given as above provided.
10.03. CERTAIN ACTIONS. The Board of Directors, either before or during any such emergency, may provide and from time to time modify lines of succession in the event that during such an emergency any or all officers, appointees, employees or agents of the Company are for any reason rendered incapable of discharging their duties. The Board, either before or during any such emergency, may, effective in the emergency, change the head office or designate several alternative head offices of the Company, or authorize the officers to do so.
10.04. LIABILITY. No director, officer, appointee, employee or agent acting in accordance with these emergency Bylaws will be liable except for willful misconduct.
10.05. MODIFICATIONS. These emergency Bylaws will be subject to repeal or change by further action of the Board of Directors, but no such repeal or change will modify the provisions of Section 10.04 with respect to action taken prior to the time of such repeal or change. Any amendment of these emergency Bylaws may make any further or different provisions that may be practical and necessary for the circumstances of the emergency.
XI. DIVIDENDS
11.01. DECLARATION. Subject to such restrictions or requirements as may be imposed by law or the Company's Articles or as may otherwise be binding upon the Company, the Board of Directors may from time to time declare dividends on stock of the Company outstanding on the
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dates of record fixed by the Board, to be paid in cash, in property or in shares of the Company's stock on or as of such payment or distribution dates as the Board may prescribe.
XII. BUSINESS COMBINATIONS
12.01. DEFINITIONS. In these Bylaws, the following definitions shall apply:
1. "Affiliate" means a person that directly or indirectly controls, is controlled by, or is under common control with a specified person.
2. "Announcement date," when used in reference to any business combination, means the date of the first public announcement of the final, definitive proposal for the business combination.
3. "Associate," when used to indicate a relationship with any person, means any of the following:
(a) Any corporation or organization of which the person is an officer, director, or partnership or is, directly or indirectly, the beneficial owner of ten percent (10%) or more of any class or series of shares entitled to vote or other equity interest;
(b) Any trust or estate in which the person has a substantial beneficial interest or as to which the person serves as trustee or personal representative or in a similar fiduciary capacity; or
(c) Any relative or spouse of the person, or any relative of the spouse, residing in the home of the person.
4. "Beneficial owner," when used with respect to shares or other securities, includes any person who, directly or indirectly through any agreement, arrangement, relationship, understanding, or otherwise, whether or not in writing, has or shares the power to vote, or direct the voting of the shares or securities or has or shares the power to dispose of or direct the disposition of the shares or securities, except that:
(a) A person is not deemed the beneficial owner of shares or securities tendered pursuant to a tender or exchange offer made by the person or any of the person's affiliates or associates until the tendered shares or securities are accepted for purchase or exchange; and
(b) A person is not deemed the beneficial owner of shares or securities with respect to which the person has the power to vote or direct the voting arising solely from a revocable proxy given in response to a proxy solicitation required to be made and made in accordance with the applicable rules and regulations under the Securities Exchange Act of 1934, as amended, and is not then reportable under that act on a Schedule 13D or comparable report.
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5. "Beneficial ownership" includes the right to acquire shares or securities through the exercise of options, warrants, or rights, the conversion of convertible securities, or otherwise. The shares or securities subject to the options, warrants, rights, or conversion privileges held by a person are deemed to be outstanding for the purpose of computing the percentage of outstanding shares or securities of the class or series owned by the person but are not deemed to be outstanding for the purpose of computing the percentage of the class or series owned by any other person. A person is deemed the beneficial owner of shares and securities beneficially owned by the spouse of the person or any relative of the spouse residing in the home of the person, any trust or estate in which the person owns ten percent (10%) or more of the total beneficial interest or serves as trustee or personal representative, any corporation or entity in which the person owns ten percent (10%) or more of the equity and any affiliate of the person.
6. "Business combination," when used in reference to the Company and any interested shareholder of the Company, means any of the following:
(a) Any merger or consolidation of the Company or any subsidiary of the Company with either:
(i) The interested shareholder; or
(ii) Any other domestic or foreign corporation, whether or not itself an interested shareholder of the Company, that is, or after the merger would be, an affiliate or associate of the interested shareholder, except that the foregoing does not include the merger of a wholly-owned subsidiary of the Company into the Company or the merger of two or more wholly-owned subsidiaries of the Company.
(b) Any exchange, pursuant to a plan of exchange under the laws of the State of Arizona or a comparable statute of any other state or jurisdiction, of shares of the Company or any subsidiary of the Company for shares of either:
(i) The interested shareholder; or
(ii) Any other domestic or foreign corporation, whether or not itself an interested shareholder of the Company, that is, or after the exchange would be, an affiliate or associate of the interested shareholder.
(c) Any sale, lease, exchange, mortgage, pledge, transfer, or other disposition, in a single transaction or a series of transactions, to or with the interested shareholder or any affiliate or associate of the
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interested shareholder, of assets of the Company or any subsidiary of the Company to which any of the following applies:
(i) Has an aggregate market value equal to ten percent (10%) or more of the aggregate market value of all the assets, determined on a consolidated basis, of the Company.
(ii) Has an aggregate market value equal to ten percent (10%) or more of the aggregate market value of all the outstanding shares of the Company.
(iii) Represents ten percent (10%) or more of the earning power or net income, determined on a consolidated basis, of the Company.
(d) The issuance or transfer by the Company or any subsidiary of the Company, in a single transaction or a series of transactions, of any shares of the Company or any subsidiary of the Company that have an aggregate market value equal to five percent (5%) or more of the aggregate market value of all the outstanding shares of the Company to the interested shareholder or any affiliate or associate of the interested shareholder, except pursuant to the exercise of warrants or rights to purchase shares offered or a dividend or distribution paid or made pro rata to all shareholders of the Company.
(e) The adoption of any plan or proposal for the liquidation or dissolution of the Company, or any reincorporation of the Company in another state or jurisdiction, proposed by, on behalf of, or pursuant to any agreement, arrangement, or understanding, whether or not in writing, with the interested shareholder or any affiliate or associate of the interested shareholder.
(f) Any reclassification of securities, including any share dividend or split, reverse share split, or other distribution of shares in respect of shares, recapitalization of the Company, merger or consolidation of the Company with any subsidiary of the Company exchange of shares of the Company with any subsidiary of the Company or other transaction, whether or not with or into or otherwise involving the interested shareholder, proposed by, on behalf of, or pursuant to any agreement, arrangement, or understanding, whether or not in writing, with the interested shareholder or any affiliate or associate of the interested shareholder that has the effect, directly or indirectly, of increasing the proportionate share of the outstanding shares of any class or series of shares entitled to vote, or securities that are exchangeable for or convertible into or that carry a right to acquire shares entitled to vote, of the Company
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or any subsidiary of the Company that is, directly or indirectly, owned by the interested shareholder or any affiliate or associate of the interested shareholder, except as a result of immaterial changes due to fractional share adjustments.
(g) Any receipt by the interested shareholder or any affiliate or associate of the interested shareholder of the benefit, directly or indirectly, except proportionately as a shareholder of the Company, of any loans, advances, guarantees, pledges, or other financial assistance or any tax credits or other tax advantages provided by or through the Company or any subsidiary of the Company (other than expense account advances made in the ordinary course of business).
7. "Consummation date," with respect to any business combination, means the date of consummation of the business combination or, in the case of a business combination as to which a shareholder vote is taken, the later of:
(i) The business day before the vote; or
(ii) Twenty (20) days before the date of consummation of the business combination.
8. "Control," "controlling," "controlled by" or "under common control with" means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a person, whether through the ownership of voting securities, by contract, or otherwise. A person's beneficial ownership of ten percent (10%) or more of the voting power of the Company's outstanding shares entitled to vote in the election of directors creates a presumption that the person has control of the Company. A person is not considered to have control of the Company if the person holds voting power, in good faith and not for the purpose of avoiding any provision of law as an agent, bank, broker, nominee, custodian, or trustee for one or more beneficial owners who do not individually or as a group have control of the Company.
9. "Interested shareholder," when used in reference to the Company means any person, other than the Company or any subsidiary of the Company, that is either:
(a) The beneficial owner, directly or indirectly, of ten percent (10%) or more of the voting power of the outstanding shares entitled to vote of the Company; or
(b) An affiliate or associate of the Company.
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10. "Interested shares" means the shares of the Company with respect to which any of the following persons may exercise or direct the exercise of voting power in the election of directors of the Company:
(a) An interested shareholder;
(b) Any officer of the Company; or
(c) Any director of the Company.
11. "Market value," when used in reference to shares or property of the Company, means the following:
(a) In the case of shares, the highest closing sale price during the thirty (30) day period immediately preceding the date in question of a share on the composite tape for New York Stock Exchange listed shares or, if the shares are not quoted on the composite tape or not listed on the New York Stock Exchange, on the principal United States securities exchange registered under the Securities Exchange Act of 1934, as amended, on which the share are listed or, if the shares are not listed on any such exchange, on the National Association of Securities Dealers, Inc. Automated Quotations National Market System or, if the shares are not quoted on the National Association of Securities Dealers, Inc. Automated Quotations National Market System, the highest closing bid quotation during the thirty (30) day period preceding the date in question of a share on the National Association of Securities Dealers, Inc. Automated Quotations System or any system then in use or, if no such quotation is available, the fair market value on the date in question of a share as determined in good faith by the Board of the Company, subject to arbitration.
(b) In the case of property other than cash or shares, the fair market value of the property on the date in question as determined in good faith by the Board of the Company, subject to arbitration.
12. "Person" means any natural person, partnership, corporation, group, association, venture, firm, or other entity (other than the Company, any subsidiary of the Company, or a trustee or fiduciary holding stock for the benefit of the employees of the Company or its subsidiaries or any one of its subsidiaries, pursuant to one or more employee benefit plans). If two or more persons act as a partnership, limited partnership, syndicate, or other group pursuant to any agreement, arrangement, relationship, understanding, or otherwise, whether or not in writing, for the purposes of acquiring, owning, or voting shares of the Company, all members of the partnership, syndicate, or other group shall be deemed a person. Person does not include a licensed broker, dealer, or underwriter that purchases
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shares of the Company solely for purposes of resale to the public that is not acting in concert with an interested shareholder.
13. "Share acquisition date," with respect to any person and the Company, means the date that the person first becomes an interested shareholder of the Company.
12.02. BUSINESS COMBINATION WITH INTERESTED SHAREHOLDERS; APPROVED BY DIRECTORS.
1. Except as set forth in these Bylaws, the Company may not engage in any business combination or vote, consent or otherwise act to authorize a subsidiary of the Company to engage in any business combination with respect to, proposed by, or on behalf of, or pursuant to any agreement, arrangement or understanding, whether or not in writing, with any interested shareholder of the Company or any affiliate or associate of the interested shareholder for a period of three (3) years after the interested shareholder's share acquisition date, unless the business combination or the acquisition of shares made by the interested shareholder on the interested shareholder's share acquisition date is approved by a committee of the Board of Directors of the Company before the interested shareholder's share acquisition date. The committee shall be formed in accordance with subsection 4 of this Section 12.02.
2. If a good faith definitive proposal regarding a business combination is made in writing to the Board of Directors of the Company, a committee of the Board formed in accordance with subsection 4 of this
Section 12.02 shall consider and take action on the proposal and respond in writing within forty-five
(45) days after receipt of the proposal by the Company, setting forth its decision regarding the proposal.
3. If a good faith definitive proposal to acquire shares is made in writing to the Board of Directors of the Company, a committee of the Board of Directors formed in accordance with subsection 4 of this Section 12.02 shall consider and take action on the proposal. Unless the committee responds affirmatively in writing within forty-five (45) days after receipt of the proposal by the Company, the committee shall be considered to have disapproved the share acquisition.
4. When a business combination or acquisition of shares is proposed pursuant to this Section 12.02, the Board of Directors shall promptly form a committee composed of all of the Board's disinterested Directors. The committee shall take action on the proposal by the affirmative vote of a simple majority of the committee members. The committee is not subject to any direction or control by the Board with respect to the committee's consideration of or any action concerning a business combination or acquisition of shares pursuant to this Section 12.02. A committee formed pursuant to this subsection shall be composed of one or more members.
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Only disinterested Directors may be members of a committee formed pursuant to this subsection. However, if the Board of Directors has no disinterested Directors, the Board shall select three or more disinterested persons to be committee members. For purposes of this subsection, a Director or person is disinterested if the Director or person is not an interested shareholder or an affiliate thereof or a present or former officer or employee of the Company or an affiliate or associate of the Company.
12.03. Requirements after Three Years. Except for the provisions of Sections 12.02 and 12.04, the Company may not engage at any time in any business combination or vote, consent, or otherwise act to authorize a subsidiary of the Company to engage in any business combination with respect to, proposed by, on behalf of, or pursuant to any agreement, arrangement, or understanding, whether or not in writing, with an interested shareholder of the Company or any affiliate or associate of the interested shareholder other than a business combination meeting all the requirements of this Article XII, the Articles, and the requirements specified in any of the following:
1. A business combination with respect to which the consummation date is no less than three years after the share acquisition date, approved by the Board of Directors of the Company before the interested shareholder's share acquisition date, or as to which the acquisition of shares made by the interested shareholder on the interested shareholder's acquisition date had been approved by the Board of Directors before the interested shareholder's share acquisition date.
2. A business combination approved by the affirmative vote of the holders of a majority of the outstanding shares entitled to vote not beneficially owned by the interested shareholder proposing the business combination or any affiliate or associate of the interested shareholder proposing the business combination at a meeting called for that purpose no earlier than three years after the interested shareholder's share acquisition date.
3. A business combination, with respect to which the consummation date is no earlier than three years after the interested shareholder's share acquisition date, that meets all of the following conditions:
(a) The aggregate amount of the cash and the market value as of the consummation date of consideration other than cash to be received per share by holders of outstanding common shares of the Company in the business combination is at least equal to the higher of the following:
(i) The highest per share price paid by the interested shareholder, at a time when the interested shareholder was the beneficial owner, directly or indirectly, of five percent (5%) or more of the outstanding shares entitled to vote of the Company, for any common shares of the same class or
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series acquired by it within the three (3) year period immediately before the announcement date with respect to the business combination or within the three (3) year period immediately before, or in, the transaction in which the interested shareholder became an interested shareholder, whichever is higher, plus, in either case, interest compounded annually from the earliest date on which the highest per share acquisition price was paid through the consummation date at the rate for one year United States treasury obligations from time to time in effect less the aggregate amount of any cash dividends paid, and the market value of any dividends paid other than in cash, per common share since the earliest date, up to the amount of the interest.
(ii) The market value per common share on the announcement date with respect to the business combination or on the interested shareholder's share acquisition date, whichever is higher, plus interest compounded annually from that date through the consummation date at the rate for one year United States treasury obligations from time to time in effect less the aggregate amount of any cash dividends paid and the market value of any dividends paid other than in cash, per common share since that date, up to the amount of the interest.
(b) The aggregate amount of the cash and the market value as of the consummation date of consideration other than cash to be received per share by holders of outstanding shares of any class or series of shares, other than common shares, of the Company in the business combination is at least equal to the highest of the following, whether or not the interested shareholder has previously acquired any shares of the class or series:
(i) The highest per share price paid by the interested shareholder, at a time when the interested shareholder was the beneficial owner, directly or indirectly, of five percent (5%) or more of the outstanding shares entitled to vote of the Company, for any shares of the class or series acquired by it within the three (3) year period immediately before the announcement date with respect to the business combination or within the three (3) year period immediately before, or in, the transaction in which the interested shareholder became an interested shareholder, whichever is higher, plus, in either
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case, interest compounded annually from the earliest date on which the highest per share acquisition price was paid through the consummation date at the rate for one year United States treasury obligations from time to time in effect less the aggregate amount of any cash dividends paid and the market value of any dividends paid other than in cash, per share of the class or series since such earliest date, up to the amount of the interest.
(ii) The highest preferential amount per share to which the holders of shares of the class or series are entitled in the event of any voluntary liquidation, dissolution, or winding up of the Company, plus the aggregate amount of any unpaid dividends declared or due as to which the holders are entitled before payment of dividends on some other class or series of shares, unless the aggregate amount of the dividends is included in the preferential amount.
(iii) The market value per share of the class or series on the announcement date with respect to the business combination or on the interested shareholder's share acquisition date, whichever is higher, plus interest compounded annually from that date through the consummation date at the rate for one year United States treasury obligations from time to time in effect less the aggregate amount of any cash dividends paid and the market value of any dividends paid other than in cash, per share of the class or series since that date, up to the amount of the interest.
(c) The consideration to be received by holders of a particular class or series of outstanding shares, including common shares, of the Company in the business combination is in cash or in the same form as the interested shareholder has used to acquire the largest number of shares of the class or series of shares previously acquired by it and the consideration is distributed promptly.
(d) The holders of all outstanding shares of the Company not beneficially owned by the interested shareholder immediately before the consummation date with respect to the business combination are entitled to receive in the
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business combination cash or other consideration for the shares in compliance with subdivisions (a), (b) and (c).
(e) After the interested shareholder's share acquisition date and before the consummation date with respect to the business combination, the interested shareholder has not become the beneficial owner of any additional shares entitled to vote of the Company except:
(i) As part of the transaction that resulted in the interested shareholder becoming an interested shareholder;
(ii) By virtue of proportionate share splits, share dividends, or other distributions of shares in respect of shares not constituting a business combination;
(iii) Through a business combination meeting all of the conditions of
Section 12.02 and this paragraph; or
(iv) Through purchase by the interested shareholder at any price that, if the price had been paid in an otherwise permissible business combination the announcement date and consummation date of which were the date of the purchase, would have satisfied the requirements of subdivisions (a), (b) and (c) of this Section.
12.04. APPLICATION. This Article XII does not apply to any business combination of the Company with an interested shareholder of the Company who became an interested shareholder inadvertently, if the interested shareholder both:
1. As soon as practicable, divests itself of a sufficient amount of the shares entitled to vote of the Company so that it no longer is the beneficial owner, directly or indirectly, of ten percent (10%) or more of the outstanding shares entitled to vote of the Company.
2. Would not at any time within the three (3) year period preceding the announcement date with respect to the business combination have been an interested shareholder except for the inadvertent acquisition.
XIII. LIMITATION ON SHARE REPURCHASES
13.01. LIMITATION ON SHARE REPURCHASES. The Company shall not, directly or indirectly, purchase or agree to purchase any shares entitled to vote from a person, or two or more persons who act as a partnership, limited partnership, syndicate or other group pursuant to any agreement, arrangement, relationship, understanding or otherwise, whether or not in writing,
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for the purpose of acquiring, owning or voting shares of the Company who beneficially owns more than five per cent (5%) of the voting stock of the Company for more than the "average market price" of the shares if the shares have been beneficially owned by the person or persons for less than three (3) years, unless the purchase or agreement to purchase is approved at a meeting of shareholders by the affirmative vote of the holders of a majority of the voting stock entitled to vote and not beneficially owned by such person or persons from whom the proposed repurchase is to be made or the Company makes an offer, of at least equal value per share, to all holders of shares of such class or series and to all holders of any class or series into which the shares may be converted.
13.02. DEFINITIONS. For the purposes of this Article, "average market price" means the average closing sale price during the thirty trading days immediately preceding the purchase of the shares in question, or if the person or persons have commenced a tender offer or have announced an intention to seek control of the Company, during the thirty trading days preceding the earlier of the commencement of the tender offer or the making of the announcement, of a share on the composite tape for New York Stock Exchange listed shares or, if the shares are not quoted on the composite tape or not listed on the New York Stock Exchange, on the principal United States securities exchange registered under the Securities Exchange Act of 1934, as amended, on which the shares are listed or, if the shares are not listed on any such exchange, on the National Association of Securities Dealers, Inc. Automated Quotations National Market System or, if the shares are not quoted on the National Association of Securities Dealers, Inc. Automated Quotations National Market System, the average closing bid quotation, during the thirty trading days preceding the purchase of the shares in questions of a share on the National Association of Securities Dealers, Inc. Automated Quotations System or any system then in use, or if the person or persons have commenced a tender offer or have announced an intention to seek control of the issuing public corporation, during the thirty trading days preceding the earlier of the commencement of the tender offer or the making of the announcement, except that if no quotation is available the average market price is the fair market value on the date of purchase of the shares in question of a share as determined in good faith by the Board of Directors of the Company.
XIV. AMENDMENTS
14.01. AMENDMENT OF ARTICLES AND BYLAWS. Notwithstanding any other provision of these Bylaws, Article Fifth of the Articles (Restated As of July 29, 1988) and Sections 2.02, 3.01, and 3.13 and Articles XII, XIII, and XIV of these Bylaws shall not be altered, amended, supplemented, repealed, or temporarily or permanently suspended, in whole or in part, or replacement Bylaw provisions adopted without: (I) the affirmative vote of a majority of the directors then in office; or (ii) the affirmative vote of seventy-five percent (75%) or more of the outstanding shares of the Company entitled to vote generally.
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CERTIFICATE
I, NANCY C. LOFTIN, Vice President, General Counsel and Secretary of Pinnacle West Capital Corporation, an Arizona corporation, do HEREBY CERTIFY that the foregoing is a true and correct copy of the Company's Bylaws, as amended, and that they are in full force and effect as of the date hereof.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed the seal of the corporation this 21st day of January, 2004.
Nancy C. Loftin
 NANCY C. LOFTIN
Vice President, General Counsel and Secretary

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Exhibit 10.1a
Under the 2004 Officers Variable Incentive Plan, the Chief Executive Officer, with the approval of the Human Resources Committee of the Pinnacle West Board of Directors, annually designates the officers who will participate in the program, establishes their participation level, and establishes certain financial and operational goals. The impact, if any, of each officer's performance on his or her variable pay award is determined by the Chief Executive Officer, with the approval by the Human Resources Committee. However, the calculation and the amount of payment, if any, under this Plan are in the sole discretion of the Human Resources Committee of the Board of Directors. Accordingly, achievement of financial and operational goals is just one method that may be utilized to measure performance.
 
Exhibit 10.2a
Under the 2004 CEO Variable Incentive Plan, the Human Resources Committee of the Pinnacle West Board of Directors, annually establishes the participation level and establishes certain financial and operational goals. However, the calculation and the amount of payment, if any, under this Plan are in the sole discretion of the Human Resources Committee. Accordingly, achievement of financial and operational goals is just one method that may be utilized to measure performance.
 
EXHIBIT 10.3
AMENDMENT NO. 4
Decommissioning Trust Agreement
 (PVNGS Unit 1)
This Amendment No. 4 dated as of December 19, 2003, to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of July 1, 1991, as amended by Amendment No. 1 thereto dated as of December 1, 1994, Amendment No. 2 thereto dated as of December 16, 1996, and Amendment No. 3 thereto dated as of March 18, 2002 (the "Decommissioning Trust Agreement", terms used herein as therein defined), is entered into between Arizona Public Service Company ("APS") 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. Amendment.
(a) A new Section 29 will be added at the end of the Decommissioning Trust Agreement and will read in full as follows:
Section 29. Notice Regarding Disbursements or Payments. Notwithstanding anything to the contrary in this Agreement, except for (i) payments of ordinary administrative costs (including taxes) and other incidental expenses of the Funds (including legal, accounting, actuarial, and trustee expenses) in connection with the operation of the Funds, (ii) withdrawals being made under 10 CFR 50.82(a)(8), and
(iii) transfers between the Funds in accordance with the provisions of this Agreement, no disbursement or payment may be made from the Funds until written notice of the intention to make a disbursement or payment has been given to the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the intended disbursement or payment. The disbursement or payment from the Funds, if it is otherwise in compliance with the terms and conditions of this Agreement, may be made following the 30-working day notice period if no written notice of objection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, is received by the Decommissioning Trustee or APS within the notice period. The required notice may be made by the Decommissioning Trustee or on the Decommissioning Trustee's behalf. No such notice is required for withdrawals being made pursuant to 10 CFR 50.82(a)(8)(ii), including withdrawals made during the operating life of Unit 1 to be used
for decommissioning planning. In addition, no such notice is required to be made to the NRC after decommissioning has begun and withdrawals are being made under 10 CFR 50.82(a)(8). This Section 29 is intended to qualify each and every provision of this Agreement allowing distributions from the Funds, including but not limited to Section 10 hereof, and in the event of any conflict between any such provision and this Section 29, the provisions of this
Section 29 shall control.
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. 4 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. 4 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.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 4 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
By: Barbara M. Gomez

Title: Treasurer
MELLON BANK, N.A. as Decommissioning Trustee
By: Carlos Pacheco
Title: Vice President

2

STATE OF ARIZONA                    )
                                    ) ss:
County of Maricopa                  )	

The foregoing instrument was acknowledged before me this 12th day of December, 2003, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.

                                         Debra L. Blondin
                                         ---------------------------------
                                         Notary Public

My commission expires:

June 7, 2004

COMMONWEALTH OF PENNSYLVANIA                  )
                                              ) ss:
County of Allegheny                           )	

The foregoing instrument was acknowledged before me this 19th day of December, 2003, by Carlos Pacheco, 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.
Julie Ann Mosco
 Notary Public
My commission expires:
October 13, 2007
3
 
EXHIBIT 10.4
AMENDMENT NO. 7
Decommissioning Trust Agreement
 (PVNGS Unit 2)
This Amendment No. 7 dated as of December 19, 2003, 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 and Amendment No. 6 thereto dated as of March 18, 2002 (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. Amendment.
(a) A new Section 34 will be added at the end of the Decommissioning Trust Agreement and will read in full as follows:
Section 34. Notice Regarding Disbursements or Payments. Notwithstanding anything to the contrary in this Agreement, except for (i) payments of ordinary administrative costs (including taxes) and other incidental expenses of the Funds (including legal, accounting, actuarial, and trustee expenses) in connection with the operation of the Funds, (ii) withdrawals being made under 10 CFR 50.82(a)(8), and
(iii) transfers between the Funds in accordance with the provisions of this Agreement, no disbursement or payment may be made from the Funds until written notice of the intention to make a disbursement or payment has been given to the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the intended disbursement or payment. The disbursement or payment from the Funds, if it is otherwise in compliance with the terms and conditions of this Agreement, may be made following the 30-working day notice period if no written notice of objection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, is received by the Decommissioning Trustee or APS within the notice period. The required notice may be made by the Decommissioning
Trustee or on the Decommissioning Trustee's behalf. No such notice is required for withdrawals being made pursuant to 10 CFR 50.82(a)(8)(ii), including withdrawals made during the operating life of Unit 2 to be used for decommissioning planning. In addition, no such notice is required to be made to the NRC after decommissioning has begun and withdrawals are being made under 10 CFR 50.82(a)(8). This Section 34 is intended to qualify each and every provision of this Agreement allowing distributions from the Funds, including but not limited to Section 11 and Section 12 hereof, and in the event of any conflict between any such provision and this Section 34, the provisions of this Section 34 shall control.
(b) Paragraph (l) of Exhibit B to the Decommissioning Trust Agreement is hereby deleted and is replaced in its entirety by the following:
(l) (x) corporate equity securities, including, but not limited to, investment of units of common or collective trust funds investing in corporate equity securities; including, but not limited to, the Decommissioning Trustee's Nuclear Decommissioning Trust Equity Index Fund (the "NDT Equity Index Fund") and (y) obligations not included in clauses (a) through (k) issued or guaranteed by a person controlled or supervised by and acting as an instrumentality of the United States of America pursuant to authority granted by the Congress of the United States of America, including Federal Intermediate Credit Bank, Banks for Cooperatives, Federal Land Banks, Federal Home Loan Banks, Federal Home Loan Mortgage Corporation; provided, that no more than fifty percent (50%) of the aggregate assets of the Funds may be invested in securities described in (x) and (y) of this subparagraph (l) during the period from June 27, 1996 through December 31, 2003, no more than forty percent (40%) during the period from January 1, 2004 through December 31, 2006, and no more than twenty percent (20%) during the period from January 1, 2007 through January 31, 2010; and provided further that after January 31, 2010, no investments shall be made in such securities.
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.
2
(b) Counterparts/Representations.
The Amendment No. 7 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. 7 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.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 7 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
By: Barbara M. Gomez

Title: Treasurer
MELLON BANK, N.A. as Decommissioning Trustee

By:    /s/ Carlos Pacheco
       ---------------------------------
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: Peter M. Murphy

Title: Trust Officer

3
U.S. BANK NATIONAL ASSOCIATION, as Owner
 Trustee under a Trust Agreement with
Emerson Finance LLC and as Lessor under
a Facility Lease with Arizona Public
Service Company
By: Peter M. Murphy

Title: Trust Officer

4

STATE OF ARIZONA                    )
                                    ) ss:
County of Maricopa                  )	

The foregoing instrument was acknowledged before me this 12th day of December, 2003, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.

                                        Debra L. Blondin
                                        ----------------------------------------

                                        Notary Public

My commission expires:

June 7, 2004
-----------------------

COMMONWEALTH OF PENNSYLVANIA              )
                                          ) ss:
County of Allegheny                       )	

The foregoing instrument was acknowledged before me this 19th day of December, 2003, by Carlos Pacheco, 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.
Julie Ann Mosco
Notary Public
My commission expires:
October 13, 2007

5

[COMMONWEALTH OF MASSACHUSETTS]         )
                                        ) ss:
County of                               )	

The foregoing instrument was acknowledged before me this 17th day of December, 2003, by Peter M. Murphy, a Trust Officer 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.

                                        Maria I. Arguello
                                        ----------------------------------------

                                        Notary Public

My commission expires:

September 9, 2005
----------------------

[COMMONWEALTH OF MASSACHUSETTS]                             )
                                                            ) ss:
County of                                                   )	

The foregoing instrument was acknowledged before me this 17th day of December, 2003, by Peter M. Murphy, a Trust Officer of U.S. Bank National Association, in its capacity as Owner Trustee under a Trust Agreement with Emerson Finance LLC and as Lessor under a Facility Lease with Arizona Public Service Company, on behalf of said association in such capacities.
Maria I. Arguello
Notary Public
My commission expires:
September 9, 2005

6
 
EXHIBIT 10.5
AMENDMENT NO. 4
Decommissioning Trust Agreement
 (PVNGS Unit 3)
This Amendment No. 4 dated as of December 19, 2003, to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of July 1, 1991, as amended by Amendment No. 1 thereto dated as of December 1, 1994, Amendment No. 2 thereto dated as of December 16, 1996, and Amendment No. 3 thereto dated as of March 18, 2002 (the "Decommissioning Trust Agreement", terms used herein as therein defined), is entered into between Arizona Public Service Company ("APS") 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. Amendment.
(a) A new Section 29 will be added at the end of the Decommissioning Trust Agreement and will read in full as follows:
Section 29. Notice Regarding Disbursements or Payments. Notwithstanding anything to the contrary in this Agreement, except for (i) payments of ordinary administrative costs (including taxes) and other incidental expenses of the Funds (including legal, accounting, actuarial, and trustee expenses) in connection with the operation of the Funds, (ii) withdrawals being made under 10 CFR 50.82(a)(8), and
(iii) transfers between the Funds in accordance with the provisions of this Agreement, no disbursement or payment may be made from the Funds until written notice of the intention to make a disbursement or payment has been given to the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, at least 30 working days before the date of the intended disbursement or payment. The disbursement or payment from the Funds, if it is otherwise in compliance with the terms and conditions of this Agreement, may be made following the 30-working day notice period if no written notice of objection from the Director, Office of Nuclear Reactor Regulation, or the Director, Office of Nuclear Material Safety and Safeguards, as applicable, is received by the Decommissioning Trustee or APS within the notice period. The required notice may be made by the Decommissioning Trustee or on the Decommissioning Trustee's behalf. No such notice is required for withdrawals being made pursuant to 10 CFR 50.82(a)(8)(ii), including withdrawals made during the operating life of Unit 3 to be used
for decommissioning planning. In addition, no such notice is required to be made to the NRC after decommissioning has begun and withdrawals are being made under 10 CFR 50.82(a)(8). This Section 29 is intended to qualify each and every provision of this Agreement allowing distributions from the Funds, including but not limited to Section 10 hereof, and in the event of any conflict between any such provision and this Section 29, the provisions of this
Section 29 shall control.
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. 4 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. 4 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.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 4 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
ARIZONA PUBLIC SERVICE COMPANY
By: Barbara M. Gomez

Title: Treasurer
 MELLON BANK, N.A. as Decommissioning Trustee

By: Carlos Pacheco
Title: Vice President

2

STATE OF ARIZONA                    )
                                    ) ss:
County of Maricopa                  )	

The foregoing instrument was acknowledged before me this 12th day of December, 2003, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.

                                        Debra L. Blondin
                                        ----------------------------------------

                                        Notary Public

My commission expires:

June 7, 2004
--------------------------

COMMONWEALTH OF PENNSYLVANIA                              )
                                                          ) ss:
County of Allegheny                                       )	

The foregoing instrument was acknowledged before me this 19th day of December, 2003, by Carlos Pacheco, 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.
Julie Ann Mosco
Notary Public
My commission expires:
October 13, 2007

3
 
Exhibit 10.6a
FOURTH AMENDMENT TO
THE PINNACLE WEST CAPITAL CORPORATION
ARIZONA PUBLIC SERVICE COMPANY
SUNCOR DEVELOPMENT
AND EL DORADO INVESTMENT COMPANY
DEFERRED COMPENSATION PLAN
Effective January 1, 1992, Pinnacle West Capital Corporation (the "Company"), Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company adopted the Pinnacle West Capital Corporation, Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan (the "Plan"). The Plan was thereafter amended several times. The Plan was amended and restated in its entirety on December 1, 1995 and amended several times thereafter. The Plan was most recently amended on October 22, 2002 to increase the threshold for automatic cashout for terminated or retired Participants under certain circumstances and revise crediting of interest for certain Participants.
By this instrument, the Plan is being amended to revise its claim procedures.
1. This Amendment shall amend only those Sections set forth herein and those Sections not amended hereby shall remain in full force and effect.
2. Section 1.1.7 is hereby amended in its entirety to read as follows:
1.17 "Disability" shall mean (i) in the case of a Participant who is an employee of an Employer, a period of disability during which a participant qualifies for benefits under the Participant's Employer's long-term disability plan, or (ii) in the case of a Participant who is a Director, a period of disability during which the Participant would have qualified for benefits under such a plan, as determined in the sole discretion of the Committee, had the Participant been an employee of the Employer.
3. Section 8.1(b) is hereby amended in its entirety to read as follows:
(b) Waiver of Deferral; Credit for Plan Year of Disability. A Participant who is determined to be suffering from a Disability shall be excused from fulfilling that portion of the Annual Deferral commitment that would otherwise have been withheld fro a Participant's Bas Annual Salary, Year-End Bonus and/or Directors Fees for the Plan Year during which the Participant first suffers a Disability. In addition, the Participant's Account Balance shall be credited with that portion of the Annual Deferral commitment that is excused in accordance with the preceding sentence, unless the Disability ceases in the Plan Year that it commences, in which case, the crediting shall apply only for the period of Disability.
4. Section 8.2 is hereby amended in its entirety to read as follows:

8.2               Disability Benefit. A Participant suffering a
                  Disability shall, for the benefit purposes under this
                  Plan, continue to be considered to be employed and
                  shall be eligible for the benefits provided for in
                  Articles 4, 5, 6 or 7 in accordance with the
                  provisions of those Articles. Notwithstanding the
                  above, the Committee shall have the right, in its
                  sole and absolute discretion and for purposes of this
                  Plan only, to terminate a Participant's employment or
                  service as a Director at any time after such
                  participant is determined to be suffering from a
                  disability. In determining the Participant's Account
                  Balance for purposes of the Disability Benefit
                  described in the previous sentence, the Preferred
                  Rate shall be used in lieu of the rates in Section
                  7.1

5.                ARTICLE 14 is hereby amended in its entirety to read	

as follows:
ARTICLE 14
Claims Procedures
14.1 Claims. Any Participant, Beneficiary or any authorized representative acting on behalf of the Participant or Beneficiary ("Claimant") claiming benefits, eligibility, participation or any other right or interest under this Plan may file a written claim setting forth the basis of the claim with the Employee Benefits Department. A written notice of the Employee Benefits Department's disposition of any such claim shall be furnished to the Claimant within a reasonable time (not to exceed ninety (90) days) after the claim is received by the Employee Benefits Department. Notwithstanding the foregoing, the Employee Benefits Department may have additional time (not to exceed ninety (90) days) to decide the claim if special circumstances exist, provided that it advises the Claimant, in writing and prior to the end of the initial ninety (90) day period, of the special circumstances giving rise to the
need for additional time and the date on which it expects to decide the claim. If the claim is denied, in whole or in part, the notice of disposition shall include the specific reason for the denial, identify the specific provisions of the Plan upon which the denial is based, describe any additional material or information necessary to perfect the claim, explain why that material or information is necessary and describe the Plan's review procedures, including the timeframes thereunder for a Claimant to file a request for review and for the Committee to decide the claim. The notice shall also include a statement advising the claimant of his or her right to bring a civil action under Section 502(a) of the Employee Retirement Income Security Act of 1974, as amended, if his or her claim is denied, in whole or in part, upon review.
Within sixty (60) days after receiving the written notice of the Employee Benefits Department's disposition of the claim, the Claimant may request, in writing, review by the Committee of the Employee Benefits Department's decision regarding his or her claim. Upon written request, the Claimant shall be entitled to a review meeting with the Committee to present reasons why the claim should be allowed. The Claimant may submit a written statement in support of his or her claim, together with such comments, information and material relating to the claim, as he or she deems necessary or appropriate. The Claimant shall be provided, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information which are relevant to the Claimant's claim and its review. If the Claimant does not request review within sixty (60) days after receiving written notice of the Employee Benefits Department's disposition of the claim, the Claimant shall be deemed to have accepted the Employee Benefits Department's written disposition.
The Committee shall make its decision on review and provide written notice thereof to the Claimant within a reasonable time (not to exceed sixty (60) days) after the claim is received by the Committee. Notwithstanding the foregoing, the Committee may have additional time (not to exceed sixty (60) days) to decide the claim if special circumstances exist provided that it advises the Claimant, in writing, prior to the end of the initial sixty (60) day period, of the special circumstances giving rise to the need for additional time and the date on which it expects to decide the claim. In no event shall the Committee have more than one hundred twenty (120) days following its receipt of the Claimant's request for review to provide the Claimant with written notice of its decision.
The Committee shall have the right to request of and receive from Claimant such additional information, documents or other evidence as the Committee may reasonably require. In the event that the Committee requests such additional information from the Claimant, the period for making the benefit determination on review shall not take into account the period beginning on the date on which the Committee notifies the Claimant in writing of the need for additional information and ending on the date on which the Claimant responds to the request for additional information.
If the claim is denied upon review, in whole or in part, the notice of disposition shall include the specific reason for the denial, identify the specific provision of the Plan upon which the denial is based, include a statement advising the Claimant of his or her right to receive, upon written request and free of charge, reasonable access to and copies of all documents, records and other information which are relevant to the Claimant's claim. The notice shall also include a statement advising the claimant of his or her right to bring a civil action under Section 502(a) of the Employee Retirement Income Security Act of 1974, as amended, if his or her claim is denied, in whole or in part, upon review.
For purposes of this Section 14.1, a document, record or information will be considered "relevant" if it (a) was relied upon by the Employee Benefits Department or Committee, as applicable, in making the benefit decision, (b) was submitted, considered or generated in the course of making such decisions, even if it was not relied upon in making those decisions, or (c) demonstrates compliance with the administrative processes and safeguards established by the Plan to insure that the terms of the Plan have been followed and applied consistently.
To the extent permitted by law, a decision on review by the Committee shall be binding and conclusive upon all persons whomsoever. Completion of the claims procedure described in this Section 14.1 shall be a mandatory precondition that must be complied with prior to commencement of a legal or equitable action in connection with the Plan by a person claiming rights under the Plan, or by another person claiming rights through such a person. The Committee may, in its sole discretion, waive these procedures as a mandatory precondition to such an action.
6. Except as otherwise expressly provided herein, this Amendment shall be effective January 1, 2003.
Except as amended hereby, the Company ratifies and confirms the Plan as amended and restated effective January 1, 1995 and as thereafter amended.
Dated: December 18, 2003
PINNACLE WEST CAPITAL CORPORATION

By /s/ Jack E. Davis
   -----------------------------------------

Its   President & Chief Operating Officer of
      Pinnacle West Capital Corporation and
      President & Chief Executive Officer of
      Arizona Public Service Company	

Exhibit 10.7a
PINNACLE WEST CAPITAL CORPORATION
SUPPLEMENTAL EXCESS BENEFIT
RETIREMENT PLAN
.
.
.
TABLE OF CONTENTS

                                                                     PAGE
                                                                     ----
ARTICLE ONE - PREAMBLE............................................      1

ARTICLE TWO - CONSTRUCTION........................................      2

ARTICLE THREE - ELIGIBILITY AND PARTICIPATION.....................      2

ARTICLE FOUR - BENEFITS...........................................      4

ARTICLE FIVE - PAYMENT OF BENEFITS................................      9

ARTICLE SIX - COORDINATION OF BENEFITS............................     12

ARTICLE SEVEN - FUNDING...........................................     13

ARTICLE EIGHT - ADMINISTRATION....................................     13

ARTICLE NINE - AMENDMENT AND TERMINATION OF THE PLAN..............     13

ARTICLE TEN - ASSIGNMENT..........................................     14

ARTICLE ELEVEN - WITHHOLDING......................................     14

ARTICLE TWELVE - OTHER BENEFIT PLANS OF THE COMPANY...............     15

ARTICLE THIRTEEN - MISCELLANEOUS..................................     15

ARTICLE FOURTEEN - EFFECTIVE DATE.................................     16	

i
PINNACLE WEST CAPITAL CORPORATION
SUPPLEMENTAL EXCESS BENEFIT RETIREMENT PLAN
ARTICLE ONE
PREAMBLE
Effective January 1, 1987, PINNACLE WEST CAPITAL CORPORATION (the
"Company") adopted the PINNACLE WEST CAPITAL CORPORATION SUPPLEMENTAL EXCESS BENEFIT RETIREMENT PLAN (the "Plan") for the purpose of paying retirement benefits to certain employees in excess of the benefits permitted to be paid under the Pinnacle West Capital Corporation Retirement Plan (the "Retirement Plan") by reason of Section 415 of the Internal Revenue Code (the "Code"). The Plan was thereafter amended several times to provide additional benefits, thereby changing the Plan from an "excess benefit plan" under the Employee Retirement Income Security Act of 1974, as amended (the "Act"), to a "top hat" plan under the Act.
Effective January 1, 1982, ARIZONA PUBLIC SERVICE COMPANY ("APS") adopted the ARIZONA PUBLIC SERVICE COMPANY SUPPLEMENTAL EXCESS BENEFIT RETIREMENT PLAN (the "APS Plan") for the purpose of paying retirement benefits to certain employees in excess of the benefits permitted to be paid under the Arizona Public Service Company Employees' Retirement Plan (the "APS Retirement Plan") by reason of Section 415 of the Code. The Plan was thereafter amended several times to provide additional benefits, thereby changing the Plan from an "excess benefit plan" under the Act to a "top hat" plan under the Act.
Effective January 1, 2000, the Company and APS amended and restated the Plan and the APS Plan to merge the APS Plan into this Plan and to make other technical changes. The Plan was amended several times thereafter. By this amendment and restatement, the Company intends to amend the Plan to add a new benefit structure.
1
ARTICLE TWO
CONSTRUCTION
Terms capitalized in this Plan shall have the meaning given in Article Two of the Retirement Plan, governing definitions and construction, except where such terms are otherwise defined in this Plan. If any provision of this Plan is determined to be invalid or unenforceable for any reason, the remaining provisions shall continue in full force and effect. All of the provisions of this Plan shall be construed and enforced according to the laws of the State of Arizona, and shall be administered according to the laws of such state, except as otherwise required by the Act, the Code or other applicable federal law. It is the intention of the Company that the Plan, as adopted by the Company, shall constitute an "unfunded plan of deferred compensation for a select group of management and highly compensated employees" within the meaning of Sections 201(2) and 301(3) of the Act. Benefits under this Plan shall be paid from the Company's general assets, and not from any trust fund or other segregated fund. This Plan shall be construed in a manner consistent with the Company's intention.
ARTICLE THREE
ELIGIBILITY AND PARTICIPATION
Employees of the Company or its Affiliates who are members of a select group of management or highly compensated employees, as determined by the Human Resources Committee of the Board of Directors of the Company, in its discretion, shall be eligible to participate in the Plan if they satisfy the eligibility requirements of Section 3(a) or Section 3(b).
(a) Eligible Employees who are officers of the Company or an Affiliate which is a participating employer under the Retirement Plan shall be entitled to the benefits described in Section 4(a).
2
(b) Eligible Employees of the Company or an Affiliate which is a participating employer under the Retirement Plan who are not officers, who are designated for participation by the Human Resources Committee of the Company's Board of Directors and who are participants in the Retirement Plan shall be entitled to the benefits described in Section 4(b). The Human Resources Committee may make its designations under this Section 3(b) by individual designation or by group designation.
A participant shall commence participation in this Plan as of the first day of the Plan Year in which he or she becomes a participant pursuant to this ARTICLE THREE or the first day of his or her employment with the Company or an Affiliate which is a participating employer under the Retirement Plan, whichever is later. Such participation shall continue until the earlier of the date on which the participant no longer satisfies the requirements for participation under Section 3(a) or Section 3(b) or the date on which the Human Resources Committee informs the participant in writing that he or she is no longer eligible to participate in this Plan.
Notwithstanding the foregoing, if the status of a participant changes for reasons other than termination of employment with the Company or an Affiliate which is a participating employer under the Retirement Plan, so that he or she no longer is eligible to participate in the Plan, his or her participation in the Plan shall cease but his or her benefit under this Plan as of the date of his or her change of status shall not be canceled or distributed, but shall be determined upon his or her termination of employment with the Company or an Affiliate.
3
ARTICLE FOUR
BENEFITS
(a) Section 3(a) Participants.
(1) Subject to ARTICLE SEVEN, a participant who is eligible under Section 3(a) and who is a Group A Participant under the Retirement Plan shall be entitled to a monthly benefit equal to the lesser of
(i) or (ii), reduced by (iii), where
(i) Equals three percent (3%) of the participant's Average Monthly Compensation multiplied by the participant's Years of Service, not to exceed ten (10) Years of Service, plus two percent (2%) of the participant's Average Monthly Compensation multiplied by the participant's Years of Service in excess of ten (10) Years of Service,
(ii) Equals sixty percent (60%) of the participant's Average Monthly Compensation, and
(iii) Equals the amount of such participant's monthly benefit determined under the terms of the Retirement Plan and payable in accordance with Section 6.2 of the Retirement Plan.
(2) Subject to ARTICLE SEVEN, a participant who is eligible under Section 3(a) and who is a Group B Participant under the Retirement Plan shall be entitled to a monthly benefit equal to the sum of (i) and (ii), where
(i) Equals the benefit determined under the formula set forth above in this Section 4(a)(1) for a Group A Participant in the Retirement Plan based on the participant's Years of Service as of March 31, 2003 and his or her Average Monthly Compensation as of the date of determination. Years of Service as of March 31, 2003 shall equal his or her full Years of Service as of such date plus a partial Year of Service equal to the lesser of one (1) or a fraction, the numerator of which is the participant's Hours of
4
Service earned during the period beginning on the day after the last day of his or her Computation Period ending prior to March 31, 2003 and ending on March 31, 2003, and the denominator of which is 1,000, and
(ii) Equals the monthly benefit for life payable at Normal Retirement Age which is the Actuarial Equivalent of a lump sum benefit equal to the participant's Supplemental Retirement Account Balance minus the participant's Retirement Account Balance under the Retirement Plan.
(3) Subject to ARTICLE SEVEN, a participant who is eligible under Section 3(a) and who is a Group C Participant under the Retirement Plan shall be entitled to a monthly benefit equal to the Actuarial Equivalent of a lump sum benefit equal to (i) reduced by (ii), where
(i) Equals the participant's Supplemental Retirement Account Balance, and
(ii) Equals the participant's Retirement Account Balance under the Retirement Plan.
A participant's Supplemental Retirement Account Balance shall be a notional account credited with Monthly Retirement Account Balance Credits and Interest Credits. For purposes of this Plan, Monthly Retirement Account Balance Credits shall be determined under the general methodology set forth in the Retirement Plan based on the participant's Monthly Compensation for the month but using the following chart; provided that, except for a Group C Participant, a participant shall not receive a Monthly Retirement Account Balance Credit after he or she is credited with more than twenty-five (25) Years of Service, with twenty-five years (25) Years of Service defined as twenty-five
(25) full twelve (12) month periods in duration:
5

                          Percent of Monthly Compensation
                                    Contribution
Age at End of Plan Year                 Rate
-----------------------   -------------------------------
Less than 35                           12%
35-39                                  14%
40-44                                  16%
45-49                                  20%
50-54                                  24%
55 and over                            28%	

For purposes of this Section 4(a), Compensation and Monthly Compensation shall be determined without regard to the limitation set forth in
Section 401(a)(17) of the Code and shall be increased by any cash payments made to the participant pursuant to bonus or incentive plans maintained by the Company or an Affiliate which is a participating employer under the Retirement Plan for employees generally and by any amounts deferred by the participant under any of the Company's or such an Affiliate's deferred compensation plans for employees, provided that bonus or incentive payments made in a form other than cash, bonus or incentive payments which are not "year-end" bonus or incentive payments, bonus or incentive payments under individual agreements between the Company or such an Affiliate and a participant, and cash payments made under bonus or incentive plans maintained by the Company or such an Affiliate for employees generally which exceed the maximum amount that the Company's President or Chief Operating Officer determines, in his or her discretion, may be taken into account under this Plan shall not be taken into account as Compensation and Monthly Compensation for purposes of this Plan unless the Company's President or Chief Operating Officer determines, in his or her discretion, that such bonus or incentive payment shall be taken into account as Compensation and Monthly Compensation under this Plan. Eligible bonuses and incentive payments shall be taken into account as Compensation and Monthly Compensation in the year in which such amounts are paid rather than in the year in which they are earned, provided that the Company's President or Chief Operating Officer shall have the
6
authority to determine, in his or her discretion, that such bonus or incentive payment shall be taken into account in the year in which such amounts are earned rather than in the year in which they are paid. The Company's President or Chief Operating Officer shall have the sole and absolute discretion to determine whether a bonus or incentive payment made to a participant constitutes Compensation or Monthly Compensation for purposes of this Section 4(a) and may differentiate among individuals in establishing the bonus or incentive payments that may be taken into account under the Plan.
Notwithstanding anything herein to the contrary, the monthly benefit under this Section 4(a) of a participant who was eligible under Section 3(a) on December 31, 1999 shall not be less than such monthly benefit on such date, and the monthly benefit under this Section 4(a) of a participant who was eligible under Section 3(a) of the APS Plan on December 31, 1999 shall not be less than the monthly benefit of such participant under Section 4(a) of the APS Plan on such date, except to the extent attributable solely to an increase in any such participant's monthly benefit under the Retirement Plan due to an increase in the limitations under Sections 401(a)(17) and 415 of the Code.
(b) Section 3(b) Participants.
Subject to ARTICLE SIX and ARTICLE SEVEN, any participant who is designated for participation pursuant to Section 3(b) and who receives a benefit under the Retirement Plan, or such participant's surviving spouse or beneficiary in the event of the participant's death, shall be entitled to a monthly benefit payable in accordance with this ARTICLE FOUR and with ARTICLE FIVE equal to (i) reduced by (ii), where
(i) Equals the amount of such participant's or surviving spouse's or beneficiary's monthly benefit under the Retirement Plan computed under the provisions of the Retirement Plan but without regard to the cap on Compensation in Section 2.1(n) and
7
the limitations in Section 5.13 of the Retirement Plan and the provisions of Sections 401(a)(17) and 415 of the Code; and
(ii) Equals the amount of such participant's or surviving spouse's or beneficiary's monthly benefit actually payable under the terms of the Retirement Plan.
For purposes of this Section 4(b), Compensation shall include any amount of the participant's regular salary that the participant elects to defer under any deferred compensation plans for employees of the Company or an Affiliate which is a participating employer under the Retirement Plan and shall exclude all bonus or incentive payments paid to the participant. The Human Resources Committee shall have the sole and absolute discretion to determine a participant's Compensation for purposes of this Section 4(b).
Benefits payable under this Section 4(b) shall be payable to a Plan participant or his or her spouse or other beneficiary in the same manner and subject to all the same options, conditions, privileges and restrictions as are applicable to the benefits payable to the Plan participant, spouse or other beneficiary of a Participant under the Retirement Plan, as though such benefits were payable as a part of the benefits being paid under the Retirement Plan.
Notwithstanding anything herein to the contrary, the monthly benefit under this Section 4(b) of a participant who was eligible under Section 3(b) on December 31, 1999 shall not be less than such monthly benefit on such date, and the monthly benefit under this Section 4(b) of a participant who was eligible under Section 3(b) of the APS Plan on December 31, 1999 shall not be less than the monthly benefit of such participant under Section 4(b) of the APS Plan on such date, except to the extent attributable solely to an increase in any such participant's monthly benefit under the Retirement Plan due to an increase in the limitations under Sections 401(a)(17) and 415 of the Code.
8
ARTICLE FIVE
PAYMENT OF BENEFITS
(a) A participant entitled to benefits under Section 4(a) which are described in Section 4(a)(1) or 4(a)(2)(i) may elect to commence receiving such benefits unreduced on or after the date on which the participant attains the age of sixty-five (65) years or attains the age of sixty (60) years and is credited with at least twenty (20) Years of Service. A participant may elect to commence receiving benefits earlier if he or she has attained at least the age of fifty-five (55) years and is credited with at least ten (10) Years of Service, provided that the participant's benefit which represents the portion of his or her benefit calculated in accordance with Section 4(a)(1) or 4(a)(2)(i) shall be reduced by three percent (3%) for each year (or part thereof) by which the participant's retirement age precedes the date on which he or she would have attained the age of sixty (60) years if he or she is credited with at least twenty (20) Years of Service or the date on which he or she would have attained the age of sixty-five (65) years if credited with less than twenty (20) Years of Service.
Benefits payable to a participant under Section 4(a)(1) or Section 4(a)(2)(i) shall be payable in accordance with Section 6.2 of the Retirement Plan, and if married, shall provide a monthly payment to the participant for his or her life equal to the amount determined under Section 4(a)(1) or Section 4(a)(2)(i) and upon his or her death, shall provide monthly payments to the participant's spouse for life equal to fifty percent (50%) of the monthly payment being received by the participant at the time of his or her death.
If a participant entitled to benefits under Section 4(a)(1) or Section 4(a)(2)(i) dies while still employed by the Company or an Affiliate, the participant's spouse shall be entitled to a survivor annuity equal to one hundred percent (100%) of the monthly benefit that the participant would have received under Section 4(a)(1) or Section 4(a)(2)(i) had he or she terminated employment on the day before he or she died, survived to the age on which he or she would first be
9
eligible to commence benefits under this Section 5(a), elected to retire and commence benefits under the Plan at that time and then died. Benefits payable to the surviving spouse shall commence on the first day of the month following the participant's date of death. The surviving spouse's monthly benefit shall be reduced by the monthly benefit that the spouse receives under Section 5.9 or
Section 5.10 of the Retirement Plan, whichever is applicable. Benefits payable to a terminated participant entitled to benefits under Section 4(a)(1) or 4(a)(2)(i) who dies prior to commencing benefits shall be paid in the form of a survivor annuity equal to fifty percent (50%) of the monthly benefit which the participant would have received had he or she survived to the earliest date under this Section 5(a) upon which he or she could have commenced benefits. Such benefits shall commence on the earliest date under this Section 5(a) upon which the participant could have commenced benefits had he or she survived. The surviving spouse's monthly benefit shall be reduced by the monthly benefit that the spouse receives under Section 5.9 or Section 5.10 of the Retirement Plan, whichever is applicable.
(b) Benefits payable to a participant under Section 4(a)(2)(ii) or
Section 4(a)(3) shall become payable when a participant (or his or her spouse or beneficiary) begins to receive payment of his or her Retirement Account Balance under the Retirement Plan, and shall be subject to the same adjustments and shall be payable by the Company in the same manner and at the same time as the Plan participant's (or his or her spouse's or beneficiary's) Retirement Account Balance under the Retirement Plan is paid, as though such benefits were otherwise payable as a part of the benefits being paid under the Retirement Plan. An election or mode of payment under the Retirement Plan with respect to the participant's Retirement Account Balance shall constitute an election of a similar mode of payment under this Plan.
(c) Benefits payable to a participant under Section 4(b) shall become payable when a participant (or his or her spouse or beneficiary) begins to receive payments under the
10
Retirement Plan, and shall be subject to the same adjustments and shall be payable by the Company in the same manner and at the same time as the Plan participant's (or his or her spouse's or beneficiary's) benefits under the Retirement Plan are paid, as though such benefits were otherwise payable as a part of the benefits being paid under the Retirement Plan, subject to ARTICLE SIX. Except as provided in this Subsection (c) or Subsection (d) of this ARTICLE FIVE, an election or mode of payment under the Retirement Plan shall constitute an election of a similar mode of payment under this Plan. The form of payment under Section 6.6 of the Retirement Plan shall not be available under this Plan.
(d) If the present value of a Participant's vested benefits under the Plan is Five Thousand Dollars ($5,000.00), or less, at any time after the Participant's retirement or termination of employment and before his or her Annuity Starting Date, the Participant's vested benefits shall be distributed in a single lump sum. The benefits of a non-vested Participant shall automatically be deemed to be cashed out pursuant to this ARTICLE FIVE (d) upon such Participant's termination of employment. If the present value of a Participant's vested benefits is more than Five Thousand Dollars ($5,000.00) but not more than Ten Thousand Dollars ($10,000.00) at any time after the Participant's retirement or termination of employment and before his or her Annuity Starting Date, the Participant's vested benefits shall be distributed in a single lump sum if such distribution is requested in writing by the Participant and his spouse, if married, in accordance with the consent and waiver provisions of Section 6.2 of the Retirement Plan.
If the present value of the Spouse's Benefit or Vested Survivor's Benefit under the Plan, as applicable, is Five Thousand Dollars ($5,000.00), or less, at any time after the Participant's death and before the commencement of such benefit, the benefit shall be distributed in a single lump sum. If the present value of the Spouse's Benefit or Vested Survivor's Benefit is more than Five Thousand Dollars ($5,000.00) but not more than Ten Thousand Dollars ($10,000.00) at any
11
time after the Participant's death and before the commencement of such benefit, the benefit shall be distributed in a single lump sum if such distribution is requested in writing by the Participant's surviving Spouse.
For purposes of calculating the present value of a Participant's vested benefits, the Spouse's Benefit or the Vested Survivor's Benefit, the actuarial assumptions incorporated by reference in Section 2.1(c) of the Retirement Plan shall be used, but in no event shall such present value be less than the present value calculated using the "applicable interest rate" and "applicable mortality table," as defined in Section 5.19 of the Retirement Plan.
ARTICLE SIX
COORDINATION OF BENEFITS
If an employee who was participating in a retirement plan sponsored by an Affiliate, which is not a participating employer in the Retirement Plan, becomes an employee of the Company or a participating Affiliate and a participant in the Plan under Section 4(b) and such employee's accrued benefit under the retirement plan maintained by the Affiliate formerly employing him or her is transferred to the Retirement Plan, upon termination of employment, the employee's benefits, calculated in accordance with Section 4(b), will be payable in full from the Plan in accordance with Section 5(b). If an employee who was a participant in the retirement plan of an Affiliate, which is not a participating employer in the Retirement Plan, becomes an employee of the Company or a participating Affiliate and a participant in this Plan, and such employee's accrued benefit under the retirement plan maintained by his or her former employer is not transferred to the Retirement Plan, upon termination of employment, the employee's benefits, calculated in accordance with Section 4(b), will be payable from the Plan in accordance with Section 5(b) to the extent such benefits are attributable to the pension benefits payable to that employee under the Retirement Plan. The benefits calculated pursuant to Section 4(b) that are attributable to the pension benefits payable to
12
the employee under the Retirement Plan are those benefits that bear the same ratio to the total benefits due to the employee, calculated pursuant to Section
4(b), as the benefit payable to the employee from the Retirement Plan bears to the total benefits payable to the employee under both the Retirement Plan and the retirement plan maintained by the Affiliate formerly employing that employee.
ARTICLE SEVEN
FUNDING
Benefits under this Plan shall be payable from the general assets of the Company and shall not be segregated in a trust fund or otherwise funded in any manner prior to the time of payment. No Plan participant shall have any vested rights hereunder nor any right hereunder to any specific assets of the Company.
ARTICLE EIGHT
ADMINISTRATION
The Plan will be administered by the Administrative Committee that administers the Retirement Plan. Except as otherwise expressly provided in this Plan, the Administrative Committee shall have the same powers and responsibilities as it has under Sections 10.4 and 12.2 of the Retirement Plan. Claims for benefits under the Plan shall be determined in the manner set forth in Article Eleven of the Retirement Plan.
ARTICLE NINE
AMENDMENT AND TERMINATION OF THE PLAN
The Plan may be amended in whole or in part, prospectively or retroactively, by action of the Company's Board of Directors, and may be terminated at any time by action of the Board of Directors; provided, however, that no such amendment or termination shall reduce any amount payable hereunder to the extent such amount accrued prior to the date of amendment or
13
termination. All amendments shall be in writing, approved by the Company's Board of Directors and executed by a duly authorized officer of the Company.
ARTICLE TEN
ASSIGNMENT
No Plan participant or beneficiary of a Plan participant shall have any right to assign, pledge, hypothecate, anticipate or any way create a lien on any amounts payable hereunder. No amounts payable hereunder shall be subject to assignment or transfer or otherwise be alienable, either by voluntary or involuntary act, or by operation of law, or be subject to attachment, execution, garnishment, sequestration or other seizure under any legal, equitable or other process, or be liable in any way for the debts or defaults of Plan participants and their beneficiaries. Notwithstanding the foregoing, assignments of the benefits provided under this Plan shall be permitted for purposes of satisfying family support obligations if such assignments are pursuant to a court order which satisfies the requirements for a "qualified domestic relations order" as defined in Section 206(d)(3) of the Act.
ARTICLE ELEVEN
WITHHOLDING
Any taxes required to be withheld from payments to the Plan participants hereunder shall be deducted and withheld by the Company.
14
ARTICLE TWELVE
OTHER BENEFIT PLANS OF THE COMPANY
Nothing contained in this Plan shall prevent a Plan participant prior to his or her death, or his or her spouse or other beneficiary after his or her death, from receiving, in addition to any payments provided for under this Plan, any payments provided for under the Retirement Plan or under The Pinnacle West Capital Corporation Savings Plan, or which would otherwise be payable or distributable to him or her, his or her surviving spouse or beneficiary under any plan or policy of the Company or otherwise. Nothing in this Plan shall be construed as preventing the Company or any of its subsidiaries from establishing any other or different plans providing for current or deferred compensation for employees.
ARTICLE THIRTEEN
MISCELLANEOUS
Nothing contained in this Plan shall be construed as a contract of employment between the Company and an employee, or as a right of any employee to be continued in the employment of the Company, or as a limitation of the right of the Company to discharge any of its employees, with or without cause.
All of the provisions of this Plan shall be binding upon all persons who shall be entitled to any benefit hereunder, their heirs and personal representatives.
15
ARTICLE FOURTEEN
EFFECTIVE DATE
The Plan, as amended and restated, shall be effective as of January 1, 2003.
IN WITNESS WHEREOF, the Company has caused this Pinnacle West Capital Corporation Supplemental Excess Benefit Retirement Plan, as amended and restated herein, to be executed by its duly authorized officer this 18th day of December, 2003.
PINNACLE WEST CAPITAL CORPORATION

                                By /s/ Jack E. Davis
                                   --------------------------------------------
                                Its   President & Chief Operating Officer
                                      of Pinnacle West Capital Corporation and
                                      President and Chief Executive Officer of
                                      Arizona Public Service Company

Attest:
By    /s/ Nancy C. Loftin
      ---------------------------------
Its   Vice President, General Counsel
      and Secretary	

16
 
.
.
.
Exhibit 12.1
PINNACLE WEST CAPITAL CORPORATION
COMPUTATION OF EARNINGS TO FIXED CHARGES
 (THOUSANDS OF DOLLARS)

                                                        Twelve Months Ended
                                                           December 31,
                                       ----------------------------------------------------
                                         2003       2002       2001       2000       1999
                                       --------   --------   --------   --------   --------
Earnings:
     Income from Continuing
       Operations...................   $230,576   $206,198   $327,367   $302,332   $269,772
     Income Taxes...................    105,560    132,228    213,535    194,200    141,592
     Fixed Charges..................    235,658    219,651    211,958    202,804    194,070
                                       --------   --------   --------   --------   --------
       Total........................    571,794    558,077    752,860    699,336    605,434
                                       ========   ========   ========   ========   ========

Fixed Charges:
     Interest Expense...............    204,590    187,512    175,822    166,447    157,142
     Estimated Interest Portion of
       Annual Rents.................     31,068     32,139     36,136     36,357     36,928
                                       --------   --------   --------   --------   --------
       Total Fixed Charges..........    235,658    219,651    211,958    202,804    194,070
                                       ========   ========   ========   ========   ========

Ratio of Earnings to Fixed Charges
     (rounded down).................       2.42       2.54       3.55       3.44       3.11
                                       ========   ========   ========   ========   ========	

6
 
Exhibit 21.1
SUBSIDIARIES OF THE COMPANY
Arizona Public Service Company
AXIOM Power Solutions, Inc.
Bixco, Inc.
PWENewco, Inc.
APSES Holdings, Inc.
APS Energy L.P.
APS Energy Services Company, Inc.
Northwind Phoenix LLC
Tucson District Energy LLC SunCor Development Company
SunCor Golf, Inc.
Westworld Golf Course LLC Golden Heritage Homes, Inc.
Golden Heritage Construction, Inc. Heritage Financial Services, LLC SCM, Inc.
SunCor Realty & Management Company Palm Valley Golf Club, Inc.
Rancho Viejo de Santa Fe, Inc.
Ranchland Utility Company Rancho Viejo Village Center, LLC SunCor Idaho, LLC
Golf de Mexico, S.A. de C.V.
Type Two, Inc.
Stone Ridge- Prescott Valley LLC Stone Ridge Golf Course LLC Hayden Ferry Lakeside LLC
Lakeside Residential Communities, L.L.C.
Edgewater at Hayden Ferry Lakeside, L.L.C. BV at Hayden Ferry Lakeside, L.L.C. Club West Golf Course LLC
Scottsdale Mountain LLP
SunRidge Canyon LLC
Sedona Golf Resort LLC
Kabuto/SunCor Joint Venture
Centrepoint Associates LLC
Hidden Hills of Scottsdale LLC
Talavi Associates LLC
Coral Canyon Town Center LLC
Coral Canyon HD, L.L.C.
El Dorado Investment Company
Underground Imaging Technologies, LLC NAC Holding Inc.
NAC International Inc. Phoenix Suns Limited Partnership AZ PB Partnership
El Dorado Ventures III
Phoenix Downtown Theater LLC
Nxt Phase
Pinnacle West Energy Corporation
GenWest, LLC
APACS Holdings LLC

Exhibit 23.1 
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos. 33-15190, 333-52476, 333-101457 and 333-53150 on Form S-3; Registration Statement Nos. 33-47534, 333-40796, 33-54307, 333-95035, 333-91786 and 33-1720 on Form S-8; and Registration Statement No. 2-96386 on Form S-14, all of Pinnacle West Capital Corporation, of our report dated March 11, 2004 (which report expresses an unqualified opinion and includes explanatory paragraphs relating to the change in 2003 in the method of accounting for non-trading derivatives in order to comply with the provisions of Emerging Issues Task Force Issue No. 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 Issue No. 02-3 , the change in 2002 in the method of accounting for trading activities in order to comply with the provisions of Emerging Issues Task Force Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities , and to the change in 2001 in the method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ) appearing in this Annual Report on Form 10-K of Pinnacle West Capital Corporation for the year ended December 31, 2003.
 
DELOITTE & TOUCHE LLP
 
Phoenix, Arizona
March 11, 2004

 

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)) 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)	 	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	
 		
 	c)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter 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: March 15, 2004.

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

 

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)) 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)	 	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	
 		
 	c)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter 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: March 15, 2004.

 	 	 	 	/s/ Donald E. Brandt	 	 	
 	 	 	 		 	 	
 	 	 	 	Donald E. Brandt	 	 	
 	 	 	 	Executive Vice 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, 2003 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: March 15, 2004.

 	 	 	 	/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, 2003 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: March 15, 2004.

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

 

Exhibit 99.1
PINNACLE WEST RISK FACTORS
(2003 Annual Report on Form 10-K)
     Set forth below and in other documents we file with the Securities and Exchange Commission are risks and uncertainties that could affect our financial results.
      We cannot predict the outcome of APS’ general rate case pending before the ACC.
     As required by a 1999 settlement agreement among Arizona Public Service Company (“APS”) and various parties (the “1999 Settlement Agreement”), on June 27, 2003, APS filed a general rate case with the Arizona Corporation Commission (the “ACC”). APS requested a $175.1 million, or 9.8%, increase in its annual retail electricity revenues, to become effective July 1, 2004. The major reasons for the request include:

 	•	 	complying with the provisions of the 1999 Settlement Agreement;	
 	
 	•	 	incorporating significant increases in fuel and purchased power costs, including results of purchases through the ACC’s “Track B” procurement process;	
 	
 	•	 	recognizing changes in APS’ cost of service, cost allocation and rate design;	
 	
 	•	 	obtaining rate base recognition of the generating plants built in Arizona by Pinnacle West Energy Corporation (“Pinnacle West Energy”) since 1999 to serve APS’ retail electricity customers, specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3 (the “PWEC Dedicated Assets”);	
 	
 	•	 	recovering $234 million written off by APS as a result of the 1999 Settlement Agreement; and	
 	
 	•	 	recovering restructuring and compliance costs associated with the ACC’s electric competition rules.	
     The general rate case will also address the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized in the 1999 Settlement Agreement, would allow APS to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the ACC retail competition rules described below. If APS does not have a rate adjustment mechanism that allows it to recover its full costs of procuring fuel for its generating plants, then changes in fuel prices may increase its cost of producing power or decrease the amount it receives from selling power, harming our financial performance. On November 4, 2003, the ACC approved the issuance of an order which authorizes a rate adjustment mechanism allowing APS to recover changes in purchased power costs (but not changes in fuel costs) incurred after July 1, 2004. The other rate adjustment mechanisms authorized in the 1999 Settlement Agreement (such as the costs associated with complying with the ACC electric competition rules) were also tentatively approved for subsequent implementation in the general rate case. The purchased power rate adjustment mechanism will not become effective until there is a final order in the general rate case, and the ACC further reserved the right to amend or modify, in all respects, this November 4 order during the rate case.
     In its filed testimony in the rate case, the ACC staff recommended, among other things, that the ACC decrease APS’ rates by approximately 8% (approximately $143 million annually), not allow the PWEC Dedicated Assets to be included in APS’ rate base, and not allow APS to recover any of the $234 million written off as a result of the 1999 Settlement Agreement. The ACC staff recommendations, if implemented as proposed, could have a material adverse impact on our results of operations, financial position, liquidity, dividend sustainability, credit ratings, and access to capital markets. We believe the ACC will be able to make a decision by the end of 2004. We cannot predict the outcome of the rate case and the resulting levels of regulated revenues.

 

      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. As part of the ACC’s approval of a $500 million financing arrangement between APS and Pinnacle West Energy, APS must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce its common equity below that threshold. As defined in the ACC financing order approving the arrangement, common equity ratio is common equity divided by common equity plus long-term debt, including current maturities of long-term debt. At December 31, 2003, APS’ common equity ratio was approximately 46%.
      We are subject to complex government regulation which may have a negative impact on our business and our results of operations.
     We are, directly and through our subsidiaries, subject to governmental regulation that may have a negative impact on our business and results of operations. We are a “holding company” within the meaning of the Public Utility Holding Company Act (“PUHCA”); however, we are exempt from the provisions of PUHCA by virtue of our filing of an annual exemption statement with the SEC.
     APS is subject to comprehensive regulation by several federal, state and local regulatory agencies, which significantly influence its operating environment and may affect its ability to recover costs from utility customers. APS is required to have numerous permits, approvals and certificates from the agencies that regulate APS’ business. The Federal Energy Regulatory Commission (“FERC”), the Nuclear Regulatory Commission (“NRC”), the Environmental Protection Agency (“EPA”), and the ACC regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that APS can charge customers. We believe the necessary permits, approvals and certificates have been obtained for APS’ existing operations. However, we are unable to predict the impact on our business and operating results from the future regulatory activities of any of these agencies. Changes in regulations or the imposition of additional regulations could have an adverse impact on our results of operations.
      The procurement of wholesale power by APS without the ability to adjust retail rates could have an adverse impact on our business and
     financial results.
     The 1999 Settlement Agreement limits APS’ ability to change retail rates until at least July 1, 2004, which could have a significant adverse financial impact on us if wholesale power prices significantly exceed the amount included for generation costs in APS’ current bundled retail rates. Under the ACC’s rules, APS is the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows APS to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in APS’ cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last three years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS’ current retail rates. APS regularly makes short-term seasonal purchases of power, and may experience unforeseen increases in load demand or generation or transmission outages, requiring APS to purchase additional supplemental power in the wholesale spot market. Unless APS is able to obtain an adjustment of its rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that APS would be able to fully recover the costs of this power. In addition, APS filed a general rate case with the ACC on June 27, 2003 (see discussion above). Among other things, the rate case will address the implementation of rate adjustment mechanisms, which would allow APS to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the ACC retail competition rules.
2

 

      If we are not able to access capital at competitive rates, our ability to implement our financial strategy will be adversely affected.
     We rely on access to short-term money markets, longer-term capital markets and the bank markets as a significant source of liquidity and for capital requirements not satisfied by the cash flow from our operations. We believe that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain market disruptions or a downgrade of our credit rating 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;	
 	
 	•	 	capital market conditions generally;	
 	
 	•	 	the bankruptcy of an unrelated energy company;	
 	
 	•	 	market prices for electricity and gas;	
 	
 	•	 	terrorist attacks or threatened attacks on our facilities or those of unrelated energy companies; or	
 	
 	•	 	the overall health of the utility industry.	
     Changes in economic conditions could result in higher interest rates, which would increase our interest expense on our debt and reduce funds available to us for our current plans. Additionally, an increase in our leverage could adversely affect us by:

 	•	 	increasing the cost of future debt financing;	
 	
 	•	 	increasing our vulnerability to adverse economic and industry conditions;	
 	
 	•	 	requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, which would reduce funds available to us for operations, future business opportunities or other purposes; and	
 	
 	•	 	placing us at a competitive disadvantage compared to our competitors that have less debt.	
      A significant reduction in our credit ratings could materially and adversely affect our business, financial condition and results of
     operations.
     We cannot be sure that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any downgrade could increase our borrowing costs which would diminish our financial results. We would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. In addition, borrowing costs under certain of our existing credit facilities depend on our credit ratings. A downgrade could also require us to provide additional support in the form of letters of credit or cash or other collateral to various counterparties. If our short-term ratings were to be lowered, it could limit our access to the commercial paper market. We note that the ratings from credit agencies are not recommendations to buy, sell or hold our securities and that each rating should be evaluated independently of any other rating.
      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.
     Retail competition could have a significant adverse financial impact on us due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. In 1999, the ACC approved rules that provide a framework for the introduction of retail electric competition in Arizona. Under the rules, as modified by the 1999 Settlement Agreement, APS was required to transfer all of its competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates no later than December 31, 2002. To satisfy this requirement APS had planned to transfer its generation assets to Pinnacle West Energy. Pursuant to an
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ACC order dated September 10, 2002, the ACC unilaterally modified the 1999 Settlement Agreement and directed APS to cancel any plans to divest interests in any of its generating assets. The ACC further established a requirement that APS solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. Pinnacle West Energy bid on and entered into contracts to supply most of APS’ requirements in the summer months through September 2006. These regulatory developments and legal challenges to the rules have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. 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 our load forecasts, plans for power supply and wholesale energy sales and related revenues. As a result of the changing regulatory environment and the relatively low barriers to entry, we expect wholesale competition to increase. As competition continues to increase, our financial position and results of operations could be adversely affected.
      Recent events in the energy markets that are beyond our control may have negative impacts on our business.
     As a result of the energy crisis in California during the summer of 2001, the recent volatility of natural gas prices in North America, the filing of bankruptcy by the Enron Corporation, and investigations by governmental authorities into energy trading activities, companies generally in the regulated and unregulated utility businesses have been under an increased amount of public and regulatory scrutiny. The capital markets and credit ratings agencies also have increased their level of scrutiny. We believe that we are complying with all applicable laws, but it is difficult or impossible to predict or control what effect these or related issues may have on our business or our access to the capital markets.
      Our results of operations can be adversely affected by milder weather.
     Weather conditions directly influence the demand for electricity and affect the price of energy commodities. Electric power demand is generally a seasonal business. In Arizona, demand for power peaks during the hot summer months, with market prices also peaking at that time. As a result, our overall operating results fluctuate substantially on a seasonal basis. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. As a result, unusually mild weather could diminish our results of operations and harm our financial condition.
      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, the Palo Verde Nuclear Generating Station (“Palo Verde”), which is the largest nuclear electric generating facility in the United States. Palo Verde is subject to environmental, health and financial risks such as the ability to dispose of spent nuclear fuel, the ability to maintain adequate reserves for decommissioning, potential liabilities arising out of the operation of these facilities, and the costs of securing the facilities against possible terrorist attacks and unscheduled outages due to equipment and other problems. We maintain nuclear decommissioning trust funds and external insurance coverage to minimize our financial exposure to some of these risks; however, it is possible that damages could exceed the amount of insurance coverage.
     The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. In addition, although we have no reason to anticipate a serious nuclear incident at Palo Verde, if an incident did occur, it could materially and adversely affect our results of operations or financial condition. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.
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     The operation of Palo Verde requires licenses that need to be periodically renewed and/or extended. We do not anticipate any problems renewing these licenses. However, as a result of potential terrorist threats and increased public scrutiny of utilities, the licensing process could result in increased licensing or compliance costs that are difficult or impossible to predict.
      The 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. We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances and credits. We have established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity.
     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of all counterparties. Despite the fact that the majority of trading counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material adverse impact on our earnings for a given period.
     Changing interest rates will affect interest paid on variable-rate debt and interest earned by our pension plan and nuclear decommissioning trust funds. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The pension plan is also impacted by the discount rate, which is the interest rate used to discount future pension obligations. Continuation of recent decreases in the discount rate would result in increases in pension costs, cash contributions, and charges to other comprehensive income. The pension plan and nuclear decommissioning trust funds also have risks associated with changing market values of equity investments. A significant portion of the pension costs and all of the nuclear decommissioning costs are recovered in regulated electricity prices.
      The uncertain outcome regarding the creation of regional transmission organizations, or RTOs, and implementation of the FERC’s
     standard market design may materially impact our operations, cash flows or financial position.
     In a December 1999 order, the FERC established characteristics and functions that must be met by utilities in forming and operating RTOs. The characteristics for an acceptable RTO include independence from market participants, operational control over a region large enough to support efficient and nondiscriminatory markets and exclusive authority to maintain short-term reliability. Additionally, in a pending notice of proposed rulemaking, the FERC is considering implementing a standard market design for wholesale markets. On October 16, 2001, APS and other owners of electric transmission lines in the Southwest filed with the FERC a request for a declaratory order confirming that their proposal to form WestConnect RTO, LLC would satisfy the FERC’s requirements for the formation of an RTO. On October 10, 2002, the FERC issued an order finding that the WestConnect proposal, if modified to address specified issues, could meet the FERC’s RTO requirements and provide the basic framework for a standard market design for the Southwest. On September 15, 2003, the FERC issued an order granting clarification and rehearing, in part, of its prior orders. In particular, this order approved the use of a physical congestion management scheme, which is used to allocate transmission rights on congested lines, for WestConnect for an initial phase-in period. FERC indicated that the WestConnect utilities and the appropriate regional state advisory committee should develop a market-based congestion management scheme for subsequent implementation. APS is now participating in a cost/benefit analysis of implementing WestConnect, the results of which are expected to be completed in 2004.
     If APS ultimately joins an RTO, APS could incur increased transmission-related costs and reduced transmission service revenues; APS may be required to expand its transmission system according to decisions made by the RTO rather than its internal planning process; and APS may experience other impacts on its operations, cash flows or financial position that will not be quantifiable until the final tariffs and other material terms of the RTO are known.
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      We are subject to numerous environmental laws and regulations which may increase our cost of operations, impact our business plans,
     or expose us to environmental liabilities.
     We are subject to numerous environmental regulations affecting many aspects of our 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 us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.
     In addition, we may be a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.
     We cannot be sure that existing environmental regulations will not be revised or that new regulations seeking to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from APS’ customers, could have a material adverse effect on our results of operations.
      Actual results could differ from estimates used to prepare our financial statements.
     In preparing the financial statements in accordance with generally accepted accounting principles, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

 	•	 	Regulatory Accounting — Regulatory accounting allows for the actions of regulators, such as the ACC and the FERC, to be reflected in the 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. We had $165 million of regulatory assets on the Consolidated Balance Sheets at December 31, 2003.	
 	
 	•	 	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, plan funding requirements and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.	
 	
 	•	 	Derivative Accounting — Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, will determine whether we use accrual accounting or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in fair value be recorded in earnings or, if certain hedge accounting criteria are met, in common stock equity (as a component of other comprehensive income (loss)).	
 	
 	•	 	Mark-to-Market Accounting — The market 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	
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 	 	 	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.	
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