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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549



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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 1-4473


Arizona Public Service Company

(Exact name of registrant as specified in its charter)


|                                         |  |                                     
|---------------------------------------- |  | ------------------------------------
|ARIZONA                                  |  | 86-0011170                          
|(State or other jurisdiction             |  | (I.R.S. Employer Identification No.)
|of incorporation or organization)        |  |                                     
|400 North Fifth Street, P.O. Box 53999   |  |                                     
|Phoenix, Arizona 85072-3999              |  | (602) 250-1000                      
|(Address of principal executive offices, |  | (Registrants telephone number,     
|including zip code)                      |  | including area code)                



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Securities registered pursuant to Section 12(b) or 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 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 o No
x

As of
March 15, 2004, there were issued and outstanding 71,264,947 shares
of the registrants common stock, $2.50 par value, all of which were held
beneficially and of record by Pinnacle West Capital Corporation.

The registrant meets the conditions set forth in General Instruction I1(a)
and (b) and is therefore filing this document with the reduced disclosure
format.



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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 FINANCIAL DATA                                                                        
|           | ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS          
|           | ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                    
|           | 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 FEES AND SERVICES                                                        
|PART IV   
|           | ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K                              
|SIGNATURES
|EX-3.1    
|EX-12.1   
|EX-23.1   
|EX-31.1   
|EX-31.2   
|EX-32.1   
|EX-99.1   



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TABLE OF CONTENTS

|           |  |                                                                                                |  |  |     |      |  | 
|---------- |  | ---------------------------------------------------------------------------------------------- |  |  | --- | ---- |  | 
|           |  |                                                                                                |  |  |     | Page
|           |  |                                                                                                |  |  |     |     
|GLOSSARY   |  |                                                                                                |  |  | 1   |     
|PART I     |  |                                                                                                |  |  | 3   |     
|Item 1.    |  | Business                                                                                       |  |  | 3   |     
|Item 2.    |  | Properties                                                                                     |  |  | 14  |     
|Item 3.    |  | Legal Proceedings                                                                              |  |  | 19  |     
|Item 4.    |  | Submission of Matters to a Vote of Security Holders                                            |  |  | 19  |     
|PART II    |  |                                                                                                |  |  | 19  |     
|Item 5.    |  | Market for Registrants Common Stock and Related Stockholder Matters                           |  |  | 19  |     
|Item 6.    |  | Selected Financial Data                                                                        |  |  | 20  |     
|Item 7.    |  | Managements Discussion and Analysis of Financial Condition and Results
of Operations          |  |  | 21  |     
|Item 7A.   |  | Quantitative and Qualitative Disclosures about Market Risk                                     |  |  | 42  |     
|Item 8.    |  | Financial Statements and Supplementary Data                                                    |  |  | 43  |     
|Item 9.    |  | Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure           |  |  | 105 |     
|Item 9A.   |  | Controls and Procedures                                                                        |  |  | 105 |     
|PART III   |  |                                                                                                |  |  | 106 |     
|Item 10.   |  | Directors and Executive Officers of the Registrant                                             |  |  | 106 |     
|Item 11.   |  | Executive Compensation                                                                         |  |  | 106 |     
|Item 12.   |  | Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters |  |  | 106 |     
|Item 13.   |  | Certain Relationships and Related Transactions                                                 |  |  | 106 |     
|Item 14.   |  | Principal Accountant Fees and Services                                                         |  |  | 106 |     
|PART IV    |  |                                                                                                |  |  | 107 |     
|Item 15.   |  | Exhibits, Financial Statement Schedules, and Reports on Form 8-K                               |  |  | 107 |     
|SIGNATURES |  |                                                                                                |  |  | 135 |     

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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, the Company

APS Energy Services  APS Energy Services Company, Inc., a subsidiary of
Pinnacle West

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  Arizona Public Service Company

DOE  United States Department of Energy

EITF  the FASBs Emerging Issues Task Force

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 our $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

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





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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, parent company of the
Company

Pinnacle West Energy  Pinnacle West Energy Corporation, a subsidiary of
Pinnacle West

PRP  potentially responsible parties under Superfund

PWEC Dedicated Assets  the following Pinnacle West Energy power plants, each
of which is dedicated to serving our 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 Pinnacle West

Superfund  Comprehensive Environmental Response, Compensation and Liability
Act

T&D  transmission and distribution

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

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PART I




ITEM 1. BUSINESS

CURRENT STATUS

General

We were incorporated in 1920 under the laws of Arizona and currently have
more than 931,500 customers. Pinnacle West owns all of our outstanding common
stock. We are 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. Electricity is delivered through a
distribution system that we own. We do not distribute any products. During
2003, no single purchaser or user of energy (other than Pinnacle West)
accounted for more than 4% of total electric revenues. Through our marketing
and trading division, we generate, sell and deliver electricity to wholesale
customers in the western United States. The marketing and trading division
also sells, in the wholesale market, our and Pinnacle West Energy generation
output that is not needed for our Native Load, which includes loads for retail
customers and cost-of-service wholesale customers. The marketing and trading
division focuses primarily on managing our purchased power and fuel risks in
connection with our costs of serving retail customer energy requirements.
Additionally, the marketing and trading division, subject to specific
parameters, markets, hedges and trades in electricity, fuels and emission
allowances and credits.

At December 31, 2003, we employed approximately 6,000 people, which includes employees at jointly-owned generating facilities for which we serve as
the generating facility manager. Our principal executive offices are located
at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone 602-250-1000).

Business Segments

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



| |  |  | our regulated electricity segment (95% 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; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | our marketing and trading segment (5% of operating revenues
in 2003), which consists of our competitive energy business
activities, including wholesale marketing and trading.                                                                            

See Note 15 of Notes to Financial Statements in Item 8 for financial
information about our business segments.

General Rate Case

We believe our 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
Financial Statements in Item 8, in this

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rate case we have 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 us as part of
the 1999 Settlement Agreement. In its filed testimony, the ACC staff
recommended, among other things, that the ACC decrease our rates by
approximately 8% (approximately $143 million annually), not allow the PWEC
Dedicated Assets to be included in our rate base, and not allow us 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 our rate case requests are supported by,
among other things, our demonstrated need for the PWEC Dedicated Assets; our
need to attract capital at reasonable rates of return to support the required
capital investment to ensure continued customer reliability in our 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.

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 we 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                                                                                                                                                                      

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| |   |  | 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;                                                                                                                                                                                                    
|
| |  |  | 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;                                                                                                                                                                                                                                    
|
| |  |  | 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 our retail electric rates and our issuance of
securities. The ACC must also approve any transfer of our property used to
provide retail electric service and approve or receive prior notification of
certain transactions between us and affiliated parties. See Note 3 of Notes to
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.

As of January 1, 2001, all of our 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 our
customers. As a result, we cannot predict when, and the extent to which,
additional competitors will re-enter our 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 Financial Statements in Item 8 for
additional information.

We are 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). We also face 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.

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Wholesale

General

The FERC regulates rates for wholesale power sales and transmission
services. During 2003, approximately 8% of our electric operating revenues
resulted from such sales and services. In early 2003, the marketing and
trading division was moved from Pinnacle West to us 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 our generating assets to Pinnacle West Energy (see Track A Order
in Note 3 of Notes to Financial Statements in Item 8).

The marketing and trading division focuses primarily on managing our
purchased power and fuel risks in connection with our costs of serving retail
customer energy requirements. The division also sells, in the wholesale market, our and Pinnacle West Energy generation output that is
not needed for our 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 Financial Statements in Item 8 for information regarding an
ACC-mandated process by which we 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

FederalIn 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, we 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. We are now participating in a cost/benefit
analysis of implementing WestConnect, the results which are expected to be
completed in 2004.

StateThe 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.
We participated in the creation of the AISA, a not-for-profit entity, and the
filing at the FERC for

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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 we should be required
to continue funding the AISA.

Purchased Power and Generating Fuel

See Properties  Net Accredited Capacity in Item 2 for information about
our power plants by fuel types.

2003 Energy Mix

Our
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

ChollaCholla is a coal-fired power plant located in northeastern
Arizona. It is a jointly-owned facility operated by us. We purchase 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. We 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, we believe that numerous competitive fuel
supply options will exist to ensure the continued operation of Cholla for its
useful life.

Four CornersFour Corners is a coal-fired power plant located in the
northwestern corner of New Mexico. It is a jointly-owned facility operated by
us. We purchase 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 StationThe Navajo Generating Station is a coal-fired
power plant located in northern Arizona. It is a jointly-owned facility
operated by Salt River Project. The Navajo Generating Stations coal
requirements are purchased from a supplier with long-term leases from the
Navajo Nation and the Hopi Tribe. The Navajo Generating Station is under
contract with its coal supplier through 2011, with options to extend through
the 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  Net Accredited Capacity in Item 2 for information about
our ownership interests in Cholla, Four Corners and the Navajo Generating
Station. See Note 10 of Notes to Financial Statements in Item 8 for
information regarding our coal mine reclamation obligations.

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Natural Gas Supply

See Note 10 of Notes to Financial Statements in Item 8 for a discussion of
our natural gas requirements.

Nuclear Fuel Supply

Palo Verde Fuel CyclePalo Verde is a nuclear power plant located about
50 miles west of Phoenix, Arizona. It is a jointly-owned facility operated by
us. The fuel cycle for Palo Verde is comprised of the following stages:



| |  |  | mining and milling of uranium ore to produce uranium concentrates;
| | - |  | ------------------------------------------------------------------
|
| |  |  | conversion of uranium concentrates to uranium hexafluoride;       
|
| |  |  | enrichment of uranium hexafluoride;                               
|
| |  |  | fabrication of fuel assemblies;                                   
|
| |  |  | utilization of fuel assemblies in reactors; and                   
|
| |  |  | storage and disposal of spent nuclear fuel.                       

The Palo Verde participants have contracted for all of Palo Verdes
requirements for uranium concentrates and conversion services through 2008.
The Palo Verde participants have also contracted for all of Palo Verdes
enrichment services through 2010 and fuel assembly fabrication services until
at least 2015.

Spent Nuclear Fuel and Waste DisposalSee Palo Verde Nuclear Generating
Station in Note 10 of Notes to Financial Statements in Item 8 for a discussion
of spent nuclear fuel and waste disposal.

Purchased Power Agreements

In addition to that available from our own generating capacity (see
Properties in Item 2), we purchase 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 us is based in large part on
customer demand within certain areas now served by us pursuant to a related
territorial agreement. The generating capacity available to us pursuant to the
contract was 343 MW from January through May 2003, and starting in June 2003,
it changed to 350 MW. In 2003, we 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. We may also cancel the contract on
five years notice, given no earlier than December 31, 2006.

In September 1990, we entered into a thirty-year seasonal capacity
exchange agreement with PacifiCorp. Under this agreement, we receive
electricity from PacifiCorp during the summer peak season (from May 15 to
September 15) and we return electricity to PacifiCorp during the winter season
(from October 15 to February 15). Until 2020, we and PacifiCorp each have 480
MW of capacity and a related amount of energy available to us under the
agreement for our respective seasons. In 2003, we received approximately
571,392 MWh of energy under the capacity exchange. We must also make
additional offers of energy to PacifiCorp each year through October 31, 2020.

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Pursuant to this requirement, during 2003, PacifiCorp received offers of
1,091,450 MWh and purchased about 168,000 MWh.

In December 2003, we 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 our anticipated retail load. For additional information,
see Request for Proposals in Note 3 of Notes to Financial
Statements in Item 8.

Consistent with the ACCs Track B Order, we issued a request for proposals
(RFP) in March 2003 and, as a result of that RFP, on or before May 6, 2003,
we entered into contracts with three parties, including Pinnacle West Energy,
to meet a portion of our capacity and energy requirements for the years 2003
through 2006. See Track B Order in Note 3 of Notes to Financial Statements
in Item 8 for additional information about the contracts and the Track B Order.

Construction Program

During the years 2001 through 2003, we incurred approximately $1.4 billion
in capital expenditures. Our 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. Our capital expenditures were
approximately $429 million in 2003. Our 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 our generation (production) assets. We
conduct a continuing review of our construction program.

See Managements Discussion and Analysis of Financial Condition and
Results of Operations  Capital Needs and Resources in Item 7 for additional
information about our construction program.

Environmental Matters

EPA Environmental Regulation

Regional Haze RulesOn 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.

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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,
we do not anticipate any new emission reduction requirements for our 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. We are currently assessing the need 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, we do 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 PlanIn September 1999, the EPA proposed a FIP to
set air quality standards at certain power plants, including the Navajo
Generating Station and Four Corners. The FIP is similar to current Arizona
regulation of the Navajo Generating Station and New Mexico regulation of Four
Corners, with minor modifications. We do not currently expect the FIP to have
a material adverse effect on our financial position, results of operations or
liquidity.

SuperfundThe 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 us that
the EPA considers us to be a potentially responsible party in the Motorola
52nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. We have
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 SitesWe are currently investigating properties
which we now own or which were previously owned by us or our corporate
predecessors, that were at one time sites of, or sites associated with,
manufactured gas plants. Where appropriate, we conduct clean-up activities for
these sites. We do not expect these matters to have a material adverse effect
on our financial position, results of operations or liquidity.

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Arizona Department of Environmental Quality

ADEQ issued two NOVs to us in 2001 alleging, among other things, the
burning of unauthorized materials and storage of hazardous waste without a
permit at the Cholla Power Plant. We, 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, we paid a
$200,000 penalty to the State of Arizona.

ADEQ issued an NOV to us in January 2004 alleging, among other things,
that the discharge limit for lead was exceeded at the Saguaro Power Plant. We
are 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. We are the Four Corners operating
agent. We own a 100% interest in Four Corners Units 1, 2 and 3, and a 15%
interest in Four Corners Units 4 and 5. We own 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. We 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. We
believe that the Clean Air Act does not supersede these pre-existing
agreements. We 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.

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Water Supply

Assured supplies of water are important for our generating plants. At the
present time, we have adequate water to meet our 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 our operations
have been the subject of inquiries, claims and legal proceedings, which will
require a number of years to resolve. We are 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 us 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 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. Our 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, we 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, we seek confirmation of such rights.
Three of our other power plants and two of Pinnacle West Energys power plants
are also located within the geographic area subject to the summons. Our claims
dispute the courts jurisdiction over our groundwater rights with respect to
these plants. Alternatively, we seek 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 our water rights claims has been set in this matter.

We have 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). Our groundwater resource utilized at Cholla is within the
geographic area subject to the adjudication and is therefore potentially at
issue in the case. Our claims dispute the courts jurisdiction over our
groundwater rights. Alternatively, we seek 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 our water
rights claims has been set in this matter.

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Although the above matters remain subject to further evaluation, we expect
that the described litigation will not have a material adverse impact on our
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.

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ITEM 2. PROPERTIES

Net Accredited Capacity

Our 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                                                      |  |               | 4,012,191 | 
|                |                                                            |  |               |          

Reserve Margin

Our 2003 peak one-hour demand on our 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 us under long-term purchase power contracts as well as our and
Pinnacle West Energys generating capacity, our 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 us from our 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 Purchased Power Agreements in Item 1 for information about certain
of our long-term power agreements. See "Request for Proposals" in
Note 3 of Notes to Financial Statements in Item 8 for information
regarding a request for proposals issued by us in December 2003 for
the purchase of at least 500 MW of long-term power supply resources
for delivery beginning June 1, 2007.

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Plant Sites Leased from Navajo Nation

The Navajo Generating Station and Four Corners are located on land held
under easements from the federal government and also under leases from the
Navajo Nation. These are long-term agreements with options to extend, and 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 us, 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
other than us, the customer will still have to pay this charge as part of the
customers electric bill.

Other mechanisms are prescribed, including prepayment, if the requirements
for exclusive reliance on the external sinking fund mechanism are not met. We
currently rely on the external sinking fund mechanism to meet the NRC financial
assurance requirements for our interests in Palo Verde Units 1, 2 and 3. The
decommissioning costs of Palo Verde Units 1, 2 and 3 are currently included in
our ACC jurisdictional rates. The Rules provide that decommissioning costs
would be recovered through a non-bypassable system benefits charge, which
would allow us to maintain our external sinking fund mechanism. See Note 11 of
Notes to 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 10 of Notes to
Financial Statements in Item 8 for a discussion of the insurance maintained by
the Palo Verde participants, including us, for Palo Verde.

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Property Not Held in Fee or Subject to Encumbrances

Jointly-Owned Facilities

We share ownership of some of our generating and transmission facilities
with other companies. The following table shows our interest in those
jointly-owned facilities recorded on the Balance Sheets at December 31, 2003:

|                         |                                                                              |  |             |      |     
|------------------------ | ---------------------------------------------------------------------------- |  | ----------- | ---- | ----
|                         |                                                                              |  | Percent    
|                         |                                                                              |  | Owned by Us
|                         |                                                                              |  |            
|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)



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

Palo Verde Leases

In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. We account
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 8 and 18 of Notes to Financial Statements in Item 8 for additional
information regarding the Palo Verde Unit 2 sale-leaseback transactions.

First Mortgage Lien

Our 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 Financial Statements in Item 8 for
information regarding our outstanding first mortgage bonds.

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##### Table of Contents



Transmission Access

Our 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. Our 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 we 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.

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.

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(MAP)

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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
Financial Statements in Item 8 for a discussion of the ACC retail electric
competition Rules, the Track A Order and related litigation.

See Note 10 of Notes to Financial Statements in Item 8 for information
relating to the FERC proceedings on California energy market issues and a claim
by Citizens that we overcharged Citizens under a power service agreement.




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

Not applicable.




PART II




ITEM 5. MARKET FOR REGISTRANTS COMMON
STOCK AND RELATED STOCKHOLDER MATTERS

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

The chart below sets forth the dividends declared on the Companys common
stock for each of the four quarters for 2003 and 2002.

Common Stock Dividends
(Dollars in Thousands)

|            |  |      |        |      |  |   |        | 
|----------- |  | ---- | ------ | ---- |  | - | ------ | 
|Quarter     |  | 2003 |        | 2002
|            |  |      |        |     
|1st Quarter |  | $    | 42,500 |      |  | $ | 42,500 | 
|2nd Quarter |  |      | 42,500 |      |  |   | 42,500 | 
|3rd Quarter |  |      | 42,500 |      |  |   | 42,500 | 
|4th Quarter |  |      | 42,500 |      |  |   | 42,500 | 

After payment or setting aside for payment of cumulative dividends and
mandatory sinking fund requirements, where applicable, on all outstanding
issues of preferred stock, the holders of common stock are entitled to
dividends when and as declared out of funds legally available therefor. As of
December 31, 2003, we did not have any outstanding preferred stock.

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##### Table of Contents






ITEM 6. SELECTED FINANCIAL DATA

|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |           | 
|------------------------------- | ------------------------------------------------------------------- | -------------------- | --------- | ---------------------- | --------- | ---- | --------- | --------- | --------- | ---- | --------- | --------- | --------- | - | --------- | --------- | --------- | - | --------- | --------- | --------- | 
|                                |                                                                     |                      |           | 2003                   |           | 2002 |           | 2001      |           | 2000 |           | 1999     
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |          
|                                |                                                                     |                      |           | (dollars in thousands)
|Electric operating revenues:    |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |          
|                                | Regulated electricity segment (a)                                   |                      | $         | 1,999,390              |           |      | $         | 1,902,112 |           |      | $         | 1,984,305 |           |   | $         | 2,538,750 |           |   | $         | 1,914,722 |          
|                                | Marketing and trading segment (a)                                   |                      |           | 105,541                |           |      |           | 34,054    |           |      |           | 367,793   |           |   |           | 395,392   |           |   |           | 154,126   |          
|Purchased power and fuel costs: |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |          
|                                | Regulated electricity segment                                       |                      |           | 606,251                |           |      |           | 438,141   |           |      |           | 649,405   |           |   |           | 1,065,596 |           |   |           | 432,844   |          
|                                | Marketing and trading segment                                       |                      |           | 97,180                 |           |      |           | 32,662    |           |      |           | 132,544   |           |   |           | 267,032   |           |   |           | 136,522   |          
|Operating expenses              |                                                                     |                      | 1,103,342 |                        |           |      | 1,136,363 |           |           |      | 1,171,171 |           |           |   | 1,155,278 |           |           |   | 1,115,664 |          
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |          
|                                | Operating income                                                    |                      |           | 298,158                |           |      |           | 329,000   |           |      |           | 398,978   |           |   |           | 446,236   |           |   |           | 383,818   |          
|Other income/(deductions)       |                                                                     |                      | 26,347    |                        |           |      | (8,041    | )         |           |      | (79       | )         |           |   | (6,545    | )         |           |   | 20,857    |          
|Interest deductions  net       |                                                                     |                      | 143,568   |                        |           |      | 121,616   |           |           |      | 118,211   |           |           |   | 133,097   |           |           |   | 136,353   |          
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |          
|                                | Income before extraordinary
charge and cumulative effect
adjustment |                      |           | 180,937                |           |      |           | 199,343   |           |      |           | 280,688   |           |   |           | 306,594   |           |   |           | 268,322   |          
|                                | Extraordinary charge  net of
income tax (b)                        |                      |           |                       |           |      |           |          |           |      |           |          |           |   |           |          |           |   |           | (139,885  | )        
|                                | Cumulative effect of change in
accounting  net of income
tax (c)   |                      |           |                       |           |      |           |          |           |      |           | (15,201   | )         |   |           |          |           |   |           |          |          
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |          
|                                | Net income                                                          |                      |           | 180,937                |           |      |           | 199,343   |           |      |           | 265,487   |           |   |           | 306,594   |           |   |           | 128,437   |          
|                                | Preferred dividends                                                 |                      |           |                       |           |      |           |          |           |      |           |          |           |   |           |          |           |   |           | 1,016     |          
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |          
|                                | Earnings for common stock                                           |                      | $         | 180,937                |           |      | $         | 199,343   |           |      | $         | 265,487   |           |   | $         | 306,594   |           |   | $         | 127,421   |          
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |          
|Total Assets                    |                                                                     | $                    | 7,754,988 |                        |           | $    | 7,122,238 |           |           | $    | 6,815,458 |           |           | $ | 6,924,500 |           |           | $ | 6,603,725 |          
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |          
|Capital Structure:              |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |          
|                                | Common stock equity                                                 |                      | $         | 2,203,630              |           |      | $         | 2,159,312 |           |      | $         | 2,150,690 |           |   | $         | 2,119,768 |           |   | $         | 1,983,174 |          
|                                | Long-term debt less current
maturities                              |                      |           | 2,415,946              |           |      |           | 2,217,340 |           |      |           | 1,949,074 |           |   |           | 1,806,908 |           |   |           | 1,997,400 |          
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |          
|                                |                                                                     | Total capitalization |           |                        | 4,619,576 |      |           |           | 4,376,652 |      |           |           | 4,099,764 |   |           |           | 3,926,676 |   |           |           | 3,980,574 | 
|                                | Commercial paper                                                    |                      |           |                       |           |      |           |          |           |      |           | 171,162   |           |   |           | 82,100    |           |   |           | 38,300    |          
|                                | Current maturities of long-term
debt                                |                      |           | 206,727                |           |      |           | 3,503     |           |      |           | 125,451   |           |   |           | 250,266   |           |   |           | 114,711   |          
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |          
|                                |                                                                     | Total                |           | $                      | 4,826,303 |      |           | $         | 4,380,155 |      |           | $         | 4,396,377 |   |           | $         | 4,259,042 |   |           | $         | 4,133,585 | 
|                                |                                                                     |                      |           |                        |           |      |           |           |           |      |           |           |           |   |           |           |           |   |           |           |          



---

|(a) |  | Includes reclassifications of revenues in 2003, 2002 and 2001 for the
adoption of EITF 03-11. See Note 16 of Notes to Financial Statements.
|--- |  | -------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Changes associated with a regulatory disallowance. See Regulatory
Accounting in Note 1 of Notes to Financial Statements.                 
|   
|(c) |  | Change in accounting standards related to derivatives in 2001. See Note
16 of Notes to 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 Financial
Statements and the related Notes that appear in Item 8 of this report.

BUSINESS OVERVIEW

We are 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 our marketing and trading
division, we generate, sell and deliver electricity to wholesale customers in
the western United States. Our marketing and trading division also sells, in
the wholesale market, our and Pinnacle West Energys generation output that is
not needed for our Native Load, which includes loads for retail customers and
traditional cost-of-service wholesale customers. Our service territory growth
is about three times the national average and remains a fundamental driver of
our revenues and earnings. We do not distribute any products. Pinnacle West
owns all of our outstanding common stock.

Pinnacle West Energy is our unregulated generation affiliate. Pinnacle
West formed Pinnacle West Energy in 1999 as a result of the ACCs requirement
that we transfer all of our competitive assets and services to an affiliate or
to a third party by the end of 2002. We planned to transfer our 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 us from transferring our 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 us to unite the Arizona generation under
one common owner, as originally intended.

The earnings contributions of our marketing and trading segment decreased
in 2002 due to the transfer of our marketing and trading division to Pinnacle
West. In the first quarter of 2003, Pinnacle West moved the marketing and
trading division back to us for future marketing and trading activities
(existing wholesale contracts remained at Pinnacle West). In 2003, the
earnings contributions of our marketing and trading segment was negative due to
low 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 our purchased power and fuel risks in connection
with our 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.

21



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We believe our 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 we have 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 us as part of
the 1999 Settlement Agreement. In its filed testimony, the ACC staff
recommended, among other things, that the ACC decrease our rates by
approximately 8% (approximately $143 million annually), not allow the PWEC
Dedicated Assets to be included in our rate base, and not allow us 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 our rate case requests are supported by,
among other things, our demonstrated need for the PWEC Dedicated Assets; our
need to attract capital at reasonable rates of return to support the required
capital investment to ensure continued customer reliability in our 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.

BUSINESS SEGMENTS

We have two principal business segments (determined by 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; and                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | our marketing and trading segment, which consists of our
competitive energy business activities, including wholesale
marketing and trading. During 2001, we transferred most of our
marketing and trading activities to Pinnacle West. Thus, we did not
have any significant marketing and trading activity in 2002.
Conversely, in the first quarter of 2003, Pinnacle West moved the
marketing and trading division back to us for future marketing and
trading activities (existing wholesale contracts remained at
Pinnacle West). This latest move was a result of the ACCs Track A
Order prohibiting the previously-required transfer of our generating
assets to Pinnacle West Energy.

The following table summarizes earnings by business segment for the years
ended December 31, 2003, 2002, and 2001 (dollars in millions):

22



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##### Table of Contents



|                                                                    |                                 |            |     |      |     |      |     |      |     |   |     |     |     | 
|------------------------------------------------------------------- | ------------------------------- | ---------- | --- | ---- | --- | ---- | --- | ---- | --- | - | --- | --- | --- | 
|                                                                    |                                 |            |     | 2003 |     | 2002 |     | 2001
|                                                                    |                                 |            |     |      |     |      |     |     
|Regulated electricity                                               |                                 | $          | 184 |      |     | $    | 198 |      |     | $ | 138 |    
|Marketing and trading                                               |                                 |            | (3  | )    |     |      | 1   |      |     |   | 142 |    
|                                                                    |                                 |            |     |      |     |      |     |      |     |   |     |    
|                                                                    | Income before accounting change |            |     | 181  |     |      |     | 199  |     |   |     | 280 |    
|Cumulative effect of change in
accounting  net of income taxes (a) |                                 |            |    |      |     |      |    |      |     |   | (15 | )  
|                                                                    |                                 |            |     |      |     |      |     |      |     |   |     |    
|                                                                    |                                 | Net income |     | $    | 181 |      |     | $    | 199 |   |     | $   | 265 | 
|                                                                    |                                 |            |     |      |     |      |     |      |     |   |     |    



|(a) |  | We 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 16.
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|    |  | See Note 15 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. 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 16).

2003 Compared with 2002

Our net income for the year ended December 31, 2003 was $181 million
compared with $199 million for the prior year. The $18 million decrease in the
period-to-period comparison reflects the following changes in earnings by
segment:



| |  |  | Regulated Electricity Segment  Net income decreased $14
million due to higher purchased power and fuel costs resulting from
higher prices for hedged gas and purchased power; 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); 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 partially offset by higher retail sales
primarily due to customer growth and favorable weather; 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 our return to the AFUDC method of
capitalizing construction finance costs.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

23



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##### Table of Contents





| |  |  | Marketing and Trading Segment Net income decreased approximately
$4 million primarily due to the higher payroll costs incurred
related to the transfer of the marketing and trading division from
Pinnacle West to us, partially offset by increased generation sales
other than Native Load primarily due to higher sales volumes,
partially offset by lower unit margins.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Additional details on the major factors that increased (decreased) net
income for the year ended December 31, 2003 compared with the prior year are
contained in the following table (dollars in millions).

|                                                                                         |                                                                                                                                  |                                                                                         |     |                     |     |           |    |     |     |  
|---------------------------------------------------------------------------------------- | -------------------------------------------------------------------------------------------------------------------------------- | --------------------------------------------------------------------------------------- | --- | ------------------- | --- | --------- | -- | --- | --- | -
|                                                                                         |                                                                                                                                  |                                                                                         |     | 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                       |                                                                                         | $   | (74                 | )   |           | $  | (45 | )  
|                                                                                         | 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  |    
|                                                                                         | Effects of weather on retail sales                                                                                               |                                                                                         |     | 13                  |     |           |    | 8   |    
|                                                                                         | Decreased purchased power costs due to new power plants in service                                                               |                                                                                         |     | 8                   |     |           |    | 5   |    
|                                                                                         | Miscellaneous factors, net                                                                                                       |                                                                                         |     | 8                   |     |           |    | 4   |    
|                                                                                         |                                                                                                                                  |                                                                                         |     |                     |     |           |    |     |    
|                                                                                         |                                                                                                                                  | Net decrease in regulated electricity segment gross margin                              |     |                     | (71 | )         |    |     | (43 | )
|                                                                                         |                                                                                                                                  |                                                                                         |     |                     |     |           |    |     |    
|Marketing and trading segment gross margin:                                              |                                                                                                                                  |                                                                                         |     |                     |     |           |    |    
|                                                                                         | Increase in generation sales other than Native Load primarily due to
higher sales volumes partially offset by lower unit margins |                                                                                         |     | 10                  |     |           |    | 6   |    
|                                                                                         | Miscellaneous factors, net                                                                                                       |                                                                                         |     | (3                  | )   |           |    | (2  | )  
|                                                                                         |                                                                                                                                  |                                                                                         |     |                     |     |           |    |     |    
|                                                                                         |                                                                                                                                  | Net increase in marketing and trading segment gross margin                              |     |                     | 7   |           |    |     | 4   |  
|                                                                                         |                                                                                                                                  |                                                                                         |     |                     |     |           |    |     |    
|                                                                                         |                                                                                                                                  | Net decrease in regulated electricity and marketing and
trading segments gross margins |     |                     | (64 | )         |    |     | (39 | )
|Operations and maintenance expense decreases (increases):                                |                                                                                                                                  |                                                                                         |     |                     |     |           |    |    
|                                                                                         |                                                                                                                                  | Severance costs recorded in 2002                                                        |     |                     | 34  |           |    |     | 20  |  
|                                                                                         |                                                                                                                                  | Increased pension and other benefit costs                                               |     |                     | (22 | )         |    |     | (13 | )
|                                                                                         |                                                                                                                                  | Increased costs related to customer growth and increased payroll                        |     |                     | (15 | )         |    |     | (9  | )
|                                                                                         |                                                                                                                                  | Increased payroll cost related to transfer of power marketing
division                  |     |                     | (13 | )         |    |     | (8  | )
|                                                                                         |                                                                                                                                  | Net other items                                                                         |     |                     | (2  | )         |    |     | (1  | )
|Higher interest expense due to higher debt balances                                      |                                                                                                                                  |                                                                                         | (14 | )                   |     |           | (8 | )  
|Depreciation and amortization decreases (increases):                                     |                                                                                                                                  |                                                                                         |     |                     |     |           |    |    
|                                                                                         |                                                                                                                                  | Decreased regulatory asset amortization                                                 |     |                     | 29  |           |    |     | 18  |  
|                                                                                         |                                                                                                                                  | Increased delivery and other assets                                                     |     |                     | (19 | )         |    |     | (12 | )
|Our return to the AFUDC method of capitalizing construction finance costs                |                                                                                                                                  |                                                                                         | 8   |                     |     |           | 11 |    
|Higher other income due to increased interest income and investment gains                |                                                                                                                                  |                                                                                         | 15  |                     |     |           | 9  |    
|Miscellaneous items, net                                                                 |                                                                                                                                  |                                                                                         | 5   |                     |     |           | 3  |    
|Tax credits and favorable income tax adjustments related to prior years
resolved in 2003 |                                                                                                                                  |                                                                                         |    |                     |     |           | 11 |    
|                                                                                         |                                                                                                                                  |                                                                                         |     |                     |     |           |    |     |    
|                                                                                         |                                                                                                                                  | Net decrease in net income                                                              |     | $                   | (58 | )         |    | $   | (18 | )
|                                                                                         |                                                                                                                                  |                                                                                         |     |                     |     |           |    |     |    

24



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##### Table of Contents



Regulated Electricity Segment Revenues

Regulated electricity segment revenues were $97 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 $12 million net increase due to miscellaneous factors.                                                                  

Marketing and Trading Segment Revenues

Marketing and trading segment revenues were $71 million higher in the year
ended December 31, 2003 compared with the prior year, primarily as a result of:



| |  |  | a $66 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;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | a $5 million net increase due to miscellaneous factors.                                                                                                                

2002 Compared with 2001

Our net income for the year ended December 31, 2002 was $199 million
compared with $265 million for the prior year. 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 16). Excluding the
accounting changes, the $81 million decrease in the period-to-period comparison
reflects the following changes in earnings by segment:



| |  |  | Regulated Electricity Segment  Income before accounting
change increased $60 million primarily due to lower replacement
power costs for power plants outages, retail customer growth, higher
average customer usage and lower purchased power costs related to
2001 generation reliability program (the addition of generation
capability to enhance reliability for the summer of 2001). These
positive factors were partially offset by severance costs recorded
in 2002 relating to voluntary workforce reductions, 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 before accounting
change decreased $141 million primarily due to our transfer of the
marketing and trading activities to Pinnacle West in 2001.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           

Additional details on the major factors that increased (decreased) income
before accounting change and net income for the year ended December 31, 2002
compared with the prior year are contained in the following table (dollars in
millions).

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##### Table of Contents



|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      |                     |      |           |     |   |      |  
|-------------------------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ---------------------------------------------------------- | ---- | ------------------- | ---- | --------- | --- | - | ---- | -
|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      | 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  |  
|                                                                                                                                                               | 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 |  |                                                            | (24  | )                   |      |           | (14 | )
|                                                                                                                                                               | Lower purchased power and fuel costs related to the 2001 generation
reliability program                                                                            |  |                                                            | 30   |                     |      |           | 18  |  
|                                                                                                                                                               | 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 | )
|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      |                     |      |           |     |  
|                                                                                                                                                               |                                                                                                                                                                    |  | Net increase in regulated electricity segment gross margin |      |                     | 129  |           |     |   | 78   |  
|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      |                     |      |           |     |  
|Marketing and trading segment gross margin:                                                                                                                    |                                                                                                                                                                    |  |                                                            |      |                     |      |           |    
|                                                                                                                                                               | Decrease in marketing and trading segment margin resulting from our
transfer of marketing and trading activities to Pinnacle West in 2001                          |  |                                                            | (156 | )                   |      |           | (93 | )
|                                                                                                                                                               | Decrease in generation sales other than Native Load due to lower
market prices partially offset by higher sales volumes                                            |  |                                                            | (78  | )                   |      |           | (47 | )
|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      |                     |      |           |     |  
|                                                                                                                                                               |                                                                                                                                                                    |  | Net decrease in marketing and trading segment gross margin |      |                     | (234 | )         |     |   | (140 | )
|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      |                     |      |           |     |  
|Net decrease in regulated electricity and marketing and trading segments
gross margins                                                                        |                                                                                                                                                                    |  | (105                                                       | )    |                     |      | (62       | )  
|Higher operations and maintenance expense related to 2002 severance costs of
approximately $34 million, partially offset by lower generation reliability
costs |                                                                                                                                                                    |  | (30                                                        | )    |                     |      | (18       | )  
|Lower depreciation and amortization expense primarily related to lower
regulatory asset amortization                                                           |                                                                                                                                                                    |  | 21                                                         |      |                     |      | 13        |    
|Higher taxes other than income taxes                                                                                                                           |                                                                                                                                                                    |  | (7                                                         | )    |                     |      | (4        | )  
|Lower other income primarily due to a 2001 insurance recovery of
environmental remediation costs                                                               |                                                                                                                                                                    |  | (15                                                        | )    |                     |      | (9        | )  
|Higher net interest expense primarily due to higher debt balances and lower
capitalized interest                                                               |                                                                                                                                                                    |  | (3                                                         | )    |                     |      | (2        | )  
|Miscellaneous factors, net                                                                                                                                     |                                                                                                                                                                    |  | 2                                                          |      |                     |      | 1         |    
|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      |                     |      |           |     |  
|                                                                                                                                                               | Net decrease in income before accounting change                                                                                                                    |  | $                                                          | (137 | )                   |      |           | (81 | )
|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      |                     |      |           |    
|Increase due to 2001 cumulative effect of change in accounting for derivatives
- net of income taxes                                                           |                                                                                                                                                                    |  |                                                            |      |                     |      | 15        |    
|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      |                     |      |           |    
|                                                                                                                                                               | Net decrease in net income                                                                                                                                         |  |                                                            |      |                     |      | $         | (66 | )
|                                                                                                                                                               |                                                                                                                                                                    |  |                                                            |      |                     |      |           |    

Regulated Electricity Segment Revenues

Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $82 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 $69 million increase in retail revenues related to customer
growth and higher average usage, excluding weather effects;     

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| |  |  | a $28 million decrease in retail revenues related to
reductions in retail electricity prices;
| | - |  | ---------------------------------------------------------------------------------------------
|
| |  |  | a $60 million decrease in retail revenues related to milder weather; and                     
|
| |  |  | a $1 million net increase due to other miscellaneous factors.                                

Marketing and Trading Segment Revenues

Marketing and trading segment revenues were $334 million lower in the year
ended December 31, 2002, compared with the prior year as a result of:



| |  |  | $206 million of lower marketing and trading revenues as a
result of our transfer of marketing and trading activities to
Pinnacle West in 2001; and 
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | a $128 million decrease from generation sales other than
Native Load primarily due to lower market prices partially offset by
higher sales volumes.

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
|               |       |   |          |     |             |   |      |     |     
|Delivery       |       | $ | 288      |     |             | $ | 309  |     |      | $ | 390 |     |  | $ | 453 |    
|Generation (a) |       |   | 136      |     |             |   | 107  |     |      |   | 160 |     |  |   | 200 |    
|Other (b)      |       |   | 5        |     |             |   | 10   |     |      |   | 12  |     |  |   | 2   |    
|               |       |   |          |     |             |   |      |     |      |   |     |     |  |   |     |    
|               | Total |   | $        | 429 |             |   | $    | 426 |      |   | $   | 562 |  |   | $   | 655 | 
|               |       |   |          |     |             |   |      |     |      |   |     |     |  |   |     |    



|(a) |  | As discussed in Note 3 under General Rate Case and Retail Rate
Adjustment Mechanisms, as part of our 2003 general rate case, we
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) |  | The other amounts relate to capital expenditures for our marketing and
trading segment. In 2002, these costs were in the parent company.                                                                                                                                                                                                                                                          

Delivery capital expenditures are comprised of T&D infrastructure
additions and upgrades, capital replacements, new customer construction and
related information systems and facility costs. Examples of the types of
projects included in the forecast include T&D lines and substations, line
extensions to new residential and commercial developments and upgrades to
customer information

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systems. We 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. We will begin major projects each year for
the next several years, and expect to spend about $200 million on major
transmission projects during the 2004 to 2006 time frame. These amounts are
included in 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
our 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 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

Our capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. See Note 3 for
discussion of the $500 million financing arrangement between us and Pinnacle
West Energy approved by the ACC.

We pay for our capital requirements with cash from operations and, to the
extent necessary, external financings. We have historically paid for our
dividends to Pinnacle West with cash from operations. We must maintain a
common equity ratio of at least 40% and may not pay common dividends if the
payment would reduce our 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, our common equity ratio was approximately 45.7%.

On April 7, 2003, we redeemed approximately $33 million of our First
Mortgage Bonds, 8% Series due 2025, and on August 1, 2003, we redeemed
approximately $54 million of our First Mortgage Bonds, 7.25% Series due 2023.

On February 15, 2004, $125 million of our 5.875% Notes due 2004 were redeemed
at maturity and on March 1, 2004, $80 million of our First Mortgage Bonds,
6.625% Series due 2004 were redeemed at maturity. We used cash from operations
and short-term debt to redeem the maturing debt.

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On May 12, 2003, we issued $500 million of debt as follows: $300 million
aggregate principal amount of our 4.65% Notes due 2015 and $200 million
aggregate principal amount of our 5.625% Notes due 2033. Also on May 12, 2003,
we made a $500 million loan to Pinnacle West Energy.

Our outstanding debt was approximately $2.6 billion at December 31, 2003.
At December 31, 2003, we 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, we had no outstanding commercial paper or bank borrowings. We ended 2003
in an invested position.

Although provisions in our first mortgage bond indenture, articles of
incorporation and ACC financing orders establish maximum amounts of additional
first mortgage bonds, debt and preferred stock that we may issue, we do not
expect any of these provisions to limit our ability to meet our capital
requirements.

We participate in a pension plan sponsored by Pinnacle West. Pinnacle
West contributes 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. Pinnacle West elected to contribute cash to our pension plan in
each of the last five years; our minimum required contributions during each of
those years was zero. Specifically, Pinnacle West 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. We fund our share of the pension contribution. In 2003, we
represented 89% of the total cost of this plan. 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, Pinnacle West is required to contribute approximately $100
million to its pension plans and expects to contribute approximately $50
million to its other postretirement benefit plan in 2004. If currently pending
legislation is enacted, Pinnacle Wests required pension contribution in 2004
would decrease to the $25 to $50 million range.

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) |  | $    | 342 |      |  | $     | 699   |       |  | $      | 192 |  |  | $ | 2,567 |  |  | $ | 3,800 | 
|Capital lease payments                          |  |      | 2   |      |  |       | 4     |       |  |        | 2   |  |  |   | 3     |  |  |   | 11    | 
|Operating lease payments                        |  |      | 65  |      |  |       | 127   |       |  |        | 125 |  |  |   | 402   |  |  |   | 719   | 
|Minimum pension funding
requirement (b)         |  |      | 89  |      |  |       |      |       |  |        |    |  |  |   |      |  |  |   | 89    | 
|Purchase power and fuel
commitments (c)         |  |      | 262 |      |  |       | 187   |       |  |        | 102 |  |  |   | 461   |  |  |   | 1,012 | 
|Purchase obligations (d)                        |  |      | 87  |      |  |       | 27    |       |  |        | 5   |  |  |   | 68    |  |  |   | 187   | 
|Nuclear decommissioning
funding requirements    |  |      | 11  |      |  |       | 22    |       |  |        | 22  |  |  |   | 158   |  |  |   | 213   | 
|                                                |  |      |     |      |  |       |       |       |  |        |     |  |  |   |       |  |  |   |       | 
|Total contractual
commitments                   |  | $    | 858 |      |  | $     | 1,066 |       |  | $      | 448 |  |  | $ | 3,659 |  |  | $ | 6,031 | 
|                                                |  |      |     |      |  |       |       |       |  |        |     |  |  |   |       |  |  |   |       | 

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|(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) |  | If currently pending legislation is enacted, our share of the required
pension contribution in 2004 would decrease to the $22 to $44 million
range. Future pension contributions are not determinable for time periods
after 2004.
|   
|(c) |  | Our purchase power and fuel commitments include purchases of coal,
electricity, natural gas, and nuclear fuel (see Note 10).                                                                                                      
|   
|(d) |  | 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, we 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 8 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.

We are exposed to losses under the Palo Verde sale leaseback agreements
upon the occurrence of certain events that we do 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), we 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, we 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 have entered into various agreements that require letters of credit for
financial assurance purposes. We generally provide indemnifications relating
to liabilities arising from or related to certain of our agreements, except
with limited exceptions depending on the particular agreement. We have also
provided indemnifications to the equity participants and other parties in the
Palo Verde saleleaseback 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. See Note 19 for additional information
about our guarantees and letters of credit.

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Credit Ratings

The
ratings of our securities 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 price of our 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 16).

|                               |  |          |     |                   |  |  |     | 
|------------------------------ |  | -------- | --- | ----------------- |  |  | --- | 
|                               |  | Moody's  |     | Standard & Poor's
|                               |  |          |     |                  
|Senior secured                 |  |          | A3  |                   |  |  | A-  | 
|Senior unsecured               |  | Baa1     |     | BBB              
|Secured lease
obligation bonds |  | Baa2     |     | BBB              
|Commercial paper               |  |          | P-2 |                   |  |  | A-2 | 
|Outlook                        |  | Negative |     | Stable           

Debt Provisions

Our debt
covenants related to our financing arrangements
include a debt-to-total-capitalization ratio and an interest coverage test. We
comply with such covenants and we anticipate we will continue to meet all the
significant covenant requirement levels. The ratio of debt to total
capitalization cannot exceed 65%. At December 31, 2003, our ratio was
approximately 53%. The provisions regarding interest coverage require a
minimum cash coverage of two times the interest requirements. Based on 2003
results, coverage is approximately 4 times for our bank financing agreements
and 15 times for our 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.

Our financing agreements do not 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, we may be subject to increased interest costs under certain
financing agreements.

All of our bank agreements contain cross-default provisions that would
result in defaults and the potential acceleration of payment under these bank
agreements if we were to default under other agreements. Our 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.

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management
must often make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses and related disclosures at the date of
the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from

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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 Balance
Sheets at December 31, 2003. See Notes 1 and 3 for more information about
regulatory assets and our 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,
the 2003 reported pension liability on the Pinnacle West Consolidated Balance
Sheets and the 2003 reported pension expense, after consideration of amounts
capitalized or billed to electric plant participants, on the Pinnacle West
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 the 2003 reported other postretirement
benefit expense, after consideration of amounts capitalized or billed to
electric plant participants, on the Pinnacle West Consolidated Statements of
Income (dollars in millions):

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|                                                           |             |            |                        |                 |                 |  |   |    |  
|---------------------------------------------------------- | ----------- | ---------- | ---------------------- | --------------- | --------------- |  | - | -- | -
|                                                           |             |            | 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 7 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 16 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 16 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, Reporting Realized Gains and Losses on Derivative
Instruments That Are Subject to FASB Statement No. 133 and Not Held for
Trading Purposes As Defined in EITF Issue No. 02-3, 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.

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. We adopted the EITF 02-3, Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities in the fourth
quarter of 2002. The impact of the guidance was immaterial to our financial
statements.

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 16 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

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calculated in accordance with SFAS No. 71 Accounting for the Effects of
Certain Types of Regulation (see Note 1) and SFAS No. 143 (see Note 11).
Adopting SFAS No. 143 had no impact on our Statements of Income or our
Statements of Cash Flow.

Variable Interest Entities

See Liquidity and Capital Resources  Off-Balance Sheet Arrangements and
Note 18 for discussion of VIEs.

FACTORS AFFECTING OUR FINANCIAL OUTLOOK

General Rate Case

We believe our 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 we have 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 us as part of the 1999
Settlement Agreement. In its filed testimony, the ACC staff recommended, among
other things, that the ACC decrease our rates by approximately 8%
(approximately $143 million annually), not allow the PWEC Dedicated Assets to
be included in our rate base, and not allow us 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 our rate case requests are supported by, among other things, our
demonstrated need for the PWEC Dedicated Assets; our need to attract capital at
reasonable rates of return to support the required capital investment to ensure
continued customer reliability in our 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, which Pinnacle West moved to us 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 our transfer of generating assets to Pinnacle West Energy, focuses
primarily on managing our purchased power and fuel risks in connection with our
cost in serving retail customer demand. 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.

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Factors Affecting Operating Revenues

GeneralElectric operating revenues are derived from sales of electricity
in regulated retail markets in Arizona and from competitive retail and
wholesale power markets in the western United States. These revenues are
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

Customer GrowthCustomer growth in our 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 ChangesAs part of the 1999 Settlement Agreement, we 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 General Rate Case and Retail Rate
Adjustment Mechanisms in Note 3 for further information.

Other Factors Affecting Future Financial Results

Purchased Power and Fuel CostsPurchased 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 10 for more
information on fuel costs.

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

Depreciation and Amortization ExpensesDepreciation and amortization
expenses are impacted by net additions to existing utility plant and other
property, changes in regulatory asset amortization and our generation
construction program. The regulatory assets to be recovered under the 1999
Settlement Agreement are currently being amortized as follows (dollars in
millions):

|     |  |      |     |      |  |      |     |      |  |      |     |       |  |   |    |  |  |   |    |  |  |   |     | 
|---- |  | ---- | --- | ---- |  | ---- | --- | ---- |  | ---- | --- | ----- |  | - | -- |  |  | - | -- |  |  | - | --- | 
|1999 |  | 2000 |     | 2001 |  | 2002 |     | 2003 |  | 2004 |     | Total
|     |  |      |     |      |  |      |     |      |  |      |     |      
|$164 |  | $    | 158 |      |  | $    | 145 |      |  | $    | 115 |       |  | $ | 86 |  |  | $ | 18 |  |  | $ | 686 | 

Property TaxesTaxes other than income taxes consist primarily of
property taxes, which are affected by tax rates and the value of property
in-service and under construction. Our average property tax rate was 9.3% of
assessed value for 2003 and 9.7% for 2002.

36



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##### Table of Contents



Interest ExpenseInterest expense is affected by the amount of debt
outstanding and the interest rates on that debt. The primary factors affecting
borrowing levels in the next several years are expected to be our capital
requirements and our internally generated cash flow. Capitalized interest
offsets a portion of interest expense while capital projects are under
construction. We stop accruing capitalized interest on a project when it is
placed in commercial operation. 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 CompetitionThe 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 our service
area in 1999 and 2000, there are currently no active retail competitors
providing unbundled energy or other utility services to our customers. As a
result, we cannot predict when, and the extent to which, additional competitors
will re-enter our service territory.

GeneralOur financial results may be affected by a number of broad
factors. See Forward-Looking Statements below for further information on
such factors, which may cause our actual future results to differ from those we
currently seek or anticipate.

Market Risks

Our operations include managing market risks related to changes in
interest rates, commodity prices and investments held by 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 11). Our
policy is to manage interest rates through the use of a combination of
fixed-rate and floating-rate debt. The nuclear decommissioning fund also has
risk associated with changing market values of equity investments. Nuclear
decommissioning costs are recovered in regulated electricity prices.

The table below presents contractual balances of our long-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 table below represent
the weighted-average interest rates for the year ended December 31, 2003
(dollars in thousands):

37



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##### Table of Contents



Variable-Rate
    
    Fixed-RateShort-Term Debt
    
    Long-Term Debt
    
    Long-Term DebtInterest
    
    
    
    
    
    Interest
    
    
    
    
    
    InterestRates
    
    Amount
    
    Rates
    
    Amount
    
    Rates
    
    Amount2004
    
    
    
    %
    
    $
    
    
    
    
    
    %
    
    $
    
    
    
    
    6.16
    %
    
    $
    206,7272005
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7.27
    %
    
    
    402,2592006
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6.73
    %
    
    
    85,4512007
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5.55
    %
    
    
    1,1342008
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5.55
    %
    
    
    1,098Years thereafter
    
    
    
    
    
    
    
    
    
    
    1.51
    %
    
    
    386,860
    
    
    
    5.83
    %
    
    
    1,547,775Total
    
    
    
    
    
    $
    
    
    
    
    
    
    
    $
    386,860
    
    
    
    
    
    
    $
    2,244,444Fair value
    
    
    
    
    
    $
    
    
    
    
    
    
    
    $
    386,906
    
    
    
    
    
    
    $
    2,365,821
 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. The ERMC, consisting of officers and key management personnel, oversees
company-wide energy risk management activities and monitors the results of
marketing and trading activities to ensure compliance with our stated energy
risk management and trading policies. As part of our risk management program,
we use such instruments to hedge purchases and sales of electricity, fuels and
emissions allowances and credits. The changes in market value of such
contracts have a high correlation to price changes in the hedged commodities.
In addition, subject to specified risk parameters monitored by the ERMC, we
engage in marketing and trading activities intended to profit from market price
movements. 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 our
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): 38




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##### Table of Contents



Regulated
    
    MarketingElectricity
    
    and TradingMark-to-market of net positions
at December 31, 2002
    
    $
    (50
    )
    
    $
    Change in mark-to-market losses
for future period deliveries
    
    
    
    
    
    
    (4
    )Changes in cash flow hedges
recorded in OCI
    
    
    37
    
    
    
    3Ineffective portion of changes in fair value
recorded in earnings
    
    
    7
    
    
    
    Mark-to-market losses/(gains) realized
during the year
    
    
    6
    
    
    
    (3
    )Mark-to-market of net positions
at December 31, 2003
    
    $
    
    
    
    $
    (4
    )
 Regulated
    
    MarketingElectricity
    
    and TradingMark-to-market of net positions
at December 31, 2001
    
    $
    (107
    )
    
    $
    Change in mark-to-market losses
for future period deliveries
    
    
    (22
    )
    
    
    Changes in cash flow hedges
recorded in OCI
    
    
    64
    
    
    
    Ineffective portion of changes in fair
value recorded in earnings
    
    
    8
    
    
    
    Mark-to-market losses realized
during the year
    
    
    7
    
    
    
    Mark-to-market of net positions
at December 31, 2002
    
    $
    (50
    )
    
    $
    
 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 TotalYears
    
    fairSource of Fair Value
    
    2004
    
    2005
    
    thereafter
    
    valuePrices actively quoted
    
    $
    (4
    )
    
    $
    3
    
    
    $
    
    
    
    $
    (1
    )Prices provided by
other external sources
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    2Prices based on models
and other valuation
methods
    
    
    (1
    )
    
    
    
    
    
    
    
    
    
    
    (1
    )Total by maturity
    
    $
    (3
    )
    
    $
    3
    
    
    $
    
    
    
    $
    
 39




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##### Table of Contents



Marketing andTrading TotalYears
    
    fairSource of Fair Value
    
    2004
    
    2005
    
    thereafter
    
    valuePrices actively quoted
    
    $
    (3
    )
    
    $
    
    
    
    $
    
    
    
    $
    (3
    )Prices provided by
other external sources
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    2Prices based on models
and other valuation
methods
    
    
    (2
    )
    
    
    (1
    )
    
    
    
    
    
    
    (3
    )Total by maturity
    
    $
    (3
    )
    
    $
    (1
    )
    
    $
    
    
    
    $
    (4
    )
 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 Balance Sheets at December 31, 2003 (dollars in
millions): December 31, 2003Gain (Loss)Commodity
    
    Price Up 10%
    
    Price Down 10%Mark-to-market changes
reported in earnings (a):Electricity
    
    $
    (2
    )
    
    $
    2Mark-to-market changes
reported in OCI (b):Electricity
    
    
    5
    
    
    
    (5
    )Natural gas
    
    
    31
    
    
    
    (30
    )Total
    
    $
    34
    
    
    $
    (33
    )
  (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. See Note 1, Mark-to-Market Accounting for a discussion of
our credit valuation adjustment policy. See Note 16 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. 40




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##### Table of Contents



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 we 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;
    
    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;
    
    conservation programs; and
    
    other uncertainties, all of which are difficult to predict
and many of which are beyond our control. 41




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##### Table of Contents



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. 42




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##### Table of Contents



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS Managements Report on Internal Control Over Financial Reporting
    44Independent Accountants Report
    45Independent Auditors Report
    46Statements of Income for 2003, 2002 and 2001
    47Balance Sheets as of December 31, 2003 and 2002
    48Statements of Cash Flows for 2003, 2002 and 2001
    50Statements of Changes in Common Stock Equity for 2003, 2002 and 2001
    51Notes to Financial Statements
    52Financial Statement Schedule for 2003, 2002 and 2001 Schedule II  Reserve for
Uncollectibles for 2003, 2002 and 2001
    104
 See Note 12 for the selected quarterly financial data required to be presented
in this Item. 43




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##### Table of Contents



MANAGEMENTS REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING Management at APS 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 Arizona Public
Service Company  (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 Frameworkissued
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 44




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##### Table of Contents



INDEPENDENT ACCOUNTANTS REPORT Board of Directors and Stockholder
Arizona Public Service Company
Phoenix, Arizona We have examined the
accompanying managements assertion that Arizona Public Service Company (the Company) maintained effective
internal control over financial reporting as of December 31, 2003, based on the
criteria established in Internal Control-Integrated Frameworkissued 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 Frameworkissued 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 45




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##### Table of Contents



INDEPENDENT AUDITORS REPORT Board of Directors and Stockholder
Arizona Public Service Company
Phoenix, Arizona We have audited the accompanying balance sheets of Arizona Public Service
Company (the Company) as of December 31, 2003 and 2002 and the related
statements of income, changes in common stock equity and cash flows for each of
the three years in the period ended December 31, 2003. Our audits also
included the financial statement schedule listed in the Index. These financial
statements and the 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 financial statements present fairly, in all material
respects, the financial position of Arizona Public Service Company at December
31, 2003 and 2002, and the results of its operations and its 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 financial statements taken as a whole, presents fairly in
all material respects the information set forth therein. As discussed in Note 16 to
the financial statements, in 2003 Arizona Public Service 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 16 to
the financial statements, in 2001 Arizona Public Service 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 46




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##### Table of Contents



ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF INCOME Year Ended December 31,2003
    
    2002
    
    2001(dollars in thousands)Electric Operating Revenues:Regulated electricity segment
    
    $
    1,999,390
    
    
    $
    1,902,112
    
    
    $
    1,984,305Marketing and trading segment
    
    
    105,541
    
    
    
    34,054
    
    
    
    367,793Total
    
    
    2,104,931
    
    
    
    1,936,166
    
    
    
    2,352,098Purchased Power and Fuel Costs:Regulated electricity segment
    
    
    606,251
    
    
    
    438,141
    
    
    
    649,405Marketing and trading segment
    
    
    97,180
    
    
    
    32,662
    
    
    
    132,544Total
    
    
    703,431
    
    
    
    470,803
    
    
    
    781,949Operating Revenues less Purchased
Power and Fuel Costs
    
    
    1,401,500
    
    
    
    1,465,363
    
    
    
    1,570,149Other Operating Expenses:Operations and maintenance
    
    
    513,604
    
    
    
    495,845
    
    
    
    465,561Depreciation and amortization
    
    
    389,240
    
    
    
    399,640
    
    
    
    420,893Income taxes (Note 4)
    
    
    91,646
    
    
    
    132,953
    
    
    
    183,640Other taxes
    
    
    108,852
    
    
    
    107,925
    
    
    
    101,077Total
    
    
    1,103,342
    
    
    
    1,136,363
    
    
    
    1,171,171Operating Income
    
    
    298,158
    
    
    
    329,000
    
    
    
    398,978Other Income (Deductions):Income taxes (Note 4)
    
    
    4,792
    
    
    
    6,148
    
    
    
    504Allowance for equity funds used
during construction
    
    
    14,240
    
    
    
    
    
    
    
    Other income (Note 17)
    
    
    20,277
    
    
    
    5,149
    
    
    
    20,207Other expense (Note 17)
    
    
    (12,962
    )
    
    
    (19,338
    )
    
    
    (20,790
    )Total
    
    
    26,347
    
    
    
    (8,041
    )
    
    
    (79
    )Interest Deductions:Interest on long-term debt
    
    
    142,706
    
    
    
    128,462
    
    
    
    126,118Interest on short-term borrowings
    
    
    4,904
    
    
    
    5,416
    
    
    
    4,407Debt discount, premium and expense
    
    
    3,337
    
    
    
    2,888
    
    
    
    2,650Capitalized interest
    
    
    (7,379
    )
    
    
    (15,150
    )
    
    
    (14,964
    )Total
    
    
    143,568
    
    
    
    121,616
    
    
    
    118,211Income Before Accounting Change
    
    
    180,937
    
    
    
    199,343
    
    
    
    280,688Cumulative Effect of Change in
Accounting for Derivatives 
net of income taxes of $9,892
    
    
    
    
    
    
    
    
    
    
    (15,201
    )Net Income
    
    $
    180,937
    
    
    $
    199,343
    
    
    $
    265,487
 See Notes to Financial Statements. 47




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##### Table of Contents



ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
ASSETS December 31,2003
    
    2002(dollars in thousands)Utility Plant (Notes 1, 6, 8, 9 and 11)Electric plants in service and held for future use
    
    $
    8,826,033
    
    
    $
    8,299,131Less accumulated depreciation and amortization
    
    
    3,089,645
    
    
    
    2,885,798Total
    
    
    5,736,388
    
    
    
    5,413,333Construction work in progress
    
    
    187,478
    
    
    
    329,089Intangible assets, net of accumulated amortization
    
    
    94,181
    
    
    
    93,259Nuclear fuel, net of accumulated amortization of
$58,053 and $59,163
    
    
    52,011
    
    
    
    51,124Utility Plant  net
    
    
    6,070,058
    
    
    
    5,886,805Investments and Other AssetsNotes Receivable from Pinnacle West Energy
(Notes 1 and 3)
    
    
    497,865
    
    
    
    Decommissioning trust accounts (Note 11)
    
    
    240,645
    
    
    
    194,440Assets from risk management and trading activities 
long-term
    
    
    18,001
    
    
    
    31,622Other assets
    
    
    64,119
    
    
    
    57,380Total Investments and Other Assets
    
    
    820,630
    
    
    
    283,442Current Assets:Cash and cash equivalents
    
    
    112,002
    
    
    
    42,549Accounts receivable:Service customers
    
    
    190,884
    
    
    
    136,945Other (Note 1)
    
    
    67,540
    
    
    
    202,597Allowance for doubtful accounts
    
    
    (3,743
    )
    
    
    (1,341
    )Accrued utility revenues
    
    
    71,501
    
    
    
    72,915Materials and supplies (at average cost)
    
    
    80,682
    
    
    
    79,985Fossil fuel (at average cost)
    
    
    28,360
    
    
    
    28,185Deferred income taxes (Note 4)
    
    
    
    
    
    
    4,094Assets from risk management and trading activities
    
    
    52,448
    
    
    
    39,616Other
    
    
    6,969
    
    
    
    7,945Total Current Assets
    
    
    606,643
    
    
    
    613,490Deferred Debits:Regulatory assets (Notes 1 and 3)
    
    
    164,804
    
    
    
    241,045Unamortized debt issue costs
    
    
    19,797
    
    
    
    16,696Other
    
    
    73,056
    
    
    
    80,760Total Deferred Debits
    
    
    257,657
    
    
    
    338,501Total Assets
    
    $
    7,754,988
    
    
    $
    7,122,238
 See Notes to Financial Statements. 48




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##### Table of Contents



ARIZONA PUBLIC SERVICE COMPANY
BALANCE SHEETS
LIABILITIES AND EQUITY December 31,2003
    
    2002(dollars in thousands)Capitalization:Common stock
    
    $
    178,162
    
    
    $
    178,162Additional paid-in capital
    
    
    1,246,804
    
    
    
    1,246,804Retained earnings
    
    
    830,569
    
    
    
    819,632Accumulated other comprehensive income (loss):Minimum pension liability adjustment
    
    
    (57,158
    )
    
    
    (61,487
    )Derivative instruments
    
    
    5,253
    
    
    
    (23,799
    )Common stock equity
    
    
    2,203,630
    
    
    
    2,159,312Long-term debt less current maturities (Note 6)
    
    
    2,415,946
    
    
    
    2,217,340Total Capitalization
    
    
    4,619,576
    
    
    
    4,376,652Current Liabilities:Current maturities of long-term debt (Note 6)
    
    
    206,727
    
    
    
    3,503Accounts payable
    
    
    131,383
    
    
    
    118,133Accrued taxes
    
    
    90,474
    
    
    
    82,557Accrued interest
    
    
    42,702
    
    
    
    42,608Customer deposits
    
    
    45,481
    
    
    
    39,865Deferred income taxes (Note 4)
    
    
    631
    
    
    
    Liabilities from risk management and trading
activities
    
    
    58,138
    
    
    
    59,773Other
    
    
    60,008
    
    
    
    51,820Total Current Liabilities
    
    
    635,544
    
    
    
    398,259Deferred Credits and Other:Deferred income taxes (Note 4)
    
    
    1,248,397
    
    
    
    1,225,552Regulatory Liabilities (Notes 1, 3 and 4)
    
    
    510,423
    
    
    
    26,264Liability for asset retirements and removals (Note 11)
    
    
    234,440
    
    
    
    600,431Pension liability (Note 7)
    
    
    160,639
    
    
    
    156,442Unamortized gain  sale of utility plant (Note 8)
    
    
    54,909
    
    
    
    59,484Customer advances for construction
    
    
    52,783
    
    
    
    45,513Liabilities from risk management and trading
activities
    
    
    4,502
    
    
    
    36,678Other
    
    
    233,775
    
    
    
    196,963Total Deferred Credits and Other
    
    
    2,499,868
    
    
    
    2,347,327Commitments and Contingencies (Note 10)Total Liabilities and Equity
    
    $
    7,754,988
    
    
    $
    7,122,238
 See Notes to Financial Statements. 49




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ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CASH FLOWS Year Ended December 31,2003
    
    2002
    
    2001(dollars in thousands)Cash Flows from Operating Activities:Net income
    
    $
    180,937
    
    
    $
    199,343
    
    
    $
    265,487Items not requiring cash:Depreciation and amortization
    
    
    389,240
    
    
    
    399,640
    
    
    
    420,893Nuclear fuel amortization
    
    
    28,757
    
    
    
    31,185
    
    
    
    28,362Allowance for equity funds used during
construction
    
    
    (14,240
    )
    
    
    
    
    
    
    Deferred income taxes
    
    
    (1,087
    )
    
    
    206,767
    
    
    
    (26,516
    )Change in derivative mark-to-market
valuations
    
    
    2,339
    
    
    
    2,957
    
    
    
    (100,030
    )Cumulative effect of change in
accounting  net of income taxes
    
    
    
    
    
    
    
    
    
    
    15,201Changes in certain current assets and
liabilities:Accounts receivable
    
    
    83,692
    
    
    
    (102,450
    )
    
    
    302,283Materials, supplies and fossil fuel
    
    
    (872
    )
    
    
    68
    
    
    
    (16,867
    )Other current assets
    
    
    2,390
    
    
    
    5,443
    
    
    
    (5,385
    )Accounts payable
    
    
    17,961
    
    
    
    15,372
    
    
    
    (190,141
    )Accrued taxes
    
    
    7,917
    
    
    
    (25,038
    )
    
    
    1,080Accrued interest
    
    
    94
    
    
    
    1,565
    
    
    
    1,555Other current liabilities
    
    
    13,804
    
    
    
    44,224
    
    
    
    (58,361
    )Increase in regulatory assets
    
    
    (11,697
    )
    
    
    (11,029
    )
    
    
    (17,516
    )Change in risk management trading  assets
    
    
    12,551
    
    
    
    (22,570
    )
    
    
    10,730Change in customer advances
    
    
    7,270
    
    
    
    (23,780
    )
    
    
    28,599Change in pension liability
    
    
    17,395
    
    
    
    7,016
    
    
    
    (35,244
    )Change in other long-term assets
    
    
    (14,623
    )
    
    
    (24,502
    )
    
    
    (13,967
    )Change in other long-term liabilities
    
    
    55,296
    
    
    
    301
    
    
    
    (5,088
    )Net cash flow provided by operating
activities
    
    
    777,124
    
    
    
    704,512
    
    
    
    605,075Cash Flows from Investing Activities:Capital expenditures
    
    
    (426,260
    )
    
    
    (490,156
    )
    
    
    (465,360
    )Capitalized interest
    
    
    (7,379
    )
    
    
    (15,150
    )
    
    
    (14,964
    )Loan to Pinnacle West Energy
    
    
    (497,865
    )
    
    
    
    
    
    
    Other
    
    
    (8,296
    )
    
    
    44,918
    
    
    
    (41,926
    )Net cash flow used for investing activities
    
    
    (939,800
    )
    
    
    (460,388
    )
    
    
    (522,250
    )Cash Flows from Financing Activities:Issuance of long-term debt
    
    
    491,654
    
    
    
    459,926
    
    
    
    396,072Short-term borrowings
    
    
    
    
    
    
    (171,162
    )
    
    
    89,062Dividends paid on common stock
    
    
    (170,000
    )
    
    
    (170,000
    )
    
    
    (170,000
    )Repayment and reacquisition of long-term debt
    
    
    (89,525
    )
    
    
    (337,160
    )
    
    
    (383,747
    )Net cash flow provided by (used for)
financing
activities
    
    
    232,129
    
    
    
    (218,396
    )
    
    
    (68,613
    )Net increase in cash and cash equivalents
    
    
    69,453
    
    
    
    25,728
    
    
    
    14,212Cash and cash equivalents at beginning of year
    
    
    42,549
    
    
    
    16,821
    
    
    
    2,609Cash and cash equivalents at end of year
    
    $
    112,002
    
    
    $
    42,549
    
    
    $
    16,821Supplemental disclosure of cash flow information:Cash paid during the year for:Income taxes paid/(refunded)
    
    $
    74,523
    
    
    $
    (54,283
    )
    
    $
    212,989Interest (excluding capitalized interest)
    
    $
    140,010
    
    
    $
    117,081
    
    
    $
    114,094
 See Notes to Financial Statements. 50




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ARIZONA PUBLIC SERVICE COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY Years Ended December 31,2003
    
    2002
    
    2001(dollars in thousands)COMMON STOCK
    
    $
    178,162
    
    
    $
    178,162
    
    
    $
    178,162ADDITIONAL PAID-IN CAPITAL
    
    
    1,246,804
    
    
    
    1,246,804
    
    
    
    1,246,804RETAINED EARNINGSBalance at beginning of year
    
    
    819,632
    
    
    
    790,289
    
    
    
    694,802Net income
    
    
    180,937
    
    
    
    199,343
    
    
    
    265,487Common stock dividends
    
    
    (170,000
    )
    
    
    (170,000
    )
    
    
    (170,000
    )Balance at end of year
    
    
    830,569
    
    
    
    819,632
    
    
    
    790,289ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS)Balance at beginning of year
    
    
    (85,286
    )
    
    
    (64,565
    )
    
    
    Minimum pension liability adjustment, net of
tax of $3,105, $39,696 and $634
    
    
    4,329
    
    
    
    (60,521
    )
    
    
    (966
    )Cumulative effect of a change in accounting
for derivatives, net of tax of $47,404
    
    
    
    
    
    
    
    
    
    
    72,274Unrealized gain/(loss) on derivative
instruments, net of tax of $15,824, $25,426
and $71,720
    
    
    24,135
    
    
    
    38,764
    
    
    
    (109,346
    )Reclassification of realized (gain)/loss to
income, net of tax of $3,207, $679 and
$17,399
    
    
    4,917
    
    
    
    1,036
    
    
    
    (26,527
    )Balance at end of year
    
    
    (51,905
    )
    
    
    (85,286
    )
    
    
    (64,565
    )TOTAL COMMON STOCK EQUITY
    
    $
    2,203,630
    
    
    $
    2,159,312
    
    
    $
    2,150,690COMPREHENSIVE INCOMENet income
    
    $
    180,937
    
    
    $
    199,343
    
    
    $
    265,487Other comprehensive income (loss)
    
    
    33,381
    
    
    
    (20,721
    )
    
    
    (64,565
    )Comprehensive income
    
    $
    214,318
    
    
    $
    178,622
    
    
    $
    200,922
 See Notes to Financial Statements. 51




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS  1.
    
    Summary of Significant Accounting Policies Nature of Operations We are 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. We also generate, sell and deliver
electricity to wholesale customers in the western United States. In early
2003, the marketing and trading division was moved from Pinnacle West to us 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 our generating assets to Pinnacle West Energy.
See Note 3 for a discussion of the Track A Order. Our marketing and trading
division sells, in the wholesale market, our and Pinnacle West Energys
generation output that is not needed for our Native Load, which includes loads
for retail customers and cost-of-service wholesale customers. We do not
distribute any products. Pinnacle West owns all of our outstanding stock. During 2001, we transferred most of our marketing and trading activities
to Pinnacle West. Thus, we did not have any significant marketing and trading
activity in 2002. Conversely, in the first quarter of 2003, Pinnacle West
moved the marketing and trading division back to us for future marketing and
trading activities (existing wholesale contracts remained at Pinnacle West).
This latest move was a result of the ACCs Track A Order prohibiting the
previously-required transfer of our generating assets to Pinnacle West Energy. From time to time, we enter into transactions with Pinnacle West or
Pinnacle Wests subsidiaries. The following table summarizes the amounts
included in the Statements of Income and Balance Sheets related to transactions
with affiliated companies (dollars in millions): For the year endedDecember 31,2003
    
    2002
    
    2001Electric operating revenues:Pinnacle West  marketing and trading
    
    $
    12
    
    
    $
    85
    
    
    $
    50Pinnacle West Energy
    
    
    1
    
    
    
    
    
    
    
    Total
    
    $
    13
    
    
    $
    85
    
    
    $
    50Purchased power and fuel costs:Pinnacle West  marketing and trading
    
    $
    
    
    
    $
    135
    
    
    $
    50Pinnacle West Energy
    
    
    70
    
    
    
    
    
    
    
    14Total
    
    $
    70
    
    
    $
    135
    
    
    $
    64Other:Pinnacle West Energy:Lease expense
    
    $
    10
    
    
    $
    
    
    
    $
    Interest income
    
    $
    12
    
    
    $
    
    
    
    $
    
 52




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS As of December 31,2003
    
    2002Net intercompany receivables/(payables):Pinnacle West Energy (a)
    
    $
    463
    
    
    $
    (1
    )Pinnacle West  marketing and trading
    
    
    16
    
    
    
    135APS Energy Services
    
    
    10
    
    
    
    Pinnacle West
    
    
    (8
    )
    
    
    (1
    )Total
    
    $
    481
    
    
    $
    133
  (a)
    
    The net intercompany receivable as of December 31, 2003
related to Pinnacle West Energy primarily consists of the $500
million of debt we issued to Pinnacle West Energy pursuant to the
Financing Order (see ACC Financing Order in Note 3). Electric revenues include sales of electricity to affiliated companies at
contract prices. Purchased power includes purchases of electricity from
affiliated companies at contract prices. The Company purchases electricity
from and sells electricity to APS Energy Services; however, these transactions
are settled net and reported net in accordance with EITF 03-11, Reporting
Realized Gains and Losses on Derivative Instruments That Are Subject to FASB
Statement No. 133 and Not Held for Trading Purposes As Defined in Issue No.
2-3. See Note 16 for more information related to EITF 03-11. Intercompany
receivables primarily include the amounts related to the loan we made to
Pinnacle West Energy and intercompany sales of electricity. Intercompany
payables primarily include amounts related to the intercompany purchases of
electricity. Intercompany receivables and payables are generally settled on a
current basis in cash. 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. 53




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS We account for our derivative contracts in accordance with
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities.
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 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. The impact of this guidance was
immaterial to our financial statements. 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 16 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 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. 54




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS For non-exchange traded contracts, we calculate fair market value based on
the average of the bid and offer price, and we discount to reflect net present
value. We maintain certain valuation adjustments for a number of risks
associated with the valuation of future commitments. These include valuation
adjustments for liquidity and credit risks based on the financial condition of
counterparties. The liquidity valuation adjustment represents the cost that
would be incurred if all unmatched positions were closed-out or hedged. The credit valuation adjustment represents estimated credit losses on our
overall exposure to counterparties, taking into account netting arrangements,
expected default experience for the credit rating of the counterparties and the
overall diversification of the portfolio. Counterparties in the portfolio
consist principally of major energy companies, municipalities 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 16 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 We are 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): 55




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS 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): December 31,2003
    
    2002Remaining balance recoverable under the 1999
Settlement Agreement (a)
    
    $
    18
    
    
    $
    104Spent nuclear fuel storage (Note 10)
    
    
    49
    
    
    
    46Electric industry restructuring transition costs (Note 3)
    
    
    46
    
    
    
    40Deferred compensation
    
    
    24
    
    
    
    23Contributions in aid of construction
    
    
    11
    
    
    
    10Loss on reacquired debt (b)
    
    
    12
    
    
    
    9Other
    
    
    5
    
    
    
    9Total 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
    
    2002Removal costs (a)
    
    $
    480
    
    
    $
    Deferred gains on utility property
    
    
    20
    
    
    
    20Deferred interest income (b)
    
    
    8
    
    
    
    Other
    
    
    2
    
    
    
    6Total regulatory liabilities
    
    $
    510
    
    
    $
    26
  (a)
    
    See Note 11 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 56




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS June 30, 2004. Amortization of the deferrals is included in depreciation
and amortization expense in the 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:  
    
    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 11). 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  25 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. 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. 57




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS 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. AFUDC was calculated by using a composite rate of 8.55% for 2003. We
compound AFUDC monthly and cease to accrue AFUDC when construction work is
completed and the property is placed in service. In 2003, we returned to the AFUDC method of capitalizing interest and
equity costs associated with construction projects in a regulated utility.
This is consistent with our returning to a vertically-integrated utility, as
evidenced by our recent general rate case filing, which includes the request
for rate recognition of generation assets. Previously, we 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 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 Statements of Income on a net basis. We
adopted EITF 03-11 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 58




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS and fuel costs in 2003, 2002 and 2001, but this did not impact our
financial condition, net income or cash flows (see Note 16 for additional
information). 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 We charge 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. We divide the cost of the fuel by the estimated number
of thermal units it expects to produce with that fuel. We then multiply that
rate by the number of thermal units produced within the current period. This
calculation determines the current period nuclear fuel expense. We also charge 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 us $0.001 per kWh of nuclear generation. See Note
10 for information about spent nuclear fuel disposal and Note 11 for
information on nuclear decommissioning costs. Income Taxes Income taxes are provided using the asset and liability approach
prescribed by SFAS No. 109, Accounting for Income Taxes. Pinnacle West files
the federal income tax return on a consolidated basis and files the 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 us as though we filed a separate income tax return. Any
difference between that method and the consolidated (and unitary) income tax
liability is attributed to Pinnacle West. See Note 4. Reacquired Debt Costs We defer the
gains and losses incurred upon early retirement and are seeking recovery in the
general rate case (see Note 3). In accordance with the 1999 Settlement
Agreement, we are 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
Statements of Income. Stock-Based Compensation Pinnacle West offers stock-based compensation plans for officers and key
employees of our company. 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 59




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS method allowed in Accounting Principles Board Opinion (APB) No. 25, Accounting
for Stock Issued to Employees. The following chart compares our net income and stock compensation expense
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): 2003
    
    2002
    
    2001Net income, as reported
    
    $
    180,937
    
    
    $
    199,343
    
    
    $
    265,487Add: Stock compensation
expense included in reported
net income (net of tax):
    
    
    751
    
    
    
    200
    
    
    
    Deduct: Total stock
compensation expense
determined under fair
value method (net of tax):
    
    
    1,740
    
    
    
    1,162
    
    
    
    1,582Pro forma net income
    
    $
    179,948
    
    
    $
    198,381
    
    
    $
    263,905
 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
    
    2001Risk-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 14 for further discussion about our stock compensation plans. Intangible Assets We have no goodwill recorded and have separately disclosed other
intangible assets on our 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 $215 million at December 31,
2003 and $193 million at December 31, 2002. The related accumulated
amortization was $121 million at December 31, 2003 and $100 million at December
31, 2002. Amortization expense was $21 million in 2003, $19 million in 2002
and $21 million in 2001. Estimated amortization expense on existing intangible
assets over the next five years is $24 million in 2004, $23 million in 2005,
$21 million in 2006, $17 60




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS million in 2007 and $9 million in 2008. At December 31, 2003, the
weighted average amortization period for our intangible assets is 7 years.  2.
    
    Accounting Matters See the following Notes for information about new accounting standards and
other accounting matters:  
    
    Note 7 for amended disclosure requirements (SFAS No. 132) on
retirement plans and other benefits;
    
    Note 11 for a new accounting standard (SFAS No. 143) on asset
retirement obligations;
    
    Notes 14 for a new accounting standard (SFAS No. 148) related
to stock-based compensation;
    
    Note 16 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 18 for a new FASB interpretation (FIN No. 46R) related to VIEs; and
    
    Note 19 for a new FASB interpretation (FIN No. 45) on guarantees.  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:  
    
    We have 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; 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 61




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS  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 us 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 we are
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 our cost of service for ACC-regulated services
resulting from federal, tribal, state or local laws; regulatory
requirements; or judicial decisions, actions or orders.
    
    We 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 General Rate Case and Retail Rate
Adjustment Mechanisms below.
    
    Our 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.
We opened our 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 our service area in 1999
and 2000, there are currently no active retail competitors providing
unbundled energy or other utility services to our customers. As a
result, we cannot predict when, and the extent to which, additional
competitors will re-enter our service territory.
    
    Prior to the 1999 Settlement Agreement, we were recovering
substantially all of our regulatory assets through July 1, 2004,
pursuant to a 1996 regulatory agreement. In addition, the 1999
Settlement Agreement states that we had demonstrated that our
allowable stranded costs, after mitigation and exclusive of
regulatory assets, are at least $533 million net present value (in
1999 dollars). The 1999 Settlement Agreement also states that we
will not be allowed to recover $183 million net present value (in
1999 dollars) of the $533 million. The 1999 Settlement Agreement 62




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS  provides that we 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
General Rate Case and Retail Rate Adjustment Mechanisms, we are
seeking to recover amounts written off by us as a result of the
1999 Settlement Agreement.
    
    The 1999 Settlement Agreement required us to form, or cause
to be formed, a separate corporate affiliate or affiliates and
transfer to such affiliate(s) our competitive electric assets and
services no later than December 31, 2002. The 1999 Settlement
Agreement provided that we would be allowed to defer and later
collect, beginning July 1, 2004, 67% of our 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 us from transferring our generation assets. We are
seeking to recover all costs incurred by us in preparation for the
previously anticipated transfer of generation assets to Pinnacle
West Energy. See 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 us.
    
    Effective January 1, 2001, retail access became available to
all of our 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, we received a waiver to allow
transfer of our 63




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS  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 us
to transfer our 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, we 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 our
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, we are, 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 us 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 our 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 our current
retail rates. In the event of shortfalls due to unforeseen increases in load
demand or generation or transmission outages, we may need to purchase
additional supplemental power in the wholesale spot market. Unless we are able
to obtain an adjustment of our rates under the emergency provisions of the 1999
Settlement Agreement, there can be no assurance that we would be able to fully
recover the costs of this power. See 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. 64




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS Track A Order On September 10, 2002, the ACC issued the Track A Order, in which the ACC,
among other things:  
    
    reversed its decision, as reflected in the Rules, to require
us to transfer our generation assets either to an unrelated third
party or to a separate corporate affiliate; and  
    
    unilaterally modified the 1999 Settlement Agreement, which
authorized our transfer of our generating assets, and directed us to
cancel our activities to transfer our generation assets to Pinnacle
West Energy. On November 15, 2002, we 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, we and the ACC staff agreed to principles for
resolving certain issues raised by us in our appeals of the
Track A Order. We
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:  
    
    We and the ACC staff agreed that it would be appropriate for
the ACC to consider the following matters in our general rate case,
which was filed on June 27, 2003:  
    
    the generating assets to be included in our rate
base, including the question of whether the PWEC Dedicated
Assets should be included in our rate base;  
    
    the appropriate treatment of the $234 million
pretax asset write-off agreed to by us as part of the 1999
Settlement Agreement; and  
    
    the appropriate treatment of costs incurred by us
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 our request to provide $500 million of
financing or credit support to Pinnacle West Energy or the Company,
with appropriate conditions, our 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, our appeals of the
Track A Order are limited to the issues described in the preceding
bullet points. On August 27, 2003, we, 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 65




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS 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 us to
solicit bids for certain estimated amounts of capacity and energy for periods
beginning July 1, 2003. For 2003, we were required to solicit competitive bids
for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or
approximately 20% of our total retail energy requirements. The bid amounts are
expected to increase in 2004 and 2005 based largely on growth in our retail
load and our retail energy sales. The Track B Order also confirmed that it was
not intended to change the current rate base status of our existing assets. The order recognizes our 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 us and any
affiliate of ours participating in the competitive solicitation, requires us to
treat bidders in a non-discriminatory manner and requires us to file a protocol
regarding short-term and emergency procurements. The order permits the
provision by us 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 our confidential bidding information that is
not available to other bidders. The order directs us 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 us to prepare a report evaluating
environmental issues relating to the procurement, and a series of workshops on
environmental risk management will be commenced thereafter. We issued requests for proposals in March 2003 and, by May 6, 2003, we
entered into contracts to meet all or a portion of our 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 us to
lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million
of Pinnacle West Energy debt, or a 66




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS combination of both, not to exceed $500 million in the aggregate (the APS
Loan), subject to the following principal conditions:  
    
    any debt issued by us pursuant to the order must be unsecured;
    
    the APS Loan must be callable and secured by the PWEC Dedicated Assets;
    
    the APS Loan must bear interest at a rate equal to 264 basis
points above the interest rate on our 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 our cost of capital as a result
of the transaction (such as from a decline in bond rating) will be
excluded from future rate cases;
    
    we must maintain a common equity ratio of at least forty
percent and may not pay common dividends if such payment would
reduce our 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 us and our 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 67




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS



| |   |  | (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, we submitted our 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, we 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 Pinnacle West to fund the
repayment of a portion of the debt incurred to finance the construction of the
PWEC Dedicated Assets (see Note 6).

On November 22, 2002, the ACC issued an order approving our request to
permit us 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.

General Rate Case and Retail Rate Adjustment Mechanisms

As noted above, on June 27, 2003, we filed a general rate case with the
ACC and requested a $175.1 million, or 9.8%, increase in our annual retail
electricity revenues, to become effective July 1, 2004. In this rate case, we
updated our cost of service and rate design.

Major Components of the RequestThe 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 our cost of service, cost allocation and rate design;                                                                        
|
| |  |  | obtaining rate recognition of the PWEC Dedicated Assets;                                                                                            
|
| |  |  | recovering $234 million written off by us as a result of the
1999 Settlement Agreement; and                                                         
|
| |  |  | recovering restructuring and compliance costs associated with
the ACCs Rules.                                                                      

68



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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

Requested Rate IncreaseThe 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 YearThe filing is based on an adjusted historical test year ended
December 31, 2002.

Cost of CapitalThe 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 BaseThe 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 us 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-OffThe request includes
recovery, over a fifteen year period, of the write-off of $234 million pretax
of regulatory assets by us as a result of the 1999 Settlement Agreement. See
1999 Settlement Agreement above.

Estimated TimelineWe have 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 us 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.

69



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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

On November 4, 2003, the ACC approved the issuance of an order which
authorizes a rate adjustment mechanism allowing us 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.

TestimonyAs 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;                                                                                                                                                                
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | 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 RecommendationsIn its filed testimony, the ACC staff
recommended, among other things, that the ACC:



| |  |  | decrease our 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 our
rate base;                                                                                                  
|
| |  |  | not allow us 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 our rate case requests are supported by, among other
things, our demonstrated need for the PWEC Dedicated Assets; our need to
attract capital at reasonable rates of return to support the required capital
investment to ensure continued customer reliability in our 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 we and our
affiliates had violated the spirit, if not the letter, of the Rules, the Code
of Conduct and the 1999 Settlement Agreement.

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RUCO RecommendationsIn its filed testimony, RUCO recommended, among
other things, that the ACC:



| |  |  | decrease our 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 our
rate base;                                                                                             
|
| |  |  | not allow us 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.                                                                                            

We believe that our rate request is necessary to ensure our continued
ability to reliably serve one of the fastest growing regions in the country and view any ultimate
decision that would deny recovery of the Companys investment in the PWEC Dedicated Assets as
constituting a regulatory taking.  We will vigorously oppose the recommendations of the ACC
staff, RUCO, and other parties offering similar recommendations.

Request for Proposals

In early December 2003, we 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, us to file a summary
of the proposals with the ACC. On January 27, 2004, we filed a summary of the
proposals with the ACC. We are 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 our service area in 1999 and
2000, there are currently no active retail competitors providing unbundled
energy or other utility services to our customers. As a result, we cannot
predict when, and the extent to which, additional competitors will re-enter our
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.

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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS



|4. |  | Income Taxes
|-- |  | ------------

We are included in Pinnacle Wests consolidated tax return. However, when
Pinnacle West allocates income taxes to us, it does so based on our taxable
income or loss alone.

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.

We have recorded a regulatory asset related to income taxes on our 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. We amortize this amount as the differences reverse. In
accordance with ACC settlement agreements, we are continuing to accelerate
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 the
Statements of Income.

As a result of a change in IRS guidance, we claimed a tax deduction
related to a tax accounting method change on the 2001 Pinnacle West 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 the 2001 Pinnacle
West federal consolidated income tax return. In 2003, we resolved certain
prior-year issues with the taxing authorities and recorded a $13 million tax
benefit associated with tax credits and other reductions to income tax expense.

The components of income tax expense for income before accounting change
are as follows (dollars in thousands):

|                         |         |   |                         |        |      |   |         |         |   |   |         |         | 
|------------------------ | ------- | - | ----------------------- | ------ | ---- | - | ------- | ------- | - | - | ------- | ------- | 
|                         |         |   | Year Ended December 31,
|                         |         |   |                        
|                         |         |   | 2003                    |        | 2002 |   | 2001   
|                         |         |   |                         |        |      |   |        
|Current:                 |         |   |                         |        |      |   |         |         |   |   |         |        
|                         | Federal |   | $                       | 75,087 |      |   | $       | (61,962 | ) |   | $       | 174,251 | 
|                         | State   |   |                         | 12,854 |      |   |         | (18,000 | ) |   |         | 35,401  | 
|                         |         |   |                         |        |      |   |         |         |   |   |         |         | 
|Total current            |         |   | 87,941                  |        |      |   | (79,962 | )       |   |   | 209,652 |        
|Deferred                 |         |   | (1,087                  | )      |      |   | 206,767 |         |   |   | (26,516 | )      
|                         |         |   |                         |        |      |   |         |         |   |   |         |         | 
|Total income tax expense |         | $ | 86,854                  |        |      | $ | 126,805 |         |   | $ | 183,136 |        
|                         |         |   |                         |        |      |   |         |         |   |   |         |         | 

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

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

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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

|                                                      |                                                                           |   |                         |         |      |   |         |        |   |   |         |        | 
|----------------------------------------------------- | ------------------------------------------------------------------------- | - | ----------------------- | ------- | ---- | - | ------- | ------ | - | - | ------- | ------ | 
|                                                      |                                                                           |   | Year Ended December 31,
|                                                      |                                                                           |   |                        
|                                                      |                                                                           |   | 2003                    |         | 2002 |   | 2001   
|                                                      |                                                                           |   |                         |         |      |   |        
|Federal income tax expense at 35%
statutory rate      |                                                                           | $ | 93,727                  |         |      | $ | 114,152 |        |   | $ | 162,338 |       
|Increases (reductions) in tax expense
resulting from: |                                                                           |   |                         |         |      |   |         |        |   |   |         |       
|                                                      | State income tax net of
federal income tax benefit                        |   |                         | 11,889  |      |   |         | 15,036 |   |   |         | 20,563 | 
|                                                      | Credits and favorable
adjustments related to prior
years resolved in 2003 |   |                         | (12,944 | )    |   |         |       |   |   |         |       | 
|                                                      | Allowance for equity funds
used during construction (see
Note 1)          |   |                         | (5,616  | )    |   |         |       |   |   |         |       | 
|                                                      | Other                                                                     |   |                         | (202    | )    |   |         | (2,383 | ) |   |         | 235    | 
|                                                      |                                                                           |   |                         |         |      |   |         |        |   |   |         |       
|Income tax expense                                    |                                                                           | $ | 86,854                  |         |      | $ | 126,805 |        |   | $ | 183,136 |       
|                                                      |                                                                           |   |                         |         |      |   |         |        |   |   |         |       

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

|                                        |  |              |            |      |  |   |            |  
|--------------------------------------- |  | ------------ | ---------- | ---- |  | - | ---------- | -
|                                        |  | December 31,
|                                        |  |             
|                                        |  | 2003         |            | 2002
|                                        |  |              |            |     
|Current asset/(liability)               |  | $            | (631       | )    |  | $ | 4,094      |  
|Long term liability                     |  |              | (1,248,397 | )    |  |   | (1,225,552 | )
|                                        |  |              |            |      |  |   |            |  
|Accumulated deferred income taxes  net |  | $            | (1,249,028 | )    |  | $ | (1,221,458 | )
|                                        |  |              |            |      |  |   |            |  

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

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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS

|                                        |                                                   |                                    |            |              |        |      |            |            |        | 
|--------------------------------------- | ------------------------------------------------- | ---------------------------------- | ---------- | ------------ | ------ | ---- | ---------- | ---------- | ------ | 
|                                        |                                                   |                                    |            | December 31,
|                                        |                                                   |                                    |            |             
|                                        |                                                   |                                    |            | 2003         |        | 2002
|                                        |                                                   |                                    |            |              |        |     
|DEFERRED TAX ASSETS                     |                                                   |                                    |            |              |        |      |            |           
|                                        | Pension liability                                 |                                    | $          | 63,356       |        |      | $          | 61,966     |       
|                                        | Regulatory liabilities:                           |                                    |            |              |        |      |            |            |       
|                                        |                                                   | Federal excess deferred income tax |            |              | 18,936 |      |            |            | 20,887 | 
|                                        |                                                   | Other                              |            |              | 33,542 |      |            |            | 9,818  | 
|                                        | Risk management and trading activities            |                                    |            | 24,706       |        |      |            | 38,204     |       
|                                        | Deferred gain on Palo Verde Unit 2
sale-leaseback |                                    |            | 21,656       |        |      |            | 23,562     |       
|                                        | Other                                             |                                    |            | 72,556       |        |      |            | 71,147     |       
|                                        |                                                   |                                    |            |              |        |      |            |            |       
|Total deferred tax assets               |                                                   |                                    | 234,752    |              |        |      | 225,584    |           
|                                        |                                                   |                                    |            |              |        |      |            |            |       
|DEFERRED TAX LIABILITIES                |                                                   |                                    |            |              |        |      |            |           
|                                        | Plant-related                                     |                                    |            | (1,386,136   | )      |      |            | (1,316,636 | )     
|                                        | Regulatory assets                                 |                                    |            | (69,070      | )      |      |            | (101,522   | )     
|                                        | Risk management and trading activities            |                                    |            | (28,574      | )      |      |            | (28,884    | )     
|                                        |                                                   |                                    |            |              |        |      |            |            |       
|Total deferred tax liabilities          |                                                   |                                    | (1,483,780 | )            |        |      | (1,447,042 | )         
|                                        |                                                   |                                    |            |              |        |      |            |            |       
|Accumulated deferred income taxes  net |                                                   | $                                  | (1,249,028 | )            |        | $    | (1,221,458 | )         
|                                        |                                                   |                                    |            |              |        |      |            |            |       



|5. |  | Lines of Credit and Short-Term Borrowings
|-- |  | -----------------------------------------

We 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. We
had no bank borrowings outstanding under these lines of credit at December 31,
2003 and 2002.

We had no commercial paper borrowings outstanding at December 31, 2003 and
2002. By Arizona statute, our short-term borrowings cannot exceed 7% of our
total capitalization unless approved by the ACC.

All of our bank lines of credit and commercial paper agreements are
unsecured.



|6. |  | Long-Term Debt
|-- |  | --------------

Borrowings under our mortgage bond indenture are secured by substantially
all of our utility plant. We also have unsecured debt. The following table
presents the components of long-term debt on the Balance Sheets outstanding at
December 31, 2003 and 2002 (dollars in thousands):

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NOTES TO FINANCIAL STATEMENTS

|                                              |                         |  |           |  |          |  |       |      |      |   |              |         |  |   |           |       | 
|--------------------------------------------- | ----------------------- |  | --------- |  | -------- |  | ----- | ---- | ---- | - | ------------ | ------- |  | - | --------- | ----- | 
|                                              |                         |  |           |  |          |  |       |      |      |   | December 31,
|                                              |                         |  |           |  |          |  |       |      |      |   |             
|                                              |                         |  | Maturity  |  | Interest |  |       |      |      |   |              |         | 
|                                              |                         |  | Dates (a) |  | Rates    |  | 2003  |      | 2002
|                                              |                         |  |           |  |          |  |       |      |     
|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    |      
|                                              |                         |  |           |  |          |  |       |      |      |   |              |         |  |   |           |      
|Total long-term debt                          |                         |  |           |  |          |  |       |      |      |   | 2,622,673    |         |  |   | 2,220,843 |      
|                                              | Less current maturities |  |           |  |          |  |       |      |      |   |              | 206,727 |  |   |           | 3,503 | 
|                                              |                         |  |           |  |          |  |       |      |      |   |              |         |  |   |           |      
|Total long-term debt less current
maturities  |                         |  |           |  |          |  |       |      |      | $ | 2,415,946    |         |  | $ | 2,217,340 |      
|                                              |                         |  |           |  |          |  |       |      |      |   |              |         |  |   |           |      



|(a) |  | This schedule does not reflect the timing of redemptions that may occur
prior to maturity.                                                                                                                                                                                                                                                                                                                                                                                                   
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | On August 15, 2003, we redeemed at maturity $54 million of our First
Mortgage Bonds, 7.25% Series due 2023.                                                                                                                                                                                                                                                                                                                                                                                  
|   
|(c) |  | On April 7, 2003, we redeemed $33 million of our First Mortgage Bonds,
8.00% Series due 2025.                                                                                                                                                                                                                                                                                                                                                                                                
|   
|(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 us 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) |  | We currently have 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. Our payments of principal, premium and/or interest on the senior
notes satisfy our                        

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NOTES TO FINANCIAL STATEMENTS



|    |  | 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 we repay all of our 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 Balance Sheets for both December 31, 2003 and December
31, 2002.                                                                                                                                                                                          

Our debt covenants related to our financing arrangements include a
debt-to-total-capitalization ratio and an interest coverage test. We comply
with these covenants and anticipate that we will continue to meet the covenant
requirement levels. The ratio of debt to total capitalization cannot exceed
65%. At December 31, 2003, our ratio was approximately 53%. The provisions
regarding interest coverage require a minimum cash coverage of two times the
interest requirements for us. Based on 2003 results, the coverage is
approximately 4 times for our bank agreements and 15 times for our 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.

Our financing agreements do not 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, we may be subject to increased interest costs under certain
financing agreements.

All of our bank agreements contain cross-default provisions that would
result in defaults and the potential acceleration of payment under these loan
agreements if we were to default under other agreements. All of our bank
agreements contain cross-default provisions that would result in defaults and
the potential acceleration of payment under these bank agreements if we were to
default under other agreements. Our 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:



| |  |  | $207 million in 2004;      
| | - |  | ---------------------------
|
| |  |  | $402 million in 2005;      
|
| |  |  | $85 million in 2006;       
|
| |  |  | $1 million in 2007;        
|
| |  |  | $1 million in 2008; and    
|
| |  |  | $1,935 million, thereafter.

Our 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. We may pay dividends

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NOTES TO FINANCIAL STATEMENTS

on our 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 us to pay approximately $3 billion of dividends
compared to our current annual common stock dividends of $170 million.

The mortgage currently constitutes a lien on substantially all of our
property. We anticipate that in early April 2004, all first mortgage bonds
issued by us under our existing mortgage and deed of trust, other than the
first mortgage bonds securing our senior notes, will have been paid and
retired. At that time, our 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. We are then obligated to take all steps necessary to terminate
our existing mortgage and deed of trust and cannot issue any additional first
mortgage bonds under that mortgage.



|7. |  | 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 their subsidiaries. In 2003, we represented 89% of the total
cost of these plans. 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
Pinnacle Wests Board of Directors. Our employees do not contribute to the
plans. Generally, the benefits under these plans are calculated based on age,
years of service and pay.

Pinnacle West also sponsors other postretirement benefits for the
employees of Pinnacle West and their subsidiaries. Pinnacle West provides
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. Pinnacle West retains 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 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

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NOTES TO FINANCIAL STATEMENTS

accompanying notes. Specific accounting guidance for this subsidy,
including transition rules, is pending.

The following table provides details of the Pinnacle West plans benefit
costs. Also included is our 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  |       
|                                               |                               |   |         |        |                |   |         |        |      |   |         |        |      |   |         |       |   |   |         |       |   |   |         |       
|Our share of costs
charged
to expense          |                               | $ | 25,450  |        |                | $ | 10,947  |        |      | $ | 6,699   |        |      | $ | 15,166  |       |   | $ | 9,232   |       |   | $ | 4,840   |       
|                                               |                               |   |         |        |                |   |         |        |      |   |         |        |      |   |         |       |   |   |         |       |   |   |         |       

The following table sets forth the Pinnacle West plans change in the
benefit obligations for the plan years 2003 and 2002 (dollars in thousands):

|                                  |  |         |           |                |  |      |           |      |  |   |         |   |  |   |         |     
|--------------------------------- |  | ------- | --------- | -------------- |  | ---- | --------- | ---- |  | - | ------- | - |  | - | ------- | ----
|                                  |  | 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.
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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NOTES TO FINANCIAL STATEMENTS

The following table sets forth the qualified defined benefit plan and
other benefit plan changes in the fair value of Pinnacle Wests 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
Pinnacle West plans to the amounts Pinnacle West recognized in its 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 Pinnacle
West Consolidated Balance
Sheet |  | $       | (61,800  | )              |  | $    | (42,726  | )    |  | $ | (3,022   | ) |  | $ | (3,316   | )
|                                                                             |  |         |          |                |  |      |          |      |  |   |          |   |  |   |          |  

The following sets forth the details related to benefits included on
Pinnacle Wests Consolidated Balance Sheets (dollars in thousands):

|                                                |  |         |          |                |  |      |          |      |  |   |        |   |  |   |        |  
|----------------------------------------------- |  | ------- | -------- | -------------- |  | ---- | -------- | ---- |  | - | ------ | - |  | - | ------ | -
|                                                |  | 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 Pinnacle West 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 | )
|                                                |  |         |          |                |  |      |          |      |  |   |        |   |  |   |        |  

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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: |                            |  |      |       |      |  |   |        
|                                                                                              | Pinnacle West Consolidated |  | $    | 4,700 |      |  | $ | (70,298 | )
|                                                                                              | Our share                  |  |      | 4,329 |      |  |   | (60,521 | )

The
following table sets forth the projected benefit obligations and the accumulated benefit obligation for
Pinnacle West 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   |        
|                               |                                 |   |           |         |      |   |           |        
|                               | Pinnacle West pension liability |   | $         | 188,041 |      |   | $         | 183,880 | 
|                               |                                 |   |           |         |      |   |           |        
|                               | Our share of pension liability  |   | $         | 160,639 |      |   | $         | 156,442 | 
|                               |                                 |   |           |         |      |   |           |        

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 of Pinnacle West:

|                                                |  |                     |      |                     |  |      |      |      |  |               |      |   |  |  |       |  
|----------------------------------------------- |  | ------------------- | ---- | ------------------- |  | ---- | ---- | ---- |  | ------------- | ---- | - |  |  | ----- | -
|                                                |  |                     |      |                     |  |      |      |      |  | 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  |  

In selecting the pretax expected long-term rate of return on plan assets
Pinnacle West considers past performance and economic forecasts for the types
of investments held by the plan. For the year 2003, Pinnacle West decreased
its 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 Pinnacle West is assuming a 9% rate of return on plan assets.
This

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NOTES TO FINANCIAL STATEMENTS

rate is reflective of the market returns earned historically on Pinnacle Wests
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 Pinnacle Wests 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 of Pinnacle West. 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,                 |     | Target Asset Allocation
|                  |  |                              |     |                        
|                  |  | 2003                         |     | 2002                    |  |  |     |  
|                  |  |                              |     |                         |  |  |     |  
|Asset Category:   |  |                              |     |                         |  |  |     |   |  |  |       |  
|Equity securities |  |                              | 65  | %                       |  |  | 56  | % |  |  | 50-70 | %
|Debt securities   |  |                              | 23  |                         |  |  | 31  |   |  |  | 20-40 | %
|Other             |  |                              | 12  |                         |  |  | 13  |   |  |  | 5-15  | %
|                  |  |                              |     |                         |  |  |     |   |  |  |       |  
|Total             |  |                              | 100 | %                       |  |  | 100 | % |  |  |       |  
|                  |  |                              |     |                         |  |  |     |   |  |  |       |  

Pinnacle Wests 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.

Pinnacle Wests other postretirement benefit plan asset allocation at
December 31, 2003, and 2002, is as follows:

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NOTES TO FINANCIAL STATEMENTS

|                  |  |                              |     |                         |  |  |     |   |  |  |       |  
|----------------- |  | ---------------------------- | --- | ----------------------- |  |  | --- | - |  |  | ----- | -
|                  |  | Percentage of Plan Assets at |     |                         |  | 
|                  |  | December 31,                 |     | Target Asset Allocation
|                  |  |                              |     |                        
|                  |  | 2003                         |     | 2002                    |  |  |     |  
|                  |  |                              |     |                         |  |  |     |  
|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, Pinnacle West is required to contribute approximately
$100 million to its pension plans in 2004 and expects to contribute
approximately $50 million to its other postretirement benefit
plans in 2004. Our share is approximately 89%. If currently
pending legislation is enacted, Pinnacle Wests required pension contribution
in 2004 would decrease to the $25 to $50 million range (our share would
decrease to the $22 to $44 million range).

Employee Savings Plan Benefits

Pinnacle West sponsors a defined contribution savings plan for eligible
employees of Pinnacle West and subsidiaries. In 2003, we represented 90% of
the total cost of this plan. In a defined contribution savings plan, the
benefits a participant receives result from regular contributions participants
make to their own individual account. Under this plan, Pinnacle West 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 in 2003, $4 million in 2002 and $4
million in 2001.

Severance Charges

In July 2002, we implemented a voluntary workforce reduction as part of a
cost reduction program. We recorded $34 million before taxes in voluntary
severance costs in 2002. No further charges are expected.



|8. |  | Leases
|-- |  | ------

In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. We account 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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NOTES TO FINANCIAL STATEMENTS

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 18 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 Statements of Income was $66 million
in 2003, $57 million in 2002 and $55 million in 2001.

The amounts to be paid for the Palo Verde Unit 2 leases are approximately
$49 million per year for the years 2003 to 2015.

In accordance with the 1999 Settlement Agreement and previous settlement
agreements, we are 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 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 |     | $   | 65 | 
|                               |            | 2005 |     |     | 64 | 
|                               |            | 2006 |     |     | 63 | 
|                               |            | 2007 |     |     | 63 | 
|                               |            | 2008 |     |     | 62 | 
|                               | Thereafter |      |     | 402 |   
|                               |            |      |     |    
|Total future lease commitments |            | $    | 719 |    
|                               |            |      |     |    



|9. |  | Jointly-Owned Facilities
|-- |  | ------------------------

We share ownership of some of our generating and transmission facilities
with other companies. The following table shows our interest in those
jointly-owned facilities recorded on the Balance Sheets at December 31, 2003.
Our share of operating and maintaining these facilities is included in the
Statements of Income in operations and maintenance expense (dollars in
thousands):

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NOTES TO FINANCIAL STATEMENTS

|                         |                                                           |  |          |      |          |  |              |           |          |  |   |          |              |  |   |        | 
|------------------------ | --------------------------------------------------------- |  | -------- | ---- | -------- |  | ------------ | --------- | -------- |  | - | -------- | ------------ |  | - | ------ | 
|                         |                                                           |  | Percent  |      |          |  |              |           |          |  |   |          | Construction
|                         |                                                           |  | Owned by |      | Plant in |  | Accumulated  |           | Work in 
|                         |                                                           |  | Us       |      | 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 8) |  |          | 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 we operate the unit for PacifiCorp.
The common facilities at the Cholla Plant are jointly-owned.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Weighted average of interests.                                                                                                    
|   
|10. |  | Commitments and Contingencies                                                                                                     

Enron

We recorded charges totaling $13 million before income taxes for exposure
to Enron and its affiliates in the fourth quarter of 2001. These charges take
into consideration our rights of set-off with respect to the Enron related
contractual obligations. 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 us 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 Balance Sheets.
In February 2004, Enron filed an adversary proceeding against us in bankruptcy
court regarding differences in the valuation of trading positions involving us.
Enron North America v. Arizona Public Service Company, Adversary Proceeding
No. 04-02366 (ALJ). We will vigorously defend this action and do not believe
it will have any material adverse impact on our 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 that 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 us (on behalf of ourselves 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.

We have existing fuel storage pools at Palo Verde and are 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, we believe that 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, we are currently shipping low-level waste to off-site facilities. We
currently believe that 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.

We currently estimate that we will incur $115 million (in 2003 dollars)
over the life of Palo Verde for our share of the costs related to the on-site
interim storage of spent nuclear fuel. As of December 31, 2003, we had spent
$7 million and had recorded a liability of $42 million for on-site interim
spent nuclear fuel storage costs related to nuclear fuel burned to date. We
have recorded a corresponding regulatory asset of $49 million and are seeking
recovery of these costs through future rates (see General Rate Case and Retail
Rate Mechanisms in Note 3).

We have 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 Balance Sheets at
December 31, 2002. Upon adoption of SFAS No. 143 in

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2003, we reclassified this liability to a regulatory liability because no
legal obligation for removal exists.

We believe that scientific and financial aspects of the issues of spent
nuclear fuel and low-level waste storage and disposal can be resolved
satisfactorily. However, we acknowledge that their ultimate resolution in a
timely fashion will require political resolve and action on national and
regional scales which we are less able to predict. We expect to vigorously
protect and pursue our 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, we 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 our interest
in the three Palo Verde units, our 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. We have 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

We are party 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 $262 million in 2004;
$95 million in 2005; $92 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 we have for the
supply of our coal and nuclear fuel 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,
|                                  |  |                          
|                                  |  |                           |    |      |  |      |    |      |  |      |    |       |  |           |    |  |  |   |    |  |  | There-
|                                  |  | 2004                      |    | 2005 |  | 2006 |    | 2007 |  | 2008 |    | after
|                                  |  |                           |    |      |  |      |    |      |  |      |    |      
|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

We 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 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, we are 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 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. We were a seller and a purchaser in the California markets at
issue, and to the extent that refunds are ordered, we 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. We do not anticipate material
changes in our exposure and still believe, subject to the finalization of the
revised proxy prices, that we 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, the FERC made public a Final Report on Price Manipulation
in Western Markets, prepared by its Staff and covering spot markets in the West
in 2000 and 2001. The report stated that a significant number of entities who
participated in the California markets during the 2000-2001 time period,
including us, may potentially have been involved in arbitrage transactions

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that allegedly violated certain provisions of the ISO tariff. We 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.

California Energy Market LitigationOn 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 us, attempting to expand those
matters to such other participants. We have not yet filed a responsive
pleading in the matter, but we believe the claims by Reliant and Duke as they
relate to us are without merit.

We were 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 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 us 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 us that it believes we overcharged Citizens by over $50 million under a
power service agreement. We believe that our 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 that, based on its
review, if Citizens filed a complaint with the FERC, it probably would lose
the central issue in the contract interpretation dispute. We and Citizens
terminated the power service agreement effective July 15, 2001. In replacement
of the power service agreement, Pinnacle West and Citizens entered into a power
sale agreement under which Pinnacle West will supply Citizens with future

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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

Total capital expenditures in 2004 are estimated at $426 million.

Natural Gas Supply

We and
Pinnacle West Energy purchase the majority of our natural gas
requirements for our gas-fired plants under contracts with a number of
natural gas suppliers. Effective September 1, 2003, our 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, our 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 limitations on the former full requirements
contract holders ability to nominate firm transportation capacity. In order
for us and Pinnacle West Energy to meet our natural gas supply and capacity
requirements, we 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. We 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 financial statements, results of operations or
liquidity.

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|11. |  | 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.

We have asset retirement obligations for our 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 we 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 our
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 we
expect to continue. As a result, we cannot reasonably estimate the fair value
of the asset retirement obligation related to such distribution and
transmission assets.

On January 1, 2003 and in accordance with SFAS No. 143, 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 net regulatory liability of $40
million for the asset retirement obligations related to our 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. We believe we 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.

We have
reclassified prior year removal costs of approximately $557
million previously included in accumulated depreciation to the liability for
asset retirements and removals on our Balance Sheets. In 2003, we reclassified
the portion of this liability which no legal obligation for removal exists to a
regulatory liability.

In accordance with SFAS No. 71, we will continue to accrue for removal
costs for our regulated assets, even if there is no legal obligation for
removal. At December 31, 2003, regulatory liabilities shown on our Balance
Sheets included approximately $480 million of estimated future removal costs
that are not considered legal obligations.

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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 we expect to incur to decommission Palo Verde, we
established external decommissioning trusts in accordance with NRC regulations.
We invest the trust funds in fixed income and domestic equity securities and
classifies them as available for sale. The following table shows the cost and
fair value of our nuclear decommissioning trust fund assets which are on the
Balance Sheets at December 31, 2003 and December 31, 2002 (dollars in
millions):

|                                  |                         |   |              |     |              |   |     |     | 
|--------------------------------- | ----------------------- | - | ------------ | --- | ------------ | - | --- | --- | 
|                                  |                         |   | December 31, |     | December 31,
|                                  |                         |   | 2003         |     | 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 |    
|                                  |                         |   |              |     |              |   |     |    



|12. |  | Selected Quarterly Financial Data (Unaudited)
|--- |  | ---------------------------------------------

Quarterly financial information for 2003 and 2002 is as follows (dollars
in thousands):

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|                    |               |  |               |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |         |         | 
|------------------- | ------------- |  | ------------- | ------- | ---------------- | - | --------- | ------- | --------- | - | --------- | ------- |  | - | ------- | ------- |  | - | ------- | ------- | 
|                    |               |  | Operating     |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |        
|                    |               |  | Revenues as   |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |        
|                    |               |  | Previously    |         | Reclassification |   | Operating |         | Operating |   | Net      
|                    |               |  | Disclosed (a) |         | Adjustment (b)   |   | Revenues  |         | Income    |   | Income   
|                    |               |  |               |         |                  |   |           |         |           |   |          
|2003 Quarter ended: |               |  |               |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |         |        
|                    | March 31,     |  | $             | 478,726 |                  |   | $         | 46,789  |           |   | $         | 431,937 |  |   | $       | 46,830  |  |   | $       | 15,933  | 
|                    | June 30,      |  |               | 620,453 |                  |   |           | 87,131  |           |   |           | 533,322 |  |   |         | 76,258  |  |   |         | 43,175  | 
|                    | September 30, |  |               | 822,186 |                  |   |           | 139,570 |           |   |           | 682,616 |  |   |         | 120,415 |  |   |         | 100,356 | 
|                    | December 31,  |  |               |        |                  |   |           |        |           |   |           | 457,056 |  |   |         | 54,655  |  |   |         | 21,473  | 
|                    |               |  |               |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |         |        
|                    |               |  |               |         |                  | $ | 273,490   |         |           | $ | 2,104,931 |         |  | $ | 298,158 |         |  | $ | 180,937 |        
|                    |               |  |               |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |         |        

|                    |               |  |               |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |         |        | 
|------------------- | ------------- |  | ------------- | ------- | ---------------- | - | --------- | ------- | --------- | - | --------- | ------- |  | - | ------- | ------- |  | - | ------- | ------ | 
|                    |               |  | Operating     |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |        
|                    |               |  | Revenues as   |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |        
|                    |               |  | Previously    |         | Reclassification |   | Operating |         | Operating |   | Net      
|                    |               |  | Disclosed (a) |         | Adjustment (b)   |   | Revenues  |         | Income    |   | Income   
|                    |               |  |               |         |                  |   |           |         |           |   |          
|2002 Quarter ended: |               |  |               |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |         |       
|                    | March 31,     |  | $             | 394,434 |                  |   | $         | 5,247   |           |   | $         | 389,187 |  |   | $       | 61,221  |  |   | $       | 31,763 | 
|                    | June 30,      |  |               | 510,080 |                  |   |           | 15,757  |           |   |           | 494,323 |  |   |         | 97,555  |  |   |         | 64,439 | 
|                    | September 30, |  |               | 753,589 |                  |   |           | 113,364 |           |   |           | 640,225 |  |   |         | 120,452 |  |   |         | 86,570 | 
|                    | December 31,  |  |               | 435,290 |                  |   |           | 22,859  |           |   |           | 412,431 |  |   |         | 49,772  |  |   |         | 16,571 | 
|                    |               |  |               |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |         |       
|                    |               |  |               |         |                  | $ | 157,227   |         |           | $ | 1,936,166 |         |  | $ | 329,000 |         |  | $ | 199,343 |       
|                    |               |  |               |         |                  |   |           |         |           |   |           |         |  |   |         |         |  |   |         |       



|(a) |  | Operating revenues previously disclosed in the March 31, 2003, June 20,
2003 and September 30, 2003 Quarterly Report on Forms 10-Q,
except for the fourth quarter ended December 31, 2002, which was
disclosed in our 8-K dated March 31, 2003.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | Reclassification adjustment relates to the adoption of EITF 03-11 (see Note
16).                                                                                                                                                               
|   
|13. |  | 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 our nuclear decommissioning trust fund assets in Note 11.

On December 31, 2003, the carrying value of our long-term debt (excluding
capitalized lease obligations) was $2.61 billion, with an estimated fair value
of $2.74 billion. The carrying value of our long-term debt (excluding
capitalized lease obligations) was $2.21 billion on December 31, 2002, with an
estimated fair value of $2.30 billion. The fair value estimates are based on
quoted market prices of the same or similar issues.

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|14. |  | Stock-Based Compensation
|--- |  | ------------------------

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

In May 2002, Pinnacle Wests 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. Pinnacle West 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.

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, Pinnacle West 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 $1.3 million in stock
option expense before income taxes in our Statements of Income in 2003 and
approximately $0.4 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 $3
million in 2003, $3 million in 2002 and $2 million in 2001.

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The following table is a summary of the status of Pinnacle Wests stock
option plans as of December 31, 2003, 2002 and 2001 and changes during the
years ending on those dates:

|                                                               |  |        |           |          |  |          |       |          |  |        |           |          |  |   |       |  |  |          |           |   |  |   |       | 
|-------------------------------------------------------------- |  | ------ | --------- | -------- |  | -------- | ----- | -------- |  | ------ | --------- | -------- |  | - | ----- |  |  | -------- | --------- | - |  | - | ----- | 
|                                                               |  |        |           |          |  | 2003     |       |          |  |        |           | 2002     |  |   |       |  |  | 2001    
|                                                               |  |        |           |          |  | Weighted |       |          |  |        |           | Weighted |  |   |       |  |  | Weighted
|                                                               |  |        |           |          |  | Average  |       |          |  |        |           | Average  |  |   |       |  |  | Average 
|                                                               |  | 2003   |           | Exercise |  | 2002     |       | Exercise |  | 2001   |           | Exercise
|                                                               |  | Shares |           | Price    |  | Shares   |       | Price    |  | Shares |           | 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 Pinnacle Wests 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 Pinnacle West stock compensation awards granted, other than
options, during the years ended December 31, 2003, 2002 and 2001:

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NOTES TO FINANCIAL STATEMENTS

|                         |  |        |         |            |  |        |       |            |  |        |         |            |  |   |       |     |  |  |        |  |  |   |       |    
|------------------------ |  | ------ | ------- | ---------- |  | ------ | ----- | ---------- |  | ------ | ------- | ---------- |  | - | ----- | --- |  |  | ------ |  |  | - | ----- | ---
|                         |  | 2003   |         | 2003 Grant |  | 2002   |       | 2002 Grant |  | 2001   |         | 2001 Grant
|                         |  | Shares |         | Price      |  | Shares |       | Price      |  | Shares |         | 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) |  |  |       |  |  |   |      |    



| | (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.                  



|15. |  | Business Segments
|--- |  | -----------------

We have two principal business segments (determined by 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; and                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | our marketing and trading segment, which consists of our
competitive energy business activities, including wholesale
marketing and trading. During 2001, we transferred most of our
marketing and trading activities to Pinnacle West. Thus, we did not
have any significant marketing and trading activity in 2002.
Conversely, in the first quarter of 2003, Pinnacle West moved the
marketing and trading division back to us for future marketing and
trading activities (existing wholesale contracts remained at
Pinnacle West). This latest move was a result of the ACCs Track A
Order prohibiting the previously required transfer of our generating
assets to Pinnacle West Energy.

See Note 16 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 FINANCIAL STATEMENTS

|                               |                  |   |                                  |     |               |   |       |    |   |   |       |     | 
|------------------------------ | ---------------- | - | -------------------------------- | --- | ------------- | - | ----- | -- | - | - | ----- | --- | 
|                               |                  |   | Business Segments for Year Ended
|                               |                  |   | December 31, 2003               
|                               |                  |   |                                 
|                               |                  |   | Regulated                        |     | Marketing and |   |       |    |  
|                               |                  |   | Electricity                      |     | Trading       |   | Total
|                               |                  |   |                                  |     |               |   |      
|Operating revenues             |                  | $ | 1,999                            |     |               | $ | 106   |    |   | $ | 2,105 |    
|Purchased power and fuel costs |                  |   | 606                              |     |               |   | 97    |    |   |   | 703   |    
|Other operating expenses       |                  |   | 609                              |     |               |   | 14    |    |   |   | 623   |    
|                               |                  |   |                                  |     |               |   |       |    |   |   |       |    
|                               | Operating margin |   |                                  | 784 |               |   |       | (5 | ) |   |       | 779 | 
|Depreciation and amortization  |                  |   | 389                              |     |               |   |      |    |   |   | 389   |    
|Interest                       |                  |   | 144                              |     |               |   |      |    |   |   | 144   |    
|Other expense/(income)  net   |                  |   | (22                              | )   |               |   |      |    |   |   | (22   | )  
|                               |                  |   |                                  |     |               |   |       |    |   |   |       |    
|                               | Pretax margin    |   |                                  | 273 |               |   |       | (5 | ) |   |       | 268 | 
|Income taxes                   |                  |   | 89                               |     |               |   | (2    | )  |   |   | 87    |    
|                               |                  |   |                                  |     |               |   |       |    |   |   |       |    
|Net income (loss)              |                  | $ | 184                              |     |               | $ | (3    | )  |   | $ | 181   |    
|                               |                  |   |                                  |     |               |   |       |    |   |   |       |    
|Total assets                   |                  | $ | 7,747                            |     |               | $ | 8     |    |   | $ | 7,755 |    
|                               |                  |   |                                  |     |               |   |       |    |   |   |       |    
|Capital expenditures           |                  | $ | 424                              |     |               | $ | 5     |    |   | $ | 429   |    
|                               |                  |   |                                  |     |               |   |       |    |   |   |       |    

|                               |                  |   |                                  |     |               |   |       |   |  |   |       |     | 
|------------------------------ | ---------------- | - | -------------------------------- | --- | ------------- | - | ----- | - |  | - | ----- | --- | 
|                               |                  |   | Business Segments for Year Ended
|                               |                  |   | December 31, 2002               
|                               |                  |   |                                 
|                               |                  |   | Regulated                        |     | Marketing and |   |       |   | 
|                               |                  |   | Electricity                      |     | Trading       |   | Total
|                               |                  |   |                                  |     |               |   |      
|Operating revenues             |                  | $ | 1,902                            |     |               | $ | 34    |   |  | $ | 1,936 |    
|Purchased power and fuel costs |                  |   | 438                              |     |               |   | 33    |   |  |   | 471   |    
|Other operating expenses       |                  |   | 604                              |     |               |   |      |   |  |   | 604   |    
|                               |                  |   |                                  |     |               |   |       |   |  |   |       |    
|                               | Operating margin |   |                                  | 860 |               |   |       | 1 |  |   |       | 861 | 
|Depreciation and amortization  |                  |   | 400                              |     |               |   |      |   |  |   | 400   |    
|Interest                       |                  |   | 122                              |     |               |   |      |   |  |   | 122   |    
|Other expense/(income)  net   |                  |   | 14                               |     |               |   |      |   |  |   | 14    |    
|                               |                  |   |                                  |     |               |   |       |   |  |   |       |    
|                               | Pretax margin    |   |                                  | 324 |               |   |       | 1 |  |   |       | 325 | 
|Income taxes                   |                  |   | 126                              |     |               |   |      |   |  |   | 126   |    
|                               |                  |   |                                  |     |               |   |       |   |  |   |       |    
|Net income                     |                  | $ | 198                              |     |               | $ | 1     |   |  | $ | 199   |    
|                               |                  |   |                                  |     |               |   |       |   |  |   |       |    
|Total assets                   |                  | $ | 7,122                            |     |               | $ |      |   |  | $ | 7,122 |    
|                               |                  |   |                                  |     |               |   |       |   |  |   |       |    
|Capital expenditures           |                  | $ | 501                              |     |               | $ |      |   |  | $ | 501   |    
|                               |                  |   |                                  |     |               |   |       |   |  |   |       |    

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NOTES TO FINANCIAL STATEMENTS

|                                                                                       |                  |   |                                  |     |               |   |       |     |  |   |       |       | 
|-------------------------------------------------------------------------------------- | ---------------- | - | -------------------------------- | --- | ------------- | - | ----- | --- |  | - | ----- | ----- | 
|                                                                                       |                  |   | Business Segments for Year Ended
|                                                                                       |                  |   | December 31, 2001               
|                                                                                       |                  |   |                                 
|                                                                                       |                  |   | Regulated                        |     | Marketing and |   |       |     | 
|                                                                                       |                  |   | Electricity                      |     | Trading       |   | Total
|                                                                                       |                  |   |                                  |     |               |   |      
|Operating revenues                                                                     |                  | $ | 1,984                            |     |               | $ | 368   |     |  | $ | 2,352 |      
|Purchased power and fuel costs                                                         |                  |   | 649                              |     |               |   | 133   |     |  |   | 782   |      
|Other operating expenses                                                               |                  |   | 567                              |     |               |   |      |     |  |   | 567   |      
|                                                                                       |                  |   |                                  |     |               |   |       |     |  |   |       |      
|                                                                                       | Operating margin |   |                                  | 768 |               |   |       | 235 |  |   |       | 1,003 | 
|Depreciation and amortization                                                          |                  |   | 421                              |     |               |   |      |     |  |   | 421   |      
|Interest                                                                               |                  |   | 118                              |     |               |   |      |     |  |   | 118   |      
|Other expense/(income)  net                                                           |                  |   | 1                                |     |               |   |      |     |  |   | 1     |      
|                                                                                       |                  |   |                                  |     |               |   |       |     |  |   |       |      
|                                                                                       | Pretax margin    |   |                                  | 228 |               |   |       | 235 |  |   |       | 463   | 
|Income taxes                                                                           |                  |   | 90                               |     |               |   | 93    |     |  |   | 183   |      
|                                                                                       |                  |   |                                  |     |               |   |       |     |  |   |       |      
|Income before accounting change                                                        |                  |   | 138                              |     |               |   | 142   |     |  |   | 280   |      
|Cumulative effect of change in accounting for
derivatives  net of income taxes of $10 |                  |   | (15                              | )   |               |   |      |     |  |   | (15   | )    
|                                                                                       |                  |   |                                  |     |               |   |       |     |  |   |       |      
|Net income                                                                             |                  | $ | 123                              |     |               | $ | 142   |     |  | $ | 265   |      
|                                                                                       |                  |   |                                  |     |               |   |       |     |  |   |       |      
|Capital expenditures                                                                   |                  | $ | 471                              |     |               | $ |      |     |  | $ | 471   |      
|                                                                                       |                  |   |                                  |     |               |   |       |     |  |   |       |      



|16. |  | 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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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS 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. The impact of this guidance was immaterial to
our financial statements. 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
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 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 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 revenues and purchased power and fuel
costs, but did not have any impact on our financial condition, net
income or cash flows. 98




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS 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 EITF 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
    
    2001Regulated Electricity
    
    $
    40,067
    
    
    $
    157,227
    
    
    $
    577,783Marketing and Trading
    
    
    233,423
    
    
    
    
    
    
    
    181,447Total
    
    $
    273,490
    
    
    $
    157,227
    
    
    $
    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
Statements of Income for the years ended December 31, 2003 and 2002 are
comprised of the following (dollars in thousands): 2003
    
    2002Gains on the ineffective portion of
derivatives qualifying for hedge
accounting
    
    $
    7,033
    
    
    $
    9,091Gains
(losses) from the change in options time value excluded from
measurement of effectiveness
    
    
    181
    
    
    
    (609
    )Losses from the discontinuance of
cash flow hedges
    
    
    
    
    
    
    (9,206
    )
 99




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS 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 three years. During the year ending December 31,
2004, we estimate that a net gain of $7 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 our
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): December 31, 2003 Current
    
    
    
    
    
    Current
    
    Other
    
    Net Asset/Assets
    
    Investments
    
    Liabilities
    
    Liabilities
    
    (Liability)Regulated Electricity:Mark-to-Market
    
    $
    44,079
    
    
    $
    5,900
    
    
    $
    (47,268
    )
    
    $
    (3,028
    )
    
    $
    (317
    )Options
    
    
    
    
    
    
    12,101
    
    
    
    
    
    
    
    
    
    
    
    12,101Marketing & Trading:Mark-to-Market
    
    
    8,369
    
    
    
    
    
    
    
    (10,870
    )
    
    
    (1,474
    )
    
    
    (3,975
    )Total
    
    $
    52,448
    
    
    $
    18,001
    
    
    $
    (58,138
    )
    
    $
    (4,502
    )
    
    $
    7,809
 December 31, 2002 Current
    
    
    
    
    
    Current
    
    Other
    
    Net Asset/Assets
    
    Investments
    
    Liabilities
    
    Liabilities
    
    (Liability)Regulated Electricity:Mark-to-Market
    
    $
    39,616
    
    
    $
    6,971
    
    
    $
    (59,773
    )
    
    $
    (36,678
    )
    
    $
    (49,864
    )Options
    
    
    
    
    
    
    24,651
    
    
    
    
    
    
    
    
    
    
    
    24,651Total
    
    $
    39,616
    
    
    $
    31,622
    
    
    $
    (59,773
    )
    
    $
    (36,678
    )
    
    $
    (25,213
    )
 Cash or collateral may be required to serve as collateral against our open
positions on certain energy-related contracts. No collateral was provided to
counterparties at December 31, 2003. Collateral provided to counterparties was
$5 million at December 31, 2002, and is included in investments and other
assets on the Balance Sheet. Collateral provided to us by counterparties is
$12 million at December 31, 2003 and $4 million at December 31, 2002, and is
included in other deferred credits on the Balance Sheet. 100




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS Credit Risk We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. Our risk management process assesses and monitors the
financial exposure of counterparties. Despite the fact that the great 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 impact on 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. 17. 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 312003
    
    2002
    
    2001Other income:Interest income
    
    $
    15,660
    
    
    $
    3,455
    
    
    $
    5,004Miscellaneous
    
    
    2,510
    
    
    
    1,694
    
    
    
    2,854Investment gains  net
    
    
    2,107
    
    
    
    
    
    
    
    Environmental insurance
recovery
    
    
    
    
    
    
    
    
    
    
    12,349Total other income
    
    $
    20,277
    
    
    $
    5,149
    
    
    $
    20,207Other expense:Non-operating costs (a)
    
    $
    (10,883
    )
    
    $
    (16,424
    )
    
    $
    (14,637
    )Miscellaneous
    
    
    (2,079
    )
    
    
    (1,783
    )
    
    
    (2,798
    )Equity losses  net
    
    
    
    
    
    
    (1,131
    )
    
    
    (3,355
    )Total other expense
    
    $
    (12,962
    )
    
    $
    (19,338
    )
    
    $
    (20,790
    )
  (a)
    
    As defined by the FERC, includes below-the-line non-operating
utility costs (primarily community relations). 18. 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 101




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS 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, we 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 8 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. We are exposed to losses under the Palo Verde sale leaseback agreements
upon the occurrence of certain events that we do 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), we 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, we would have been required to assume approximately $268
million of debt and pay the equity participants approximately $200 million. 19. 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 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. We have also entered
into approximately $109 million of letters of credit to support certain equity
lessors in the Palo Verde sale-leaseback transactions (see Note 8 for further
details on the Palo Verde sale-leaseback transactions). These letters of
credit expire in 2005. Additionally, We have approximately $5 million of
letters of credit related to counterparty collateral requirements expiring in
2004. We intend to provide from either existing or new facilities for the
extension, renewal or substitution of the letters of credit to the extent
required. We provide indemnifications relating to liabilities arising from
or related to certain of our agreements. We have 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 102




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ARIZONA PUBLIC SERVICE COMPANY
NOTES TO FINANCIAL STATEMENTS 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.  103




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ARIZONA PUBLIC SERVICE COMPANY
SCHEDULE II  RESERVE FOR UNCOLLECTIBLES
(dollars in thousands)

Column CColumn B
    
    Additions
    
    
    
    
    
    Column EBalance at
    
    Charged
    
    Charged to
    
    
    
    
    
    Balance atColumn A
    
    beginning
    
    to cost and
    
    other
    
    Column D
    
    end ofDescription
    
    of period
    
    expenses
    
    accounts
    
    Deductions
    
    PeriodReserve for uncollectibles2003
    
    $
    1,341
    
    
    $
    5,716
    
    
    $
    
    
    
    $
    3,314
    
    
    $
    3,7432002
    
    
    3,349
    
    
    
    2,680
    
    
    
    
    
    
    
    4,688
    
    
    
    1,3412001
    
    
    2,380
    
    
    
    7,609
    
    
    
    
    
    
    
    6,640
    
    
    
    3,349




104



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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.



105



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PART III 
 ITEM 10. DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT 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.aps.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 Not applicable. 
 ITEM 12. SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS Not applicable. 
 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Not applicable. 
 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The following fees were paid
to our independent public accountants, Deloitte &
Touche LLP, for the last two fiscal years: Type of Service
    
    2002
    
    2003Audit Fees(1)
    
    $
    724,618
    
    
    $
    1,338,846Audit Related Fees(2)
    
    
    
    
    
    
    161,970Tax Fees(3)
    
    
    32,219
    
    
    
    1,677,474All Other Fees(4)
    
    
    
    
    
    
    2,304
   (1)
    
    The aggregate fees billed for services rendered for the audit of annual financial statements
and for review of financial statements included in Forms 10-Q.(2)
    
    The aggregate fees billed for assurance and services that are reasonably related to the
performance of the audit or review of the financial statements that are not included in Audit Fees
reported above, which primarily consist of fees for Sarbanes-Oxley
Section 404 readiness.(3)
    
    The aggregate fees billed primarily for investment tax credit services, tax compliance and tax
planning.(4)
    
    The aggregate fees billed for services rendered for all services in 2003, other than the audit
services described above, which for 2003 consisted
of continuing professional education fees. Pinnacle Wests Audit Committee pre-approves each audit service and non-audit service to be provided
by the Pinnacle Wests independent public accountants. The Audit Committee has delegated to the Chairman
of the Audit Committee the authority to pre-approve audit and non-audit services to be performed by the
independent public accountants if the services are not expected to cost more than $50,000. The Chairman
must report any pre-approval decisions to the Audit Committee at its next scheduled meeting. All of the
services performed by Deloitte & Touche LLP for us were
pre-approved by the Audit Committee. 106




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PART IV 
 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES,
AND REPORTS ON FORM 8-K Financial Statements and Financial Statement Schedules See the Index to Financial Statements in Part II, Item 8. Exhibits Filed Exhibit No.
    
    
    
    Description3.1
    
    
    
    Bylaws, amended as of January 21, 200412.1
    
    
    
    Computation of Ratio of Earnings to Fixed Charges23.1
    
    
    
    Consent of Deloitte & Touche LLP31.1
    
    
    
    Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a)
and Rule 15d  14(a) of the Securities Exchange Act, as amended31.2
    
    
    
    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 amended32.1
    
    
    
    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 200299.1
    
    
    
    Risk Factors
 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 Effective3.2
    
    Articles of Incorporation,
restated as of May 25, 1988
    
    4.2 to Form S-3
Registration Nos.
33-33910 and 33-55248 by
means of September 24,
1993 Form 8-K Report
    
    1-4473
    
    9-29-93
 107




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective4.1
    
    Mortgage and Deed of Trust
Relating to the Companys
First Mortgage Bonds,
together with forty-eight
indentures supplemental
thereto
    
    4.1 to September 1992
Form 10-Q Report
    
    1-4473
    
    11-9-924.2
    
    Forty-ninth Supplemental
Indenture
    
    4.1 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-934.3
    
    Fiftieth Supplemental
Indenture
    
    4.2 to 1993 Form 10-K
Report
    
    1-4473
    
    3-30-944.4
    
    Fifty-first Supplemental
Indenture
    
    4.1 to August 1, 1993
Form 8-K Report
    
    1-4473
    
    9-27-934.5
    
    Fifty-second Supplemental
Indenture
    
    4.1 to September 30, 1993
Form 10-Q Report
    
    1-4473
    
    11-15-934.6
    
    Fifty-third Supplemental
Indenture
    
    4.5 to Registration
Statement No. 33-61228
by means of February 23,
1994 Form 8-K Report
    
    1-4473
    
    3-1-944.7
    
    Fifty-fourth Supplemental
Indenture
    
    4.1 to Registration
Statements Nos. 33-61228,
33-55473, 33-64455 and
333-15379 by means of
November 19, 1996
Form 8-K Report
    
    1-4473
    
    11-22-964.8
    
    Fifty-fifth Supplemental
Indenture
    
    4.8 to Registration
Statement Nos. 33-55473,
33-64455 and 333-15379
by means of April 7, 1997
Form 8-K Report
    
    1-4473
    
    4-9-974.9
    
    Fifty-sixth Supplemental
Indenture
    
    4.1 to Pinnacle West 2002
Form 10-K Report
    
    1-8962
    
    3-31-034.10
    
    Fifty-seventh Supplemental
Indenture
    
    4.2 to Pinnacle West 2002
Form 10-K Report
    
    1-8962
    
    3-31-034.11
    
    Fifty-eighth Supplemental
Indenture
    
    10.1 to the Pinnacle West
June 2003 Form 10-Q
Report
    
    1-8962
    
    8-14-03
 108




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Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective4.12
    
    Agreement, dated March 21,
1994, 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 1993 Form 10-K
Report
    
    1-4473
    
    3-30-944.13
    
    Indenture dated as of January
1, 1995 among the Company
and The Bank of New York,
as Trustee
    
    4.6 to Registration
Statement Nos. 33-61228
and 33-55473 by means of
January 1, 1995 Form 8-K
Report
    
    1-4473
    
    1-11-954.14
    
    First Supplemental Indenture
dated as of January 1, 1995
    
    4.4 to Registration
Statement Nos. 33-61228
and 33-55473 by means of
January 1, 1995 Form 8-K
Report
    
    1-4473
    
    1-11-954.15
    
    Indenture dated as of
November 15, 1996 among
the Company and The Bank
of New York, as Trustee
    
    4.5 to Registration
Statements Nos. 33-61228,
33-55473, 33-64455 and
333-15379 by means of
November 19, 1996
Form 8-K Report
    
    1-4473
    
    11-22-964.16
    
    First Supplemental Indenture
    
    4.6 to Registration
Statements Nos. 33-61228,
33-55473, 33-64455 and
333-15379 by means of
November 19, 1996
Form 8-K Report
    
    1-4473
    
    11-22-964.17
    
    Second Supplemental Indenture dated as of April 1, 1997
    
    4.10 to Registration
Statement Nos. 33-55473,
33-64455 and 333-15379
by means of April 7, 1997
Form 8-K Report
    
    1-4473
    
    4-9-974.18
    
    Third Supplemental Indenture
    
    10.2 to the Companys
March 2003 Form 10-Q
Report
    
    1-8962
    
    5-15-03
 109




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective4.19
    
    Indenture dated as of January
15, 1998 among the Company
and The Chase Manhattan
Bank, as Trustee
    
    4.10 to Registration
Statement Nos. 333-15379
and 333-27551 by means
of January 13, 1998
Form 8-K Report
    
    1-4473
    
    1-16-984.20
    
    First Supplemental Indenture
dated as of January 15, 1998
    
    4.3 to Registration
Statement Nos. 333-15379
and 333-27551 by means
of January 13, 1998
Form 8-K Report
    
    1-4473
    
    1-16-984.21
    
    Second Supplemental
Indenture dated as of
February 15, 1999
    
    4.3 to Registration
Statement Nos. 333-27551
and 333-58445 by means of
February 18, 1999
Form 8-K Report
    
    1-4473
    
    2-22-994.22
    
    Third Supplemental Indenture
dated as of November 1, 1999
    
    4.5 to Registration
Statement No. 333-58445
by means of November 2,
1999 Form 8-K Report
    
    1-4473
    
    11-5-994.23
    
    Fourth Supplemental Indenture dated as of August 1,
2000
    
    4.1 to Registration
Statement Nos. 333-58445
and 333-94277 by means
of August 2, 2000 Form
8-K Report
    
    1-4473
    
    8-4-004.24
    
    Fifth Supplemental Indenture dated as of October 1,
2001
    
    4.1 to September 2001
Form 10-Q
    
    1-4473
    
    11-6-014.25
    
    Sixth Supplemental Indenture dated as of March 1,
2002
    
    4.1 to Registration
Statement Nos.
333-63994 and
333-83398 by means
of February 26, 2002
Form 8-K Report
    
    1-4473
    
    2-28-024.26
    
    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
 110




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Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.1
    
    Two separate
Decommissioning Trust
Agreements (relating to
PVNGS Units 1 and 3,
respectively), each dated
July 1, 1991, between the
Company and Mellon Bank,
N.A., as Decommissioning
Trustee
    
    10.2 to September 1991
Form 10-Q
    
    1-4473
    
    11-14-9110.2
    
    Amendment No. 1 to
Decommissioning Trust
Agreement (PVNGS Unit 1)
dated as of December 1,
1994
    
    10.1 to 1994 Form 10-K
Report
    
    1-4473
    
    3-30-9510.3
    
    Amendment No. 2 to
Decommissioning Trust
Agreement (PVNGS
Unit 1) dated as of
July 1, 1991
    
    10.4 to 1996 Form 10-K
Report
    
    1-4473
    
    3-28-9710.4
    
    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
    
    5-15-0210.5
    
    Amendment No. 4 to the
Decommissioning Trust
Agreement (PVNGS Unit 1),
dated as of December 19,
2003
    
    10.3 to Pinnacle Wests
March 2003 Form 10-K
Report
    
    1-8962
    
    3-15-0410.6
    
    Amendment No. 1 to
Decommissioning Trust
Agreement (PVNGS
Unit 3) dated as of
December 1, 1994
    
    10.2 to 1994 Form 10-K
Report
    
    1-4473
    
    3-30-9510.7
    
    Amendment No. 2 to
Decommissioning Trust
Agreement (PVNGS
Unit 3) dated as of
July 1, 1991
    
    10.6 to 1996 Form 10-K
Report
    
    1-4473
    
    3-28-97
 111




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.8
    
    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
    
    5-15-0210.9
    
    Amendment No. 4 to
Amended and Restated
Decommissioning Trust
Agreement (PVNGS Unit 3), dated as of December 19, 2003
    
    10.5 to 2003 Form 10-K
Report
    
    1-8962
    
    3-15-0410.10
    
    Amended and Restated
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
January 31, 1992, among
the Company, Mellon Bank,
N.A., as Decommissioning
Trustee, and State Street
Bank and Trust Company,
as successor to The First
National Bank of Boston,
as Owner Trustee under two
separate Trust Agreements,
each with a separate Equity
Participant, and as Lessor
under two separate Facility
Leases, each relating to an
undivided interest in PVNGS
Unit 2
    
    10.1 to Pinnacle West
1991 Form 10-K Report
    
    1-8962
    
    3-26-9210.11
    
    First Amendment to Amended
and Restated
Decommissioning Trust
Agreement (PVNGS
Unit 2), dated as of
November 1, 1992
    
    10.2 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9310.12
    
    Amendment No. 2 to
Amended and Restated
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
November 1, 1994
    
    10.3 to 1994 Form 10-K
Report
    
    1-4473
    
    3-30-95
 112




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.13
    
    Amendment No. 3 to
Amended and Restated
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
January 31, 1992
    
    10.1 to June 1996 Form
10-Q Report
    
    1-4473
    
    8-9-9610.14
    
    Amendment No. 4 to
Amended and Restated
Decommissioning Trust
Agreement (PVNGS
Unit 2) dated as of
January 31, 1992
    
    10.5 to 1996 Form 10-K
Report
    
    1-4473
    
    3-28-9710.15
    
    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
    
    5-15-0210.16
    
    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
    
    5-15-0210.17
    
    Amendment No. 7 to the
Decommissioning Trust
Agreement (PVNGS
Unit 2), dated as of
December 19, 2003
    
    10.4 to Pinnacle Wests
Form 10-K Report
    
    1-8962
    
    3-15-0410.18
    
    Asset Purchase and Power
Exchange Agreement dated
September 21, 1990 between
the Company and PacifiCorp,
as amended as of October 11,
1990 and as of July 18, 1991
    
    10.1 to June 1991 Form
10-Q Report
    
    1-4473
    
    8-8-91
 113




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.19
    
    Long-Term Power Transactions Agreement dated
September 21, 1990
between the Company and
PacifiCorp, as amended as
of October 11, 1990 and
as of July 8, 1991
    
    10.2 to June 1991 Form
10-Q Report
    
    1-4473
    
    8-8-9110.20
    
    Contract, dated July 21, 1984,
with DOE providing for the
disposal of nuclear fuel
and/or high-level radioactive
waste, ANPP
    
    10.31 to Pinnacle Wests
Form S-14 Registration
Statement
    
    2-96386
    
    3-13-8510.21
    
    Amendment No. 1 dated
April 5, 1995 to the Long-Term Power Transactions
Agreement and Asset Purchase
and Power Exchange Agreement between PacifiCorp and
the Company
    
    10.3 to 1995 Form 10-K
Report
    
    1-4473
    
    3-29-9610.22
    
    Restated Transmission
Agreement between
PacifiCorp and the Company
dated April 5, 1995
    
    10.4 to 1995 Form 10-K
Report
    
    1-4473
    
    3-29-9610.23
    
    Contract among PacifiCorp,
the Company 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 1995 Form 10-K
Report
    
    1-4473
    
    3-29-9610.24
    
    Reciprocal Transmission
Service Agreement between
the Company and PacifiCorp
dated as of March 2, 1994
    
    10.6 to 1995 Form 10-K
Report
    
    1-4473
    
    3-29-9610.25
    
    Indenture of Lease with
Navajo Tribe of Indians,
Four Corners Plant
    
    5.01 to Form S-7
Registration Statement
    
    2-59644
    
    9-1-77
 114




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.26
    
    Supplemental and Additional
Indenture of Lease, including
amendments and supplements
to original lease with Navajo
Tribe of Indians, Four
Corners Plant
    
    5.02 to Form S-7
Registration Statement
    
    2-59644
    
    9-1-7710.27
    
    Amendment and Supplement
No. 1 to Supplemental and
Additional Indenture of
Lease, Four Corners, dated
April 25,1985
    
    10.36 to Registration
Statement on Form 8-B of
Pinnacle West
    
    1-8962
    
    7-25-8510.28
    
    Application and Grant of
multi-party rights-of-way
and easements, Four
Corners Plant Site
    
    5.04 to Form S-7
Registration Statement
    
    2-59644
    
    9-1-7710.29
    
    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 Registration
Statement on Form 8-B of
Pinnacle West
    
    1-8962
    
    7-25-8510.30
    
    Four Corners Project
Co-Tenancy Agreement
Amendment No. 6
    
    10.7 to Pinnacle West
2000 Form 10-K Report
    
    1-8962
    
    3-14-0110.31
    
    Application and Grant of
Arizona Public Service
Company rights-of-way
and easements, Four
Corners Plant Site
    
    5.05 to Form S-7
Registration Statement
    
    2-59644
    
    9-1-7710.32
    
    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 Registration
Statement on Form 8-B of
Pinnacle West
    
    1-8962
    
    7-25-8510.33
    
    Indenture of Lease, Navajo
Units 1, 2, and 3
    
    5(g) to Form S-7
Registration Statement
    
    2-36505
    
    3-23-70
 115




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.34
    
    Application and Grant of
rights-of-way and easements, Navajo Plant
    
    5(h) to Form S-7
Registration Statement
    
    2-36505
    
    3-23-7010.35
    
    Water Service Contract
Assignment with the United
States Department of
Interior, Bureau of
Reclamation, Navajo Plant
    
    5(l) to Form S-7
Registration Statement
    
    2-39442
    
    3-16-7110.36
    
    Arizona Nuclear Power
Project Participation Agreement, dated August 23, 1973,
among the Company, 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 1988 Form 10-K
Report
    
    1-4473
    
    3-8-8910.37
    
    Amendment No. 13 dated as
of April 22, 1991, to Arizona
Nuclear Power Project Participation Agreement, dated
August 23, 1973, among
the Company, 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 March 1991 Form
10-Q Report
    
    1-4473
    
    5-15-91
 116




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.38
    
    Amendment No. 14, to
Arizona Nuclear Power
Project Participation
Agreement, dated August
23, 1973, among the
Company, 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
    
    10.4 to the Pinnacle West
June 30, 2000 Form 10-Q
Report
    
    1-8962
    
    8-14-0010.39c
    
    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 the Company, as Lessee
    
    4.3 to Form S-3
Registration Statement
    
    33-9480
    
    10-24-8610.40c
    
    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 the Company, as Lessee
    
    10.5 to September 1986
Form 10-Q Report by
means of Amendment No.
1 on December 3, 1986
Form 8
    
    1-4473
    
    12-4-86
 117




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.41c
    
    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 1988 Form 10-K
Report
    
    1-4473
    
    3-8-8910.42c
    
    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 the
Company, as Lessee
    
    10.3 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9310.43
    
    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 the Company, as Lessee
    
    10.1 to November 18, 1986
Form 8-K Report
    
    1-4473
    
    1-20-8710.44
    
    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 the Company, as
Lessee
    
    4.13 to Form S-3
Registration Statement
No. 33-9480 by means of
August 1, 1987 Form 8-K
Report
    
    1-4473
    
    8-24-87
 118




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.45
    
    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 the Company,
as Lessee
    
    10.4 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9310.46a
    
    Directors Deferred
Compensation Plan, as
restated, effective January 1,
1986
    
    10.1 to June 1986 Form
10-Q Report
    
    1-4473
    
    8-13-8610.47a
    
    Second Amendment to the
Arizona Public Service
Company Directors
Deferred Compensation
Plan, effective as of
January 1, 1993
    
    10.2 to 1993 Form 10-K
Report
    
    1-4473
    
    3-30-9410.48a
    
    Third Amendment to the
Arizona Public Service
Company Directors
Deferred Compensation
Plan effective as of
May 1, 1993
    
    10.1 to September 1994
Form 10-Q
    
    1-4473
    
    11-10-9410.49a
    
    Fourth Amendment dated
December 28, 1999 to the
Arizona Public Service
Company Directors
Deferred Compensation
Plan
    
    10.8 to Pinnacle Wests
1999 Form 10-K
    
    1-8962
    
    3-30-00
 119




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.50a
    
    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 1988 Form 10-K
Report
    
    1-4473
    
    3-8-8910.51a
    
    Third Amendment to the
Arizona Public Service
Company Deferred
Compensation Plan, effective
as of January 1, 1993
    
    10.3 to 1993 Form 10-K
Report
    
    1-4473
    
    3-30-9410.52a
    
    Fourth Amendment to the
Arizona Public Service
Company Deferred
Compensation Plan effective
as of May 1, 1993
    
    10.2 to September 1994
Form 10-Q Report
    
    1-4473
    
    11-10-9410.53a
    
    Fifth Amendment to the
Arizona Public Service
Company Deferred
Compensation Plan
    
    10.3 to 1997 Form 10-K
Report
    
    1-4473
    
    3-28-9710.54a
    
    Sixth Amendment to
Arizona Public Service
Company Deferred
Compensation Plan
    
    10.8 to Pinnacle West
2000 Form 10-K Report
    
    1-8962
    
    3-14-0110.55a
    
    Schedules of William J. Post
    
    10.2 to Pinnacle West
    
    1-8962
    
    3-31-03and Jack E. Davis to
Arizona Public Service
Company Deferred
Compensation Plan, as
amended
    
    Form 10-K Report
 120




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.56a
    
    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 1995 Form 10-K
Report
    
    1-4473
    
    3-29-9610.57a
    
    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
    
    10.6 to Pinnacle Wests
1999 Form 10-K Report
    
    1-8962
    
    3-30-0010.58a
    
    Second Amendment effective
as of January 1, 2000, to the
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and
El Dorado Investment
Company Deferred Compensation Plan
    
    10.10 to Pinnacle Wests
1999 Form 10-K Report
    
    1-8962
    
    3-30-0010.59a
    
    Third Amendment to the
Pinnacle West Capital
Corporation, Arizona Public
Service Company, SunCor
Development Company and
El Dorado Investment
Company Deferred
Compensation Plan
    
    10.3 to Pinnacle West's
March 2003 Form 10-Q
Report
    
    1-8962
    
    5-15-0310.60
    
    Fourth Amendment to the Pinnacle
West Capital Corporation, Arizona Public Service Company, SunCor
Development Company and El Dorado Investment Company Deferred
Compensation Plan
    
    10.6 to Pinnacle West's 2003 Form
10-K Report
    
    1-8962
    
    3-15-04

10.61a
    
    Pinnacle West Capital
Corporation Supplemental
Excess Benefit Retirement
Plan, as amended and
restated, dated December 7,
1999
    
    10.13 to Pinnacle Wests
1999 Form 10-K Report
    
    1-8962
    
    3-30-00
 121




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.62a
    
    First Amendment to the
Pinnacle West Capital
Corporation Supplemental
Excess Benefit Retirement
Plan
    
    10.7 to Pinnacle Wests
2001 Form 10-K Report
    
    1-8962
    
    3-27-0210.63a
    
    Pinnacle West Capital Corporation
Supplemental Excess Benefit Retirement Plan, amended and restated as
of January 1, 2003
    
    10.7 to Pinnacle Wests
2003 Form 10-K Report
    
    1-8962
    
    3-15-0410.64a
    
    Second Amendment to the
Pinnacle West Capital
Corporation Supplemental
Excess Benefit Retirement
Plan
    
    10.8 to Pinnacle Wests
2001 Form 10-K Report
    
    1-8962
    
    3-27-0210.65a
    
    Pinnacle West Capital
Corporation and Arizona
Public Service Company
Directors Retirement Plan
effective as of January 1,
1995
    
    10.7 to 1994 Form 10-K
Report
    
    1-4473
    
    3-30-9510.66a
    
    Pinnacle West Capital
Corporation and Arizona
Public Service Company
Directors Retirement Plan,
as amended and restated
on June 21, 2000
    
    99.2 to Pinnacle Wests
Registration Statement on
Form S-8 No. 333-40796
    
    1-8962
    
    7-3-0010.67a
    
    Arizona Public Service
Company Director
Equity Plan
    
    10.1 to September 1997
Form 10-K Report
    
    1-4473
    
    11-12-9710.68a
    
    Letter Agreement dated
December 21, 1993, between
the Company and William L.
Stewart
    
    10.6 to 1994 Form 10-K
Report
    
    1-4473
    
    3-30-9510.69a
    
    Letter Agreement dated
August 16, 1996 between
the Company and
William L. Stewart
    
    10.8 to 1996 Form 10-K
Report
    
    1-4473
    
    3-28-9710.70a
    
    Letter Agreement between
the Company and
William L. Stewart
    
    10.2 to September 1997
Form 10-Q Report
    
    1-4473
    
    11-12-97
 122




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.71a
    
    Letter Agreement dated
December 13, 1999 between
the Company and
William L. Stewart
    
    10.9 to Pinnacle Wests
1999 Form 10-K Report
    
    1-8962
    
    3-30-0010.72a
    
    Amendment to Letter
Agreement, effective as of
January 1, 2002, between
APS and William L. Stewart
    
    10.1 to Pinnacle Wests
June 2002 Form 10-Q
Report
    
    1-8962
    
    8-13-0210.73a
    
    Letter Agreement dated as
of January 1, 1996 between
the Company and Robert G.
Matlock & Associates, Inc.
for consulting services
    
    10.8 to 1995 Form 10-K
Report
    
    1-4473
    
    3-29-9610.74a
    
    Letter Agreement dated
October 3, 1997 between
the Company and James M.
Levine
    
    10.17 to Pinnacle Wests
1999 Form 10-K Report
    
    1-8962
    
    3-30-0010.75a
    
    Summary of James M.
Levine Retirement
Benefits
    
    10.2 to Pinnacle Wests
March 2002 Form
10-Q Report
    
    1-8962
    
    5-15-0210.76a
    
    Employment Agreement,
effective as of October 1,
2002, between APS and
James M. Levine
    
    10.1 to Pinnacle Wests
November 2002 Form
10-Q
    
    1-8962
    
    11-14-0210.77a
    
    Employment Agreement
dated February 27, 2003
between APS and James
M. Levine
    
    10.1 to Pinnacle Wests
March 2003 Form 10-Q
Report
    
    1-8962
    
    5-15-0310.78a
    
    Letter Agreement dated
June 28, 2001 between
Pinnacle West Capital
Corporation and Steve
Wheeler
    
    10.4 to Pinnacle Wests
2002 Form 10-K Report
    
    1-8962
    
    3-31-03
 123




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.79ad
    
    Key Executive Employment
and Severance Agreement
between Pinnacle West and
certain executive officers of
Pinnacle West and its
subsidiaries
    
    10.1 to Pinnacle Wests
June 1999 Form 10-Q
Report
    
    1-8962
    
    8-16-9910.80a
    
    Pinnacle West Capital
Corporation Stock Option
and Incentive Plan
    
    10.1 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9310.81a
    
    First Amendment dated
December 7, 1999 to the
Pinnacle West Capital
Corporation Stock Option
and Incentive Plan
    
    10.11 to Pinnacle Wests
1999 Form 10-K Report
    
    1-8962
    
    3-30-0010.82a
    
    Pinnacle West Capital
Corporation 1994 Long-
Term Incentive Plan
effective as of
March 23, 1994
    
    A to the Proxy Statement
for the Plan Report
Pinnacle West 1994
Annual Meeting of
Shareholders
    
    1-8962
    
    4-16-9410.83a
    
    First Amendment dated
December 7, 1999, to the
Pinnacle West Capital
Corporation 1994 Long-
Term Incentive Plan
    
    10.12 to Pinnacle Wests
1999 Form 10-K Report
    
    1-8962
    
    3-30-0010.84a
    
    Pinnacle West Capital
Corporation 2002 Long-
Term Incentive Plan
    
    10.5 to Pinnacle Wests
2002 Form 10-K Report
    
    1-8962
    
    3-31-0310.85a
    
    Trust for the Pinnacle West
Capital Corporation, Arizona
Public Service Company
and SunCor Development
Company Deferred
Compensation Plans
dated August 1, 1996
    
    10.14 to Pinnacle Wests
1999 Form 10-K Report
    
    1-8962
    
    3-30-00
 124




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.86a
    
    First Amendment dated
December 7, 1999, to the
Trust for the Pinnacle West
Capital Corporation, Arizona
Public Service Company and
SunCor Development
Company Deferred
Compensation Plans
    
    10.15 to Pinnacle Wests
1999 Form 10-K Report
    
    1-8962
    
    3-30-0010.87a
    
    2004 Officer Incentive
Plan
    
    10.1 to Pinnacle Wests
2003 Form 10-K Report
    
    1-8962
    
    3-15-0410.88a
    
    2004 CEO Variable
Incentive Plan
    
    10.2 to Pinnacle Wests
2003 Form 10-K Report
    
    1-8962
    
    3-15-0410.89
    
    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 1991 Form 10-K
Report
    
    1-4473
    
    3-19-9210.90
    
    Agreement for the Sale and
Purchase of Wastewater
Effluent with City of
Tolleson and Salt River
Agricultural Improvement
and Power District, dated
June 12, 1981,including
Amendment No. 1 dated
as of November 12, 1981
and Amendment No. 2
dated as of June 4, 1986
    
    10.4 to 1991 Form 10-K
Report
    
    1-4473
    
    3-19-9210.91
    
    Territorial Agreement
between the Company
and Salt River Project
    
    10.1 to March 1998
Form 10-Q Report
    
    1-4473
    
    5-15-9810.92
    
    Power Coordination
Agreement between
the Company and Salt
River Project
    
    10.2 to March 1998
Form 10-Q Report
    
    1-4473
    
    5-15-98
 125




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective10.93
    
    Memorandum of Agreement
between the Company and
Salt River Project
    
    10.3 to March 1998
Form 10-Q Report
    
    1-4473
    
    5-15-9810.94
    
    Addendum to Memorandum
of Agreement between the
Company and Salt River
Project dated as of May
19, 1998
    
    10.2 to May 19, 1998
Form 8-K Report
    
    1-4473
    
    6-26-9899.1
    
    Collateral Trust Indenture
among PVNGS II Funding
Corp., Inc., the Company and
Chemical Bank, as Trustee
    
    4.2 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9399.2
    
    Supplemental Indenture to
Collateral Trust Indenture
among PVNGS II Funding
Corp., Inc., the Company and
Chemical Bank, as Trustee
    
    4.3 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9399.3c
    
    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, the Company, and
the Equity Participant named
therein
    
    28.1 to September 1992
Form 10-Q Report
    
    1-4473
    
    11-9-92
 126




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective99.4c
    
    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, the Company, and
the Equity Participant named
therein
    
    10.8 to September 1986
Form 10-Q Report by
means of Amendment No.
1, on December 3, 1986
Form 8
    
    1-4473
    
    12-4-8699.5c
    
    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, the
Company, and the Equity
Participant named therein
    
    28.4 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-93
 127




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective99.6c
    
    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 Form S-3
Registration Statement
    
    33-9480
    
    10-24-8699.7c
    
    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 September 1986
Form 10-Q Report by
means of Amendment No.
1 on December 3, 1986
Form 8
    
    1-4473
    
    12-4-8699.8c
    
    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 Indenture Trustee
    
    4.4 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9399.9c
    
    Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
    
    28.3 to Form S-3
Registration Statement
    
    33-9480
    
    10-24-86
 128




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective99.10c
    
    Amendment No. 1, dated
as of November 1, 1986, to
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
    
    10.10 to September 1986
Form 10-Q Report by
means of Amendment No.
1 on December 3, 1986
Form 8
    
    1-4473
    
    12-4-8699.11c
    
    Amendment No. 2, dated
as of March 17, 1993, to
Assignment, Assumption and
Further Agreement, dated as
of August 1, 1986, between
the Company and State Street
Bank and Trust Company, as
successor to The First
National Bank of Boston, as
Owner Trustee
    
    28.6 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9399.12
    
    Participation Agreement,
dated as of December 15,
1986, among PVNGS
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
under a Trust Indenture,
the Company, and the
Owner Participant named
therein
    
    28.2 to September 1992
Form 10-Q Report
    
    1-4473
    
    11-9-92
 129




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective99.13
    
    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, the Company, and
the Owner Participant named
therein
    
    28.20 to Form S-3
Registration Statement
No. 33-9480 by means of a
November 6, 1986 Form
8-K Report
    
    1-4473
    
    8-10-8799.14
    
    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, the
Company, and the Owner
Participant named therein
    
    28.5 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9399.15
    
    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 November 18, 1986
Form 8-K Report
    
    1-4473
    
    1-20-87
 130




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective99.16
    
    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 Form S-3
Registration Statement
No. 33-9480 by means of
August 1, 1987 Form 8-K
Report
    
    1-4473
    
    8-24-8799.17
    
    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 Indenture
Trustee
    
    4.5 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9399.18
    
    Assignment, Assumption and
Further Agreement, dated as
of December 15, 1986,
between the Company and
State Street Bank and Trust
Company, as successor to The
First National Bank of
Boston, as Owner Trustee
    
    10.5 to November 18, 1986
Form 8-K Report
    
    1-4473
    
    1-20-87
 131




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective99.19
    
    Amendment No. 1, dated
as of March 17, 1993, to
Assignment, Assumption
and Further Agreement,
dated as of December 15,
1986, between the Company
and State Street Bank and
Trust Company, as successor
to The First National Bank of
Boston, as Owner Trustee
    
    28.7 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9399.20c
    
    Indemnity Agreement dated
as of March 17, 1993 by the
Company
    
    28.3 to 1992 Form 10-K
Report
    
    1-4473
    
    3-30-9399.21
    
    Extension Letter, dated as of
August 13, 1987, from the
signatories of the
Participation Agreement to
Chemical Bank
    
    28.20 to Form S-3
Registration Statement
No. 33-9480 by means of a
November 6, 1986 Form
8-K Report
    
    1-4473
    
    8-10-8799.22
    
    Rate Reduction Agreement
dated December 4, 1995
between the Company and
the ACC Staff
    
    10.1 to December 4, 1995
Form 8-K Report
    
    1-4473
    
    12-14-9599.23
    
    Arizona Corporation
Commission Order
dated April 24, 1996
    
    10.1 to March 1996
Form 10-Q Report
    
    1-4473
    
    5-14-9699.24
    
    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 1996 Form 10-K
Report
    
    1-4473
    
    3-28-9799.25
    
    Retail Electric Competition
Rules
    
    10.1 to June 1998
Form 10-Q Report
    
    1-4473
    
    8-14-98
 132




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##### Table of Contents



Exhibit No.
    
    Description
    
    Originally Filed as Exhibit:
    
    File No.b
    
    Date Effective99.26
    
    Arizona Corporation
Commission Order,
Decision No. 61973, dated
October 6, 1999, approving
our Settlement Agreement
    
    10.1 to September 1999
10-Q Report
    
    1-4473
    
    11-15-9999.27
    
    Arizona Corporation
Commission Order,
Decision No. 61969, dated
September 29, 1999, including the Retail Electric
Competition Rules
    
    10.2 to September 1999
10-Q Report
    
    1-4473
    
    11-15-9999.28
    
    Addendum to Settlement
Agreement
    
    10.1 to Pinnacle West
September 2000 10-Q
    
    1-8962
    
    11-14-0099.29
    
    ACC Opinion and Order
dated September 10, 2002,
Decision No. 65154 (Track
A Order)
    
    99.1 to Pinnacle Wests
September 10, 2002
Form 8-K Report
    
    1-8962
    
    9-17-0299.30
    
    Arizona Public Service
Company Application filed
with the Arizona
Corporation Commission on
September 16, 2002
    
    99.2 to Pinnacle Wests
September 10, 2002
Form 8-K Report
    
    1-8962
    
    9-17-0299.31
    
    Track A Appeals Issues 
Principles for Resolution
    
    99.1 to Pinnacle Wests
November 15, 2002
Form 8-K Report
    
    1-8962
    
    12-16-0299.32
    
    ACC Decision No. 65796
dated April 4, 2003
(Financing Order)
    
    99.3 to Pinnacle Wests
March 2003 Form 10-Q
Report
    
    1-8962
    
    5-15-03
   aManagement contract or compensatory plan or arrangement to be filed as an
exhibit pursuant to Item 14(c) of Form 10-K.bReports 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.cAn 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.dAdditional 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. 133




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##### Table of Contents



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 the earnings outlook of Pinnacle
West and slides presented at Pinnacle West analysts and investors meetings
(Item 5, Item 7 and Item 9). Report dated November 4, 2003 regarding the ACC approval of the issuance
of a rate adjustment mechanism order (Item 5). Report
dated December 31, 2003 containing exhibits comprised of
Pinnacle Wests financial information, earnings variance explanations and an earnings news release  (Item
7, Item 9 and Item 12). Report dated January 8, 2004 regarding a delay in the schedule for the hearing for our 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 February 3, 2004 regarding the ACC Staffs and RUCOs initial
written testimony filed with the ACC (Item 5). 134




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##### Table of Contents



SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY
(Registrant)Date: March 15, 2004
    
    /s/ Jack E. Davis(Jack E. Davis, President and ChiefExecutive 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
    
    Director
    
    March 15, 2004(William J. Post, Chairmanof the Board of Directors )/s/ Jack E. Davis
    
    Principal Executive Officer
    
    March 15, 2004and Director(Jack E. Davis, Presidentand Chief Executive Officer)/s/ Donald E. Brandt
    
    Principal Financial Officer
    
    March 15, 2004(Donald E. Brandt,Executive Vice President,and Chief Financial Officer)/s/ Chris N. Froggatt
    
    Principal Accounting Officer
    
    March 15, 2004(Chris N. Froggatt,Vice President and Controller)
 135




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##### Table of Contents



Signature
    
    Title
    
    Date/s/ Edward N. Basha, Jr.
    
    Director
    
    March 15, 2004(Edward N. Basha, Jr.)/s/ Michael L. Gallagher
    
    Director
    
    March 15, 2004(Michael L. Gallagher)/s/ Pamela Grant
    
    Director
    
    March 15, 2004(Pamela Grant)/s/ Roy A. Herberger, Jr.
    
    Director
    
    March 15, 2004(Roy A. Herberger, Jr.)/s/ Martha O. Hesse
    
    Director
    
    March 15, 2004(Martha O. Hesse)/s/ William S. Jamieson, Jr.
    
    Director
    
    March 15, 2004(William S. Jamieson, Jr.)/s/ Humberto S. Lopez
    
    Director
    
    March 15, 2004(Humberto S. Lopez)Director
    
    March 15, 2004(Robert G. Matlock)/s/ Kathryn L. Munro
    
    Director
    
    March 15, 2004(Kathryn L. Munro)/s/ Bruce J. Nordstrom
    
    Director
    
    March 15, 2004(Bruce J. Nordstrom)
 136




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##### Table of Contents



INDEX TO EXHIBITS Exhibit No.
    
    Description3.1
    
    
    
    Bylaws, amended as of January 21, 200412.1
    
    
    
    Computation of Ratio of Earnings to Fixed Charges23.1
    
    
    
    Consent of Deloitte & Touche LLP31.1
    
    
    
    Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a)
and Rule 15d  14(a) of the Securities Exchange Act, as amended31.2
    
    
    
    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 amended32.1
    
    
    
    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 200299.1
    
    
    
    Risk Factors
 For a description of the Exhibits incorporated in this filing by reference, see
Part IV, Item 14.