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================================================================================

                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                   ----------

                                    FORM 10-K

(Mark One)
[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
     ACT OF 1934

     FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

                                       OR

[ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934

     FOR THE TRANSITION PERIOD FROM ______ TO ______

                          COMMISSION FILE NUMBER 1-8962

                        PINNACLE WEST CAPITAL CORPORATION
             (Exact name of registrant as specified in its charter)

                ARIZONA                                  86-0512431
     (State or other jurisdiction           (I.R.S. Employer Identification No.)
   of incorporation or organization)

400 North Fifth Street, P.O. Box 53999                 (602) 250-1000
      Phoenix, Arizona 85072-3999              (Registrant's telephone number,
    (Address of principal executive                 including area code)
               offices,
          including zip code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

================================================================================
                                                        Name Of Each Exchange On
Title Of Each Class                                          Which Registered
--------------------------------------------------------------------------------
   Common Stock,                                         New York Stock Exchange
   No Par Value                                          Pacific Stock Exchange
================================================================================

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None.

     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

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

     Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [ ]

     State the aggregate market value of the voting and non-voting common equity
held by non-affiliates, computed by reference to the price at which the common
equity was last sold, or the average bid and asked price of such common equity,
as of the last business day of the registrant's most recently completed second
fiscal quarter: $3,348,326,875 as of June 28, 2002

================================================================================

                       DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant's definitive Proxy Statement relating to its Annual
Meeting of Shareholders to be held on May 21, 2003 are incorporated by reference
into Part III hereof.

================================================================================
<PAGE>
                                TABLE OF CONTENTS

                                                                            PAGE

GLOSSARY.....................................................................  1

PART I
  Item 1.  Business..........................................................  4
  Item 2.  Properties........................................................ 22
  Item 3.  Legal Proceedings................................................. 27
  Item 4.  Submission of Matters to a Vote of Security Holders............... 27
  Supplemental Item.
           Executive Officers of the Registrant.............................. 28

PART II
  Item 5.  Market for Registrant's Common Stock and Related
             Stockholder Matters............................................. 30
  Item 6.  Selected Consolidated Financial Data.............................. 31
  Item 7.  Management's Discussion and Analysis of Financial Condition
             and Results of Operations....................................... 35
  Item 7A. Quantitative and Qualitative Disclosures about Market Risk........ 71
  Item 8.  Financial Statements and Supplementary Data....................... 73
  Item 9.  Changes in and Disagreements with Accountants on Accounting
             and Financial Disclosure........................................139

PART III
  Item 10. Directors and Executive Officers of the Registrant................139
  Item 11. Executive Compensation............................................139
  Item 12. Security Ownership of Certain Beneficial Owners and Management
           and Related Stockholder Matters...................................139
  Item 13. Certain Relationships and Related Transactions....................141
  Item 14. Controls and Procedures...........................................142

PART IV
  Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..142

SIGNATURES...................................................................173

                                       i
<PAGE>
                                    GLOSSARY

ACC - Arizona Corporation Commission

ACC Staff - Staff of the Arizona Corporation Commission

ADEQ - Arizona Department of Environmental Quality

AISA - Arizona Independent Scheduling Administrator

ALJ - Administrative Law Judge

ANPP - Arizona Nuclear Power Project, also known as Palo Verde

APS - Arizona Public Service Company, a subsidiary of the Company

APS Energy Services - APS Energy Services Company, Inc., a subsidiary of the
Company

CC&N - Certificate of Convenience and Necessity

Cholla - Cholla Power Plant

Citizens - Citizens Communications Company

Clean Air Act - the Clean Air Act, as amended

Company - Pinnacle West Capital Corporation

CPUC - California Public Utility Commission

DOE - United States Department of Energy

EITF - the FASB's Emerging Issues Task Force

El Dorado - El Dorado Investment Company, a subsidiary of the Company

EPA - United States Environmental Protection Agency

ERMC - the Company's Energy Risk Management Committee

FASB - Financial Accounting Standards Board

FERC - United States Federal Energy Regulatory Commission

FIN - FASB Interpretation

Financing Application - APS application filed with the ACC on September 16, 2002

FIP - Federal Implementation Plan

Fitch - Fitch, Inc.

Four Corners - Four Corners Power Plant

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

Interim Financing Application - APS application filed with the ACC on November
8, 2002

IRS - United States Internal Revenue Service

ISO - California Independent System Operator

kW - kilowatt, one thousand watts
<PAGE>
kWh - kilowatt-hour, one thousand watts per hour

Moody's - Moody's Investors Service

MW - megawatt, one million watts

MWh - megawatt-hours, one million watts per hour

NAC - NAC International Inc., a subsidiary of El Dorado

Native Load - retail and wholesale sales supplied under traditional cost-based
rate regulation

1999 Settlement Agreement - comprehensive settlement agreement related to the
implementation of retail electric competition

NOV - Notice of Violation

NRC - United States Nuclear Regulatory Commission

Nuclear Waste Act - Nuclear Waste Policy Act of 1982, as amended

OCI - other comprehensive income

Palo Verde - Palo Verde Nuclear Generating Station

PG&E - PG&E Corp.

Pinnacle West - Pinnacle West Capital Corporation, the Company

Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the
Company

PRP - potentially responsible parties under Superfund

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

SMD - standard market design

SNWA - Southern Nevada Water Authority

SPE - special-purpose entity

Standard & Poor's - Standard & Poor's Corporation

SunCor - SunCor Development Company, a subsidiary of the Company

Superfund - Comprehensive Environmental Response, Compensation and Liability Act

System - non-trading energy related activities

T&D - transmission and distribution

                                       2
<PAGE>
Track A Order - ACC order dated September 10, 2002 regarding generation asset
transfers and related issues

Track B Order -ACC order dated March 14, 2003 regarding competitive solicitation
requirements for power purchases by Arizona's investor-owned electric utilities

Trading - energy-related activities entered into with the objective of
generating profits on changes in market prices

VIE - variable interest entity

WestConnect - WestConnect RTO, LLC, a proposed RTO to be formed by owners of
electric transmission lines in the southwestern United States

                                       3
<PAGE>
                                     PART I

                                ITEM 1. BUSINESS

                                 CURRENT STATUS

GENERAL

     We were incorporated in 1985 under the laws of the State of Arizona and own
all of the outstanding equity securities of APS. APS is an 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 owned by APS. APS also generates, sells and
delivers electricity to wholesale customers in the western United States.

     Our other major subsidiaries are:

     *    Pinnacle West Energy, through which we conduct our competitive
          electricity generation operations;

     *    APS Energy Services, which provides competitive commodity-related
          energy services (such as direct access commodity contracts, energy
          procurement and energy supply consultation) and energy-related
          products and services (such as energy master planning, energy use
          consultation and facility audits, cogeneration analysis and
          installation and project management) to commercial, industrial and
          institutional retail customers in the western United States;

     *    SunCor, a developer of residential, commercial and industrial real
          estate projects in Arizona, New Mexico and Utah; and

     *    El Dorado, which owns a majority interest in NAC (specializing in
          spent nuclear fuel technology) and holds miscellaneous small
          investments, including interests in Arizona community-based ventures.

     We discuss each of these subsidiaries in greater detail below.

MARKETING AND TRADING

     In early 2003, we moved our marketing and trading division from Pinnacle
West to APS for future marketing and trading activities (existing wholesale
contracts will remain at Pinnacle West) as a result of the ACC's Track A Order
prohibiting the previously required transfer of APS' generating assets to
Pinnacle West Energy (see "Overview of Arizona Regulatory Developments" below).
The marketing and trading division sells, in the wholesale market, APS and
Pinnacle West Energy generation output that is not needed for APS' Native Load,
which includes loads for retail customers and traditional cost-of-service
wholesale customers. The division focuses primarily on managing APS' purchased
power and fuel risks in connection with its costs of serving retail customer
energy requirements. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Factors Affecting Our Financial Outlook"
in Item 7 for a discussion of APS' implementation of an

                                       4
<PAGE>
ACC-mandated process by which APS must competitively procure energy.
Additionally, the marketing and trading division, subject to specific
parameters, markets, hedges and trades in electricity, fuels and emission
allowances and credits. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations" in Item 7 for information about the
historical and prospective contribution of the marketing and trading activities
to our financial results.

BUSINESS SEGMENTS

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

     *    our regulated electricity segment (76% of operating revenues in 2002),
          which consists of regulated traditional retail and wholesale
          electricity businesses and related activities, and includes
          electricity transmission, distribution and generation;

     *    our marketing and trading segment (12% of operating revenues in 2002),
          which consists of our competitive energy business activities,
          including wholesale marketing and trading and APS Energy Services'
          commodity-related energy services; and

     *    our real estate segment (9% of operating revenues in 2002), which
          consists of SunCor's real estate development and investment
          activities.

     See Note 17 of Notes to Consolidated Financial Statements in Item 8 for
financial information about our business segments.

EMPLOYEES

     At December 31, 2002, we employed about 7,200 people, including the
employees of our subsidiaries. Of these employees, about 5,100 were employees of
our major subsidiary, APS, and employees assigned to jointly-owned generating
facilities for which APS serves as the generating facility manager. About 2,100
people were employed by Pinnacle West and our other subsidiaries. Our principal
executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004
(telephone 602-250-1000).

OVERVIEW OF ARIZONA REGULATORY DEVELOPMENTS

     As discussed in "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Factors Affecting Our Financial Outlook"
in Item 7, we believe pending Arizona regulatory matters are among the key
factors affecting our financial outlook.

     GENERAL

     On September 21, 1999, the ACC approved Rules that provided a framework for
the introduction of retail electric competition in Arizona. On September 23,
1999, the ACC approved a comprehensive settlement agreement among APS and
various parties related to the implementation of retail electric competition in
Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was
required to transfer all of its competitive electric assets and services to an
unaffiliated party or parties or to a separate corporate affiliate or affiliates
no later than December 31, 2002. Consistent with that requirement, APS had been
addressing the legal and regulatory requirements necessary to complete the
transfer of its generation assets to Pinnacle West Energy on or before that

                                       5
<PAGE>
date. On September 10, 2002, the ACC issued the Track A Order, which, among
other things, directed APS not to transfer its generation assets to Pinnacle
West Energy. See Note 3 of Notes to Consolidated Financial Statements in Item 8
for additional information about the 1999 Settlement Agreement, the Rules
(including legal challenges to the Rules) and the Track A Order.

     APS FINANCING APPLICATION

     On September 16, 2002, APS filed an application with the ACC requesting the
ACC to allow APS to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to the Company; to guarantee up to $500 million of
Pinnacle West Energy's or the Company's debt; or a combination of both, not to
exceed $500 million in the aggregate. In its application, APS stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between APS and Pinnacle West Energy under
different regulatory regimes result in Pinnacle West Energy being unable to
attain investment-grade credit ratings. This, in turn, precludes Pinnacle West
Energy from accessing capital markets to refinance the bridge financing that we
provided to fund the construction of Pinnacle West Energy generation assets or
from effectively competing in the wholesale markets. On March 27, 2003, the ACC
authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up
to $500 million of Pinnacle West Energy debt or a combination of both, not to
exceed $500 million in the aggregate. See "ACC Applications" in Note 3 of Notes
to Consolidated Financial Statements in Item 8 for additional information.

     COMPETITIVE PROCUREMENT PROCESS

     On September 10, 2002, the ACC issued an order that, among other things,
established a requirement that APS competitively procure certain power
requirements. On March 14, 2003, the ACC issued the Track B Order, which
documented the decision made by the ACC at its open meeting on February 27,
2003, addressing this requirement. Under the order, APS will be required to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, APS will be required to solicit competitive
bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or
approximately 20% of APS' total retail energy requirements. The bid amounts are
expected to increase in 2004 and 2005 based largely on growth in APS' retail
load and APS' retail energy sales. The Track B Order also confirmed that it was
"not intended to change the current rate base status of [APS'] existing assets."
The order recognizes APS' right to reject any bids that are unreasonable,
uneconomical or unreliable.

     APS expects to issue requests for proposals in March 2003 and to complete
the selection process by June 1, 2003. Pinnacle West Energy will be eligible to
bid to supply APS' electricity requirements. See "Track B Order" in Note 3 of
Notes to Consolidated Financial Statements in Item 8 for additional information.

     APS GENERAL RATE CASE

     As required by the 1999 Settlement Agreement, on or before June 30, 2003,
APS will file a general rate case with the ACC. In this rate case, APS will
update its cost of service and rate design. In addition, APS expects to seek:

                                       6
<PAGE>
     *    rate base treatment of certain power plants currently owned by
          Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West
          Phoenix Units 4 and 5 and Saguaro Unit 3);

     *    recovery of the $234 million pretax asset write-off recorded by APS as
          a result of the 1999 Settlement Agreement; and

     *    recovery of costs incurred by APS in preparation for the previously
          required transfer of generation assets to Pinnacle West Energy.

We assume that the ACC will make a decision in this general rate case by the end
of 2004.

AVAILABLE INFORMATION

     We make available free of charge on or through our Internet website
(www.pinnaclewest.com) our Annual Report on Form 10-K, Quarterly Reports on Form
10-Q, Current Reports on Form 8-K and, if applicable, amendments to those
reports filed or furnished pursuant to Section 13(a) of the Securities Exchange
Act of 1934 as soon as reasonably practicable after we electronically file such
material with, or furnish it to, the SEC. The information on our website is not
part of this report.

FORWARD-LOOKING STATEMENTS

     This document contains forward-looking statements based on current
expectations and we assume no obligation to update these statements or make any
further statements on any of these issues, except as required by applicable law.
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
the ongoing restructuring of the electric industry, including the introduction
of retail electric competition in Arizona and decisions impacting wholesale
competition; the outcome of regulatory and legislative proceedings relating to
the restructuring; state and federal regulatory and legislative decisions and
actions, including price caps and other market constraints imposed by the FERC;
regional economic and market conditions, including the California energy
situation and 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; weather
variations affecting local and regional customer energy usage; the effect of
conservation programs on energy usage; power plant performance; the successful
completion of our generation construction program; regulatory issues associated
with generation construction, such as permitting and licensing; our ability to
compete successfully outside traditional regulated markets (including the
wholesale market); our ability to manage our marketing and trading activities
and the use of derivative contracts in our business; technological developments
in the electric industry; the performance of the stock market, which affects the
amount of our required contributions to our pension plan and nuclear
decommissioning trust funds; the strength of the real estate market in SunCor's
market areas, which include Arizona, New Mexico and Utah; and other
uncertainties, all of which are difficult to predict and many of which are
beyond our control.

                                       7
<PAGE>
                           REGULATION AND COMPETITION

RETAIL

     The ACC regulates APS' retail electric rates and its issuance of
securities. The ACC must also approve any transfer of APS' utility property and
certain transactions between APS and affiliated parties. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Factors Affecting Our Financial Outlook" in Item 7 and Note 3 of Notes to
Consolidated Financial Statements in Item 8 for a discussion of the status of
electric industry restructuring in Arizona.

     APS is subject to varying degrees of competition from other utilities in
Arizona (such as Tucson Electric Power Company, Southwest Gas Corporation and
Citizens Communications Company) as well as cooperatives, municipalities,
electrical districts and similar types of governmental organizations
(principally Salt River Project). APS also faces competition from low-cost
hydroelectric power and parties that have access to low-priced preferential
federal power and other subsidies. In addition, some customers, particularly
industrial and large commercial customers, may own and operate facilities to
generate their own electric energy requirements. Although some very limited
retail competition existed in APS' service area in 1999 and 2000, there are
currently no active retail competitors providing unbundled energy or other
utility services to APS' customers. As a result, we cannot predict when, and the
extent to which, additional competitors will re-enter APS' service territory. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete
effectively in a restructured industry.

WHOLESALE

     GENERAL

     The FERC regulates rates for wholesale power sales and transmission
services. During 2002, approximately 20% of our electric operating revenues
resulted from such sales and services. In early 2003, we moved our marketing and
trading division from Pinnacle West to APS for all future marketing and trading
activities (existing wholesale contracts will remain at Pinnacle West) as a
result of the ACC's Track A Order prohibiting the previously required transfer
of APS' generating assets to Pinnacle West Energy (see "Overview of Arizona
Regulatory Developments" above). The marketing and trading division sells, in
the wholesale market, APS and Pinnacle West Energy generation output that is not
needed for APS' Native Load and, in doing so, competes with other utilities,
power marketers and independent power producers. The division focuses primarily
on managing APS' purchased power and fuel risks in connection with its costs of
serving retail customer energy requirements. See "Track B Order" in Note 3 of
Notes to Consolidated Financial Statements in Item 8 for information regarding
an ACC-mandated process by which APS must competitively procure energy. See Note
11 of Notes to Consolidated Financial Statements in Item 8 for information
regarding our generation construction plans.

     REGIONAL TRANSMISSION ORGANIZATIONS

     On December 20, 1999, the FERC issued its Order No. 2000 regarding regional
transmission organizations. In its order, the FERC set minimum characteristics
and functions that must be met by utilities that participate in RTOs. The
characteristics for an acceptable RTO include independence from market

                                       8
<PAGE>
participants, operational control over a region large enough to support
efficient and nondiscriminatory markets and exclusive authority to maintain
short-term reliability.

     As stated in Order No. 2000, the FERC believes that a number of benefits
will result from the formation of RTOs throughout the country, and it has moved
aggressively to ensure that all public utilities participate in an RTO or
demonstrate why such participation is not feasible. According to the FERC, the
benefits it expects to result from RTO formation include: (1) improvements in
transmission system operations with resulting enhancements to inter-regional
trade, congestion management, reliability and coordination; and (2) improved
performance of energy markets, including greater incentives for efficient
generator performance and enhanced potential for demand response.

     On October 16, 2001, APS and other owners of electric transmission lines in
the Southwest filed with the FERC a request for a declaratory order confirming
that their proposal to form WestConnect RTO, LLC would satisfy the FERC's
requirements for the formation of an RTO. APS and the other filing parties have
agreed to fund the start-up of WestConnect's operations, which are subject to
FERC approval. WestConnect has been structured as a for-profit RTO and evolved
from DesertSTAR, a not-for-profit corporation in which APS participated, which
was originally designed to serve as an RTO for the southwestern United States.
The success of WestConnect will be largely dependent on participation by all
major transmission owners in the Southwest. The success is also dependent on
support from the affected state regulatory commissions.

     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. In its order, the FERC also stated that its approval of various
WestConnect provisions addressed in the order would not be overturned or
affected by the final rule the FERC intends to ultimately adopt in response to
its July 31, 2002 Notice of Proposed Rulemaking regarding a standard market
design for the electric utility industry (see "Federal" in Note 3 of Notes to
Consolidated Financial Statements in Item 8 for additional information regarding
the Notice of Proposed Rulemaking). On November 12, 2002, APS and other owners
filed a request for rehearing and clarification on portions of the October 10,
2002 order.

     On December 23, 2002, the FERC issued its order on rehearing. In it, the
FERC clarified the RTO elements that it had approved. In its order, the FERC
stated that it envisions the Seams Steering Group - Western Interconnection
(SSG-WI) as the entity that will facilitate a common market design for the West.
The SSG-WI consists of western transmission owners, including members of
WestConnect. The FERC also noted that its prior WestConnect order did not
address other elements of market design that are currently being considered in
the pending SMD proposal and/or through the SSG-WI process. The FERC clarified
that there are only three areas that would be subject to the final SMD rule: (1)
transmission credits; (2) resource adequacy; and (3) market monitoring.

     The order also stated that the FERC's approval of the for-profit structure
will not predetermine its decision in the final SMD rule regarding whether a
for-profit independent transmission company should be permitted to perform all
the functions of an independent transmission provider. To the extent that the
FERC has not addressed aspects of WestConnect's for-profit proposal or
WestConnect's proposed particular functions, such elements will be subject to
review for consistency with Order No. 2000 and other related decisions regarding

                                       9
<PAGE>
functions that may be performed by an independent transmission company. The
WestConnect applicants sought further clarification of that aspect of the
rehearing order. The FERC has indicated that it will issue an order on the
WestConnect applicants' motion for clarification before April 14, 2003.

     The ACC Rules also required the formation and implementation of an Arizona
Independent Scheduling Administrator. The purpose of the AISA is to oversee the
application of operating protocols to ensure statewide consistency for
transmission access. The AISA is anticipated to be a temporary organization
until the implementation of an independent system operator or RTO. APS
participated in the creation of the AISA, a not-for-profit entity, and the
filing at the FERC for approval of its operating protocols. The operating
protocols were partially rejected and the remainder are currently under review.
On February 8, 2002, the ACC's Chief ALJ issued a procedural order which
consolidated the ACC docket relating to the AISA with several other pending ACC
dockets. In its Track B Order, the ACC directed that a hearing be held on
whether or not APS should be required to continue funding the AISA.

                   BUSINESS OF ARIZONA PUBLIC SERVICE COMPANY

     Following is a discussion of the business of APS, our major subsidiary.

GENERAL

     APS was incorporated in 1920 under the laws of Arizona and currently has
more than 902,000 customers. APS 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 APS owns. APS
also generates, sells and delivers electricity to wholesale customers in the
western United States. APS' marketing and trading division sells, in the
wholesale market, APS and Pinnacle West Energy's generation output that is not
needed for APS' Native Load, which includes loads for retail customers and
cost-of-service wholesale customers. APS does not distribute any products.
During 2002, no single purchaser or user of energy (other than Pinnacle West)
accounted for more than 4% of consolidated electric revenues.

     At December 31, 2002, APS employed approximately 5,100 people, which
includes employees assigned to jointly-owned generating facilities for which APS
serves as the generating facility manager. APS' principal executive offices are
located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone
602-250-1000).

PURCHASED POWER AND GENERATING FUEL

     See "Properties - Capacity" in Item 2 for information about our power
plants by fuel types.

     2002 ENERGY MIX

     Our consolidated sources of energy during 2002 were: purchased power -
49.9% (approximately 90% of which was for wholesale power operations); coal -
23.8%; nuclear -17.7%; gas - 8.5%; and other (includes oil, hydro and solar) -
0.1%.

                                       10
<PAGE>
     APS' sources of energy during 2002 were: purchased power - 30.4%
(approximately 60% of which was for wholesale power operations); coal - 37.2%;
nuclear - 27.7%; gas - 4.6%; and other (includes oil, hydro and solar) - 0.1%.

     COAL SUPPLY

     CHOLLA Cholla is a coal-fired power plant located in northeastern Arizona.
It is a jointly-owned facility operated by APS. APS purchases most of Cholla's
coal requirements from a coal supplier that mines all of the coal under a
long-term lease of coal reserves owned by the Navajo Nation, the federal
government and private landholders. Cholla has sufficient coal, including low
sulfur coal, under current contracts to ensure a reliable fuel supply through
2007. APS purchases a portion of Cholla's coal requirements on the spot market
to take advantage of competitive pricing options. Following expiration of
current contracts, APS believes that numerous competitive fuel supply options
will exist to ensure the continued operation of Cholla for its useful life.

     FOUR CORNERS Four Corners is a coal-fired power plant located in the
northwest corner of New Mexico. It is a jointly-owned facility operated by APS.
APS purchases all of Four Corners' coal requirements from a supplier with a
long-term lease of coal reserves owned by the Navajo Nation. Four Corners is
under contract for coal through 2004, with options to extend the contract
through the plant site lease expiration in 2017.

     NAVAJO GENERATING STATION The Navajo Generating Station is a coal-fired
power plant located in northern Arizona. It is a jointly-owned facility operated
by Salt River Project. The Navajo Generating Station's coal requirements are
purchased from a supplier with long-term leases from the Navajo Nation and the
Hopi Tribe. The Navajo Generating Station is under contract with its coal
supplier through 2011, with options to extend through the plant site lease
expiration in 2019. The Navajo Generating Station lease waives certain taxes
through the lease expiration in 2019. The lease provides for the potential to
renegotiate the coal royalty in 2007 and 2017, which may impact the fuel price.

     See "Properties - Capacity" in Item 2 for information about APS' ownership
interest in Cholla, Four Corners and the Navajo Generating Station. See Note 11
of Notes to Consolidated Financial Statements in Item 8 for information
regarding our coal mine reclamation obligations.

     NATURAL GAS SUPPLY

     APS and Pinnacle West Energy purchase the majority of their natural gas
requirements for their gas-fired plants under contracts with a number of natural
gas suppliers. APS' and Pinnacle West Energy's natural gas supply is transported
pursuant to a firm, full requirements transportation service agreement with El
Paso Natural Gas Company. The transportation agreement features a 10-year rate
moratorium established in a comprehensive rate case settlement entered into in
1996.

     In a pending FERC proceeding, El Paso Natural Gas Company has proposed
allocating its gas pipeline capacity in such a way that the gas transportation
rights of APS and Pinnacle West Energy (and other companies with the same
contract type) could be significantly impacted. Various parties, including APS
and Pinnacle West Energy, have challenged this allocation as being inconsistent
with El Paso Natural Gas Company's existing contractual obligations and a 1996
settlement. On May 31, 2002, the FERC issued an order requiring the conversion

                                       11
<PAGE>
of all firm, full requirements contracts to contract demand contracts by
November 1, 2002. In addition, the FERC order set forth procedures to encourage
parties to resolve the details of such conversions through a settlement process.
APS and other full requirements contract holders sought rehearing of the FERC
order and requested a stay of the November 1, 2002 implementation date. On
September 20, 2002, the FERC issued another order clarifying the capacity
allocation methodology, extending the conversion implementation date from
November 1, 2002 to May 1, 2003 and approving the reallocation of costs for the
transportation service. APS and other full requirements contract holders have
sought rehearings of this FERC order. The FERC has indicated that it intends to
issue an order on the merits in this proceeding by April 14, 2003. Although we
cannot predict the outcome of this matter, we currently do not expect this
matter to have a material adverse impact on our financial position, results of
operations or liquidity. We are continuing to analyze the market to determine
the most favorable source and method of meeting our natural gas requirements.

     NUCLEAR FUEL SUPPLY

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

     *    mining and milling of uranium ore to produce uranium concentrates;
     *    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,
except for a small percentage of 2003 uranium concentrates and 2004 conversion
requirements that will be obtained under contracts currently being finalized.
The Palo Verde participants have also contracted for all of Palo Verde's
enrichment services through 2010 and fuel assembly fabrication services until at
least 2015.

     SPENT NUCLEAR FUEL AND WASTE DISPOSAL Nuclear power plant operators are
required to enter into spent nuclear 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 filed damages lawsuits
against the DOE in the Court of Federal Claims.

     In February 2002, the U.S. 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. In July
2002, Congress approved the development of the Yucca Mountain, Nevada site,
overriding the Nevada veto. It is now expected that the DOE will submit a

                                       12
<PAGE>
license application to the NRC late in 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.

     Facility funding is a further complication. While all nuclear utilities pay
an amount calculated on the basis of the output of their respective plants into
a so-called nuclear waste fund, the annual Congressional appropriations for the
permanent repository have been for amounts less than the amounts paid into the
waste fund (the balance of which is being used for other purposes).

     APS has existing fuel storage pools at Palo Verde and has completed a new
facility for on-site dry storage of spent nuclear fuel. With the existing
storage pools and the addition of the new facility, APS believes 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. See "Palo Verde Nuclear Generating Station" in Note 11 of
Notes to Consolidated Financial Statements in Item 8 for a discussion of interim
spent nuclear fuel storage costs.

     Although some low-level waste has been stored on-site in a low-level waste
facility, APS is currently shipping low-level waste to off-site facilities. APS
currently believes 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.

     APS believes that scientific and financial aspects of the issues of spent
nuclear fuel and low-level waste storage and disposal can be resolved
satisfactorily. However, APS acknowledges that their ultimate resolution in a
timely fashion will require political resolve and action on national and
regional scales which APS is less able to predict. APS expects to vigorously
protect and pursue its rights related to this matter.

PURCHASED POWER AGREEMENTS

     In addition to that available from its own generating capacity (see
"Properties" in Item 2), APS purchases electricity under various arrangements.
One of the most important of these is a long-term contract with Salt River
Project. The amount of electricity available to APS is based in large part on
customer demand within certain areas now served by APS pursuant to a related
territorial agreement. The generating capacity available to APS pursuant to the
contract was 336 MW from January through May 2002, and starting in June 2002, it
changed to 343 MW. In 2002, APS received approximately 1,104,973 MWh of energy
under the contract and paid about $46.2 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. APS may also cancel the
contract on five years' notice, given no earlier than December 31, 2006.

     In September 1990, APS entered into a thirty-year seasonal capacity
exchange agreement with PacifiCorp. Under this agreement, APS receives
electricity from PacifiCorp during the summer peak season (from May 15 to
September 15) and APS returns electricity to PacifiCorp during the winter season
(from October 15 to February 15). Until 2020, APS and PacifiCorp each has 480 MW
of capacity and a related amount of energy available to it under the agreement
for its respective seasons. In 2002, APS received approximately 571,392 MWh of
energy under the capacity exchange. APS must also make additional offers of
energy to PacifiCorp each year through October 31, 2020. Pursuant to this
requirement, during 2002, PacifiCorp received offers of 1,129,600 MWh and
purchased about 115,750 MWh.

                                       13
<PAGE>
CONSTRUCTION PROGRAM

     During the years 2000 through 2002, APS incurred approximately $1.4 billion
in capital expenditures. APS' capital expenditures for the years 2003 through
2005 are expected to be primarily for expanding transmission and distribution
capabilities to meet growing customer needs, for upgrading existing utility
property and for environmental purposes. APS' capital expenditures were
approximately $501 million in 2002. APS' capital expenditures, including
expenditures for environmental control facilities, for the years 2003 through
2005 have been estimated as follows:

                              (dollars in millions)

                      BY YEAR                 BY MAJOR FACILITIES
                 -----------------         --------------------------
                 2003      $   401         Production         $   386
                 2004          379         T&D                    877
                 2005          498         Other                   15
                           -------                            -------
                 Total     $ 1,278         Total              $ 1,278
                           =======                            =======

     The above amounts exclude capitalized interest costs and include
capitalized property taxes and approximately $30 million per year for nuclear
fuel. These amounts include only APS' generation (production) assets. APS
conducts a continuing review of its construction program.

     See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Capital Needs and Resources" in Item 7 for additional
information about APS' construction program and for information about Pinnacle
West Energy's generation construction plans.

MORTGAGE REPLACEMENT FUND REQUIREMENTS

     So long as any of its first mortgage bonds are outstanding, APS is required
for each calendar year to deposit with the trustee under its mortgage cash in a
formularized amount related to net additions to its mortgaged utility plant. APS
may satisfy all or any part of this "replacement fund" requirement by using
redeemed or retired bonds, net property additions or property retirements. For
2002, the replacement fund requirement amounted to approximately $161 million.
Certain of the bonds APS has issued under the mortgage that are callable prior
to maturity are redeemable at their par value plus accrued interest with cash
APS deposits in the replacement fund. These call provisions are subject in many
cases to a period of time after the original issuance of the bonds during which
they may not be redeemed in this manner. See Note 6 of Notes to Consolidated
Financial Statements in Item 8 for information regarding APS' first mortgage
bonds.

ENVIRONMENTAL MATTERS

     EPA ENVIRONMENTAL REGULATION

     CLEAN AIR ACT We are subject to a number of requirements under the Clean
Air Act. The Clean Air Act addresses, among other things:

     *    "acid rain";
     *    visibility in certain specified areas;
     *    hazardous air pollutants; and

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<PAGE>
     *    areas that have not attained national ambient air quality standards.

     With respect to "acid rain," the Clean Air Act established a system of
sulfur dioxide emissions "allowances" to offset each ton of sulfur dioxide
emitted by affected power plants. Based on EPA allowance allocations, we will
have sufficient allowances to permit continued operation of our plants at
current levels without installing additional equipment. The Clean Air Act also
requires the EPA to set nitrogen oxides emissions limitations for certain
coal-fired units. The EPA rule allows emissions from all units in a plant to be
averaged to demonstrate compliance with the emission limitation. Currently,
nitrogen oxides emissions from all of our units are within the limitations
specified under the EPA's rules. We do not currently expect this rule to have a
material impact on our financial position, results of operations or liquidity.

     The Clean Air Act required the EPA to establish a Grand Canyon Visibility
Transport Commission to complete a study on visibility impairment in sixteen
"Class I Areas" (large national parks and wilderness areas) on the Colorado
Plateau. The Navajo Generating Station, Cholla and Four Corners are located near
several Class I Areas on the Colorado Plateau. The Visibility Commission
completed its study and on June 10, 1996 submitted its final recommendations to
the EPA.

     On April 22, 1999, the EPA announced final regional haze rules. These new
regulations require states to submit, by 2008, implementation plans to eliminate
all man-made emissions causing visibility impairment in certain specified areas,
including Class I Areas in the Colorado Plateau. The 2008 implementation plans
must also include consideration and potential application of best available
retrofit technology for major stationary sources which came into operation
between August 1962 and August 1977, such as the Navajo Generating Station,
Cholla and Four Corners.

     The rules allow the nine western states and tribes that participated in the
Visibility Commission process to follow an alternate implementation plan and
schedule for the Class I Areas considered by the Visibility Commission. Under
this option, those states and tribes would submit implementation plans by 2003,
which would incorporate certain regional sulfur dioxide emissions milestones for
the years 2003, 2008, 2013 and 2018 (which include the application of best
available retrofit technology). If the regional emissions in those years were
within those milestones, there would be no further emission reduction
requirements, and if they were exceeded, then an emission trading program would
be implemented to maintain the emissions within those milestones.

     The EPA reviewed an "Annex" to the Visibility Commission recommendations
that specify the regional sulfur dioxide emission milestones. On April 26, 2002,
the EPA proposed to accept the Visibility Commission's Annex, which had been
submitted by the Western Regional Air Partnership (successor to Visibility
Commission) in September 2000. The Annex specifies regional sulfur dioxide
emission reduction milestones. The EPA's final approval of the Annex would allow
the states and tribes to pursue the alternate implementation of the regional
haze rules through 2018. Any states and tribes that implement this option would
have to submit state implementation plans by 2003 to address visibility in areas
identified in the process, and revised implementation plans in 2008 to address
Class I Areas which were not included in the process. The State of Arizona is in
the process of developing a State Implementation Plan to implement the
provisions of the Annex. Because Four Corners is located on the Navajo
Reservation and is currently regulated by EPA Region IX, the provisions of the
Annex currently could become applicable to Four Corners only through a Federal
Implementation Plan promulgated by EPA Region IX. At this time, it is uncertain

                                       15
<PAGE>
how the State of Arizona and/or EPA Region IX will proceed to implement the
Annex, so the actual impact on APS cannot yet be determined.

     In July 1997, the EPA promulgated final National Ambient Air Quality
Standards for ozone and particulate matter. Pursuant to these rules, the ozone
standard is more stringent and a new ambient standard for very fine particles
has been established. Congress has enacted legislation that could delay the
implementation of regional haze requirements and the particulate matter ambient
standard; however, the legislation does not preclude the Visibility Commission
states and tribes from implementing the alternate regional haze rules discussed
above. Because the actual level of emissions controls, if any, for any unit
cannot be determined at this time, APS currently cannot estimate the capital
expenditures, if any, which would result from the final rules. However, APS does
not currently expect these rules to have a material adverse effect on its
financial position, results of operations or liquidity.

     With respect to hazardous air pollutants emitted by electric utility steam
generating units, the EPA has determined that mercury emissions and other
hazardous air pollutants from coal and oil-fired power plants will be regulated.
We expect that the EPA will propose specific rules for this purpose in 2003 and
finalize them by 2004, with compliance required by 2008. 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.

     Certain aspects of the Clean Air Act may require APS to make related
expenditures, such as permit fees. APS does not expect any of these expenditures
to have a material impact on its financial position, results of operations or
liquidity.

     FEDERAL IMPLEMENTATION PLAN In September 1999, the EPA proposed a FIP to
set air quality standards at certain power plants, including the Navajo
Generating Station and Four Corners. The comment period on this proposal ended
in November 1999. The FIP is similar to current Arizona regulation of the Navajo
Generating Station and New Mexico regulation of Four Corners, with minor
modifications. APS does not currently expect the FIP to have a material impact
on its financial position, results of operations or liquidity.

     SUPERFUND The Comprehensive Environmental Response, Compensation, and
Liability Act (Superfund) establishes liability for the cleanup of hazardous
substances found contaminating the soil, water or air. Those who generated,
transported or disposed of hazardous substances at a contaminated site are among
those who are potentially responsible parties. PRPs may be strictly, and often
jointly and severally, liable for clean-up. The EPA had previously advised APS
that the EPA considers APS to be a PRP in the Indian Bend Wash Superfund Site,
South Area. APS' Ocotillo Power Plant is located in this area. Based on the
information to date, including available insurance coverage and an EPA estimate
of cleanup costs, APS does not expect this matter to have a material impact on
its financial position, results of operations or liquidity.

     MANUFACTURED GAS PLANT SITES APS is currently investigating properties
which it now owns or which were previously owned by it or its corporate
predecessors, that were at one time sites of, or sites associated with,
manufactured gas plants. The purpose of this investigation is to determine if:

     *    waste materials are present;
     *    such materials constitute an environmental or health risk; and
     *    APS has any responsibility for remedial action.

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<PAGE>
     Where appropriate, APS has begun clean-up of certain of these sites. APS
does not expect these matters to have a material adverse effect on its financial
position, results of operations or liquidity.

     ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY

     ADEQ issued to APS NOVs dated September 25, 2001 and October 15, 2001
alleging, among other things, the burning of unauthorized materials and storage
of hazardous waste without a permit at the Cholla Power Plant. Each NOV requires
APS to achieve and document compliance with specific environmental requirements.
APS has submitted responses to the NOVs as well as additional information
requested by the agency. By letter dated February 28, 2003, the Arizona Attorney
General notified APS that the ADEQ expects to take enforcement action against
APS regarding the violations included in the NOVs, as well as related
violations. APS does not expect these matters to have a material adverse effect
on its financial position, results of operations or liquidity.

     NAVAJO NATION ENVIRONMENTAL ISSUES

     Four Corners and the Navajo Generating Station are located on the Navajo
Reservation and are held under easements granted by the federal government as
well as leases from the Navajo Nation. APS is the Four Corners operating agent.
APS owns a 100% interest in Four Corners Units 1, 2 and 3, and a 15% interest in
Four Corners Units 4 and 5. APS owns a 14% interest in Navajo Generating Station
Units 1, 2 and 3.

     In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution
Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the
Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts
purport to give the Navajo Nation Environmental Protection Agency authority to
promulgate regulations covering air quality, drinking water and pesticide
activities, including those that occur at Four Corners and the Navajo Generating
Station. The Four Corners and Navajo Generating Station participants dispute
that purported authority, and by separate letters dated October 12 and October
13, 1995, the Four Corners participants and the Navajo Generating Station
participants requested the United States Secretary of the Interior to resolve
their dispute with the Navajo Nation regarding whether or not the Navajo Acts
apply to operations of 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, seeking, among other things, a declaratory
judgment that:

     *    their respective leases and federal easements preclude the application
          of the Navajo Acts to the operations of Four Corners and the Navajo
          Generating Station; and

     *    the Navajo Nation and its agencies and courts lack adjudicatory
          jurisdiction to determine the enforceability of the Navajo Acts as
          applied to Four Corners and the Navajo Generating Station.

On October 18, 1995, the Navajo Nation and the Four Corners and Navajo
Generating Station participants agreed to indefinitely stay these proceedings so

                                       17
<PAGE>
that the parties may attempt to resolve the dispute without litigation. The
Secretary and the Court have stayed these proceedings pursuant to a request by
the parties. APS cannot currently predict the outcome of this matter.

     In February 1998, the EPA issued regulations identifying those Clean Air
Act provisions for which it is appropriate to treat Indian tribes in the same
manner as states. The EPA has announced that it has not yet determined whether
the Clean Air Act would supersede pre-existing binding agreements between the
Navajo Nation and the Four Corners participants and the Navajo Generating
Station participants that could limit the Navajo Nation's environmental
regulatory authority over the Navajo Generating Station and Four Corners. APS
believes that the Clean Air Act does not supersede these pre-existing
agreements. APS cannot currently predict the outcome of this matter.

     In April 2000, the Navajo Tribal Council approved operating permit
regulations under the Navajo Nation Air Pollution Prevention and Control Act. We
believe that 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. We cannot currently
predict the outcome of this matter.

WATER SUPPLY

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

     Both groundwater and surface water in areas important to APS' operations
have been the subject of inquiries, claims and legal proceedings, which will
require a number of years to resolve. APS is one of a number of parties in a
proceeding before a state court in New Mexico to adjudicate rights to a stream
system from which water for Four Corners is derived. (STATE OF NEW MEXICO, IN
THE RELATION OF S.E. REYNOLDS, STATE ENGINEER VS. UNITED STATES OF AMERICA, CITY
OF FARMINGTON, UTAH INTERNATIONAL, INC., ET AL., SAN JUAN COUNTY, NEW MEXICO,
District Court No. 75-184). An agreement reached with the Navajo Nation in 1985,
however, provides that if Four Corners loses a portion of its rights in the
adjudication, the Navajo Nation will provide, for a then-agreed upon cost,
sufficient water from its allocation to offset the loss.

     A summons served on APS in early 1986 required all water claimants in the
Lower Gila River Watershed in Arizona to assert any claims to water on or before
January 20, 1987, in an action pending in Maricopa County, Arizona, Superior
Court. (IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE GILA
RIVER SYSTEM AND SOURCE, Supreme Court Nos. WC-79-0001 through WC 79-0004
(Consolidated) [WC-1, WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos.
W-1, W-2, W-3 and W-4 (Consolidated)). Palo Verde is located within the
geographic area subject to the summons. APS' rights and the rights of the Palo
Verde participants to the use of groundwater and effluent at Palo Verde are
potentially at issue in this action. As project manager of Palo Verde, APS filed
claims that dispute the court's jurisdiction over the Palo Verde participants'
groundwater rights and their contractual rights to effluent relating to Palo
Verde. Alternatively, APS seeks confirmation of such rights. Three of APS' other
power plants and two of Pinnacle West Energy's power plants are also located
within the geographic area subject to the summons. APS' claims dispute the
court's jurisdiction over its groundwater rights with respect to these plants.
Alternatively, APS seeks confirmation of such rights. In November 1999, the
Arizona Supreme Court issued a decision confirming that certain groundwater
rights may be available to the federal government and Indian tribes. In

                                       18
<PAGE>
addition, in September 2000, the Arizona Supreme Court issued a decision
affirming the lower court's criteria for resolving groundwater claims.
Litigation on both of these issues will continue in the trial court. No trial
date concerning APS' water rights claims has been set in this matter.

     APS has also filed claims to water in the Little Colorado River Watershed
in Arizona in an action pending in the Apache County, Arizona, Superior Court.
(IN RE THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE LITTLE
COLORADO RIVER SYSTEM AND SOURCE, Supreme Court No. WC-79-0006 WC-6, Apache
County No. 6417). APS' groundwater resource utilized at Cholla is within the
geographic area subject to the adjudication and is therefore potentially at
issue in the case. APS' claims dispute the court's jurisdiction over its
groundwater rights. Alternatively, APS seeks confirmation of such rights. A
number of parties are in the process of settlement negotiations with respect to
certain claims in this matter. Other claims have been identified as ready for
litigation in motions filed with the court. No trial date concerning APS' water
rights claims has been set in this matter.

     Although the foregoing matters remain subject to further evaluation, APS
expects that the described litigation will not have a material adverse impact on
its financial position, results of operations or liquidity.

     The Four Corners region, in which Four Corners is located, has been
experiencing drought conditions that may affect the water supply for the plants
in 2003, as well as later years if adequate moisture is not received in the
watershed that supplies the area. Various stakeholders in the San Juan Basin,
including the New Mexico State Engineer, are evaluating how water rights might
be affected by the drought conditions, including water rights pursuant to the
New Mexico state permit that provide approximately 30,000 acre feet of water to
Four Corners. We are assessing alternatives for temporary supplies of water and
are working with area stakeholders to minimize the effect, if any, on operations
of the plant. The effect of the drought cannot be fully assessed at this time,
and we cannot predict the ultimate outcome, if any, of the drought or whether
the drought will adversely affect the amount of power available, or the price
thereof, from Four Corners.

                  BUSINESS OF PINNACLE WEST ENERGY CORPORATION

     Pinnacle West Energy was incorporated in 1999 under the laws of the State
of Arizona and is engaged principally in the development of generating plants
and production of wholesale electricity. Pinnacle West Energy is the subsidiary
through which we conduct our competitive generation operations. Pinnacle West
Energy had approximately 100 employees as of December 31, 2002. Pinnacle West
Energy's principal offices are located at 400 North Fifth Street, Phoenix,
Arizona 85004 (telephone (602) 250-4145).

     Pinnacle West Energy's capital expenditures in 2002 were $374 million.
Projected capital expenditures are $268 million in 2003; $31 million in 2004;
and $20 million in 2005. These amounts exclude capitalized interest costs and
include capitalized property taxes. These capital expenditures do not reflect an
expected reimbursement in 2004 by SNWA of about $100 million of Pinnacle West
Energy's cumulative capital expenditures for the Silverhawk project in exchange
for SNWA's option to purchase a 25% interest in the project.

     Pinnacle West Energy's Arizona plants were built as a result of what we
believed was a regulatory restriction against APS construction of additional
plants and based on the requirement in the 1999 Settlement Agreement that APS

                                       19
<PAGE>
transfer its generation assets. The amounts in the preceding paragraph relate
only to Pinnacle West Energy's generation assets. As discussed in "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Factors Affecting Our Financial Outlook" in Item 7, as part of its 2003 general
rate case, APS intends to seek rate base treatment of certain power plants
currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2,
West Phoenix Units 4 and 5 and Saguaro Unit 3). At December 31, 2002, Pinnacle
West Energy had total assets of $1.2 billion. Pinnacle West Energy reported a
net loss of $19 million in 2002, net income of $18 million in 2001 and a net
loss of $2 million in 2000.

     See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Factors Affecting Our Financial Outlook" in Item 7 for a
discussion of APS' implementation of an ACC-mandated process by which APS must
competitively procure energy. See Note 11 of Notes to Consolidated Financial
Statements in Item 8 for information regarding Pinnacle West Energy's generation
construction plans.

                  BUSINESS OF APS ENERGY SERVICES COMPANY, INC.

     APS Energy Services was incorporated in 1998 under the laws of the State of
Arizona and provides competitive commodity-related energy services (such as
direct access commodity contracts, energy procurement and energy supply
consultation) and energy-related products and services (such as energy master
planning, energy use consultation and facility audits, cogeneration analysis and
installation and project management) to commercial, industrial and institutional
retail customers in the western United States. APS Energy Services had
approximately 100 employees as of December 31, 2002. APS Energy Services'
principal offices are located at 400 East Van Buren Street, Phoenix, Arizona
85004 (telephone (602) 250-5000).

     APS Energy Services reported pretax income of $28 million in 2002 and
pretax losses of $10 million in 2001 and $13 million in 2000. Income taxes
related to APS Energy Services are recorded by the parent company. At December
31, 2002, APS Energy Services had total assets of $90 million.

                     BUSINESS OF SUNCOR DEVELOPMENT COMPANY

     SunCor was incorporated in 1965 under the laws of the State of Arizona and
is a developer of residential, commercial and industrial real estate projects in
Arizona, New Mexico and Utah. The principal executive offices of SunCor are
located at 80 East Rio Salado Parkway, Suite 410 Tempe, Arizona 85281 (telephone
(480) 317-6800). SunCor and its subsidiaries had approximately 800 full- and
part-time employees at December 31, 2002.

     SunCor's assets consist primarily of land with improvements, commercial
buildings and other real estate investments. SunCor's largest project is the
Palm Valley master-planned community, which has approximately 6,900 acres
remaining to be developed west of Phoenix in the area of the towns of Avondale,
Goodyear and Litchfield Park, Arizona. SunCor has completed the master plan for
development of Palm Valley.

     SunCor projects under development include seven master-planned communities
and several commercial projects. The commercial projects and five of the
master-planned communities are in Arizona. Other master-planned communities are
located near St. George, Utah, and Santa Fe, New Mexico. Several of the
master-planned communities and commercial projects are joint ventures with other
developers, financial partners or landowners. SunCor opened two new projects in
2002:

                                       20
<PAGE>
     *    Hayden Ferry Lakeside - an 18-acre, mixed-use commercial and
          residential project located in Tempe, Arizona that opened its first
          office building in July 2002; and

     *    StoneRidge - an 1,850-acre, master-planned community with a golf
          course in Prescott Valley, Arizona that opened its initial phase of
          home and lot sales and its golf course in 2002.

     For the past three years, SunCor's operating revenues were about: $236
million in 2002; $169 million in 2001; and $158 million in 2000. For those same
periods, SunCor's net income was about: $19 million in 2002; $3 million in 2001;
and $11 million in 2000.

     SunCor's capital needs consist primarily of capital expenditures for land
development and home construction for SunCor's home-building subsidiary, Golden
Heritage Homes, Inc. SunCor's capital expenditures were approximately $72
million in 2002. On the basis of projects currently under development, SunCor
expects its capital needs over the next three years to be: $64 million in 2003;
$23 million in 2004; and $20 million in 2005.

     At December 31, 2002, SunCor had total assets of about $534 million. See
Note 6 of Notes to Consolidated Financial Statements in Item 8 for information
regarding SunCor's long-term debt. SunCor intends to continue its focus on real
estate development of master-planned communities, mixed-use residential,
commercial, office and industrial projects. As discussed in "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in
Item 7, we are undertaking an aggressive effort to accelerate SunCor's asset
sales activities to approximately double SunCor's annual earnings in the 2003 to
2005 period (compared with $19 million in earnings recorded in 2002) and to
permit SunCor to make annual cash distributions to Pinnacle West of $80 - $100
million during that same period.

                    BUSINESS OF EL DORADO INVESTMENT COMPANY

     El Dorado was incorporated in 1983 under the laws of the State of Arizona.
At December 31, 2002, El Dorado owned a majority interest in NAC, a company
specializing in spent nuclear fuel technology, and also held miscellaneous small
investments, including interests in Arizona community-based ventures. El
Dorado's short-term goal is to prudently realize the value of its existing
investments. On a long-term basis, we may use El Dorado, when appropriate, as
our subsidiary for investments that are strategic to our principal business of
generating, distributing and marketing electricity. El Dorado's offices are
located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone (602)
250-3517). El Dorado had approximately 100 employees (all NAC) as of December
31, 2002.

     El Dorado reported a pretax loss of $55 million in 2002 (during 2002,
income tax benefits related to El Dorado were recorded by the parent company)
and net income of $0.2 million in 2001 and $2 million in 2000. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in
Item 7 and Note 22 of Notes to Consolidated Financial Statements in Item 8 for
information regarding El Dorado's 2002 losses. At December 31, 2002, El Dorado
had total assets of $36 million.

                                       21
<PAGE>
                               ITEM 2. PROPERTIES

CAPACITY

     Our generating facilities are described below. For APS' plants, the "net
accredited capacities" are reported, consistent with industry practice for
regulated utilities. For Pinnacle West Energy, the "permitted capacities" are
reported, consistent with industry practice for unregulated plants.

APS - NET ACCREDITED CAPACITY

     APS' present generating facilities have net accredited capacities as
follows:

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

  Subtotal .....................................................    1,712,000
                                                                    ---------

Gas or Oil:
  Two steam units at Ocotillo and two steam units at Saguaro ...      430,000(a)
  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 ........    1,086,300
                                                                    ---------

Hydro and Solar ................................................        7,600
                                                                    ---------

  Total APS facilities .........................................    3,983,900
                                                                    =========

PINNACLE WEST ENERGY - PERMITTED CAPACITIES

     Pinnacle West Energy's present generating facilities have permitted
capacities as follows:

Gas or Oil:
Two combined cycle units at Redhawk and one combined-cycle unit
  at West Phoenix ..............................................    1,180,000(b)
One combustion turbine unit at Saguaro .........................       80,000
                                                                    ---------

Total Pinnacle West Energy facilities ..........................    1,260,000
                                                                    =========

----------
(a)  Does not include West Phoenix steam units (108,300 kW), which were retired
     in December 2002.
(b)  See Note 11 of Notes to Consolidated Financial Statements in Item 8 for
     information regarding Pinnacle West Energy's generation construction plans.

                                       22
<PAGE>
RESERVE MARGIN

     APS' 2002 peak one-hour demand on its electric system was recorded on July
9, 2002 at 5,802,900 kW, compared to the 2001 peak of 5,687,200 kW recorded on
July 2, 2001. Taking into account additional capacity then available to APS
under long-term purchase power contracts as well as APS' and Pinnacle West
Energy's generating capacity, APS' capability of meeting system demand on July
9, 2002 amounted to 6,046,600 kW, for an installed reserve margin of 6.5%. The
power actually available to APS from its resources fluctuates from time to time
due in part to planned outages and technical problems. The available capacity
from sources actually operable at the time of the 2002 peak amounted to
3,877,600 kW, for a margin of negative 38.1%. Firm purchases totaling 2,612,000
kW, including short-term seasonal purchases and unit contingent purchases, were
in place at the time of the peak, ensuring the ability to meet the load
requirement, with an actual reserve margin of 7.1%.

     See "Business of Arizona Public Service Company - Purchased Power
Agreements" in Item 1 for information about certain of APS' long-term power
agreements.

PLANT SITES LEASED FROM NAVAJO NATION

     The Navajo Generating Station and Four Corners are located on land held
under easements from the federal government and also under leases from the
Navajo Nation. These are long-term agreements 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

     PALO VERDE LEASES

     See Note 9 of Notes to Consolidated Financial Statements in Item 8 for a
discussion of three sale-leaseback transactions related to Palo Verde Unit 2.

     REGULATORY

     Operation of each of the three Palo Verde units requires an operating
license from the NRC. The NRC issued full power operating licenses for Unit 1 in
June 1985, Unit 2 in April 1986 and Unit 3 in November 1987. The full power
operating licenses, each valid for a period of approximately 40 years, authorize
APS, as operating agent for Palo Verde, to operate the three Palo Verde units at
full power.

     NUCLEAR DECOMMISSIONING COSTS

     The NRC rules on financial assurance requirements for the decommissioning
of nuclear power plants provide that a licensee may use a trust as the exclusive
financial assurance mechanism if the licensee recovers estimated total
decommissioning costs through cost of service rates or through a "non-bypassable
charge." The "non-bypassable systems benefits" charge is the charge that the ACC
has approved to recover certain types of ACC-approved costs, including costs for
low income programs, demand side management, consumer education, environmental,

                                       23
<PAGE>
renewables, etc. "Non-bypassable" means that if a customer chooses to take
energy from an "energy service provider" other than APS, the customer will still
have to pay this charge as part of the customer's APS electric bill. Other
mechanisms are prescribed, including prepayment, if the requirements for
exclusive reliance on the external sinking fund mechanism are not met. APS
currently relies on the external sinking fund mechanism to meet the NRC
financial assurance requirements for its interests in Palo Verde Units 1, 2 and
3. The decommissioning costs of Palo Verde Units 1, 2 and 3 are currently
included in APS' ACC jurisdictional rates. ACC retail electric competition Rules
provide that decommissioning costs would be recovered through a non-bypassable
"system benefits" charge, which would allow APS to maintain its external sinking
fund mechanism. See Note 12 of Notes to Consolidated Financial Statements in
Item 8 for additional information about our nuclear decommissioning costs.

     PALO VERDE LIABILITY AND INSURANCE MATTERS

     See "Palo Verde Nuclear Generating Station" in Note 11 of Notes to
Consolidated Financial Statements in Item 8 for a discussion of the insurance
maintained by the Palo Verde participants, including APS, for Palo Verde.

PROPERTY NOT HELD IN FEE OR SUBJECT TO ENCUMBRANCES

     JOINTLY-OWNED FACILITIES

     APS shares ownership of some of its generating and transmission facilities
with other companies. The following table shows APS' interest in those
jointly-owned facilities recorded on the Consolidated Balance Sheets at December
31, 2002:

                                                                      PERCENT
                                                                   OWNED BY APS
                                                                   ------------
     Generating facilities:
       Palo Verde Nuclear Generating Station
         Units 1 and 3                                                29.1%
       Palo Verde Nuclear Generating Station
         Unit 2 (see "Palo Verde Leases" below)                       17.0%
       Four Corners Steam Generating Station
         Units 4 and 5                                                15.0%
       Navajo Steam Generating Station
         Units 1, 2, and 3                                            14.0%
       Cholla Steam Generating Station
         Common Facilities (a)                                        62.8%(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                             50.0%(b)

                                       24
<PAGE>
(a)  PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The
     common facilities at the Cholla Plant are jointly-owned.

(b)  Weighted average of interests.

     PALO VERDE LEASES

     In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. APS accounts
for these leases as operating leases. The leases, which have terms of 29.5
years, contain options to renew the leases for two additional years and to
purchase the property for fair market value at the end of the lease terms. See
Notes 9 and 20 of Notes to Consolidated Financial Statements in Item 8 for
additional information regarding the Palo Verde Unit 2 sale-leaseback
transactions.

     APS FIRST MORTGAGE LIEN

     APS' first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel and transportation equipment and other
excluded assets). See Note 6 of Notes to Consolidated Financial Statements in
Item 8 for information regarding APS' outstanding first mortgage bonds.

OTHER INFORMATION REGARDING OUR PROPERTIES

     See "Environmental Matters" and "Water Supply" in Item 1 with respect to
matters having 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 plans.

INFORMATION REGARDING PROPERTIES OF PINNACLE WEST ENERGY AND SUNCOR

     See "Business of Pinnacle West Energy Corporation" and "Business of SunCor
Development Company" for information regarding Pinnacle West Energy's and
SunCor's properties.

                                       25
<PAGE>
                                   [MAP PAGE}

     In accordance with Item 304 of Regulation S-T of the Securities Exchange
Act of 1934, APS' Service Territory map contained in this Form 10-K is a map of
the State of Arizona showing APS' service area, the location of its major power
plants and principal transmission lines, the location of Pinnacle West Energy's
power plants and the location of transmission lines operated by APS for others.
APS' major power plants shown on such map are the Navajo Generating Station
located in Coconino County, Arizona; the Four Corners Power Plant located near
Farmington, New Mexico; the Cholla Power Plant, located in Navajo County,
Arizona; the Yucca Power Plant, located near Yuma, Arizona; the Palo Verde
Nuclear Generating Station, located about 55 miles west of Phoenix, Arizona; the
West Phoenix Power Plant, located near Phoenix, Arizona; and the Saguaro Power
Plant, located near Tucson, Arizona (each of which plants is reflected on such
map as being jointly owned with other utilities), as well as the Ocotillo Power
Plant located near Phoenix, Arizona. Pinnacle West Energy's power plants shown
on such map are the West Phoenix Power Plant located near Phoenix, Arizona, and
the Saguaro Power Plant, located near Tucson, Arizona (both of which plants are
reflected on such map as being jointly owned with APS), as well as the Redhawk
Power Plant, located near Phoenix, Arizona. APS' major transmission lines shown
on such map are reflected as running between the power plants named above and
certain major cities in the State of Arizona. The transmission lines operated
for others shown on such map are reflected as running from the Four Corners
Plant through a portion of northern Arizona to the California border and from
the Phoenix area.

                                       26
<PAGE>
                            ITEM 3. LEGAL PROCEEDINGS

     See "Environmental Matters" and "Water Supply" in Item 1 in regard to
pending or threatened litigation and other disputes. See Note 3 of Notes to
Consolidated Financial Statements in Item 8 for a discussion of the ACC retail
electric competition Rules, the Track A Order and related litigation.

     See Note 11 of Notes to Consolidated Financial Statements in Item 8 for
information relating to the FERC proceedings on California energy market issues
and a claim by Citizens that APS overcharged Citizens under a power service
agreement. See also Note 22 of Notes to Consolidated Financial Statements in
Item 8 for information relating to a breach of contract claim by Maine Yankee
against Pinnacle West and NAC.

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

     Not applicable.

                                       27
<PAGE>
                               SUPPLEMENTAL ITEM.
                      EXECUTIVE OFFICERS OF THE REGISTRANT

Our executive officers are as follows:

Name                Age at March 1, 2003    Position(s) at March 1, 2003
----                --------------------    ----------------------------
William J.  Post           52               Chairman of the Board and
                                              Chief Executive Officer (1)
Jack E. Davis              56               President, and President and Chief
                                              Executive Officer, APS (1)
Robert S. Aiken            46               Vice President, Federal Affairs
John G. Bohon              57               Vice President, Corporate Services &
                                              Human Resources
Donald E. Brandt           48               Senior Vice President and Chief
                                              Financial Officer
Dennis L. Brown            52               Vice President and Chief Information
                                              Officer
Armando B. Flores          59               Executive Vice President, Corporate
                                              Business Services
Edward Z. Fox              49               Vice President, Communications,
                                              Environment & Safety
Barbara M. Gomez           48               Treasurer
James M. Levine            53               Executive Vice President, APS
                                              and President, Pinnacle
                                              West Energy
Nancy C. Loftin            49               Vice President, General Counsel
                                              and Secretary
Gregg R. Overbeck          56               Senior Vice President, APS, Nuclear
Martin L. Shultz           58               Vice President, Government Affairs
Steven M. Wheeler          54               Senior Vice President, APS
                                              Transmission, Regulation and
                                              Planning
----------
(1)  Member of the Board of Directors.

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

     Mr. Post was elected Chairman of the Board effective February 2001, and
Chief Executive Officer effective February 1999. He has served as an officer of
Pinnacle West since 1995 in the following capacities: from August 1999 to
February 2001 as President; from February 1997 to February 1999 as President;
and from June 1995 to February 1997 as Executive Vice President. Mr. Post is
also Chairman of the Board (since February 2001) of APS. He was President of APS
from February 1997 until October 1998 and he was Chief Executive Officer from
February 1997 until October 2002. Mr. Post is also a director of APS, Pinnacle
West Energy and Phelps Dodge Corporation.

                                       28
<PAGE>
     Mr. Davis was elected to his present position effective February 2001.
Prior to that time he was Chief Operating Officer and Executive Vice President
of Pinnacle West (April 2000-February 2001) and Executive Vice President,
Commercial Operations of APS (September 1996-October 1998). Mr. Davis is
President of APS (since October 1998) and Chief Executive Officer of APS (since
October 2002). He is a director of APS and Pinnacle West Energy.

     Mr. Aiken was elected to his present position in July 1999. Prior to that
time he was Pinnacle West's Manager, Federal Affairs (November 1986-July 1999).

     Mr. Bohon was elected to his present position in July 1999. Prior to that
time he was Vice President, Corporate Services and Human Resources of APS
(October 1998-July 1999) and Vice President, Procurement of APS (April
1997-October 1998).

     Mr. Brandt was elected to his present position in December 2002. Prior to
that time he was Senior Vice President and Chief Financial Officer of Ameren
Corporation (diversified energy services company). Mr. Brandt was elected Senior
Vice President and Chief Financial Officer of APS in January 2003.

     Mr. Brown was elected to his present position in June 2001. Prior to that
time he was Director, Information Technology of Pinnacle West (October 1999 -
June 2001) and Global Solution Executive for IBM Utilities and Energy Services
of IBM prior to that time.

     Mr. Flores was elected to his present position in July 1999. Prior to that
time, he was Executive Vice President, Corporate Business Services of APS
(October 1998-July 1999) and Senior Vice President, Corporate Business Services
of APS (September 1996-October 1998).

     Mr. Fox was elected to his present position in July 1999. Prior to that
time he was Vice President, Environmental/Health/Safety and New Technology
Ventures of APS (October 1995-July 1999).

     Ms. Gomez was elected to her present position in August 1999. Prior to that
time, she was Manager, Treasury Operations of APS (1997-1999). She was also
elected Treasurer of APS in October 1999.

     Mr. Levine was elected Executive Vice President of APS in July 1999 and
President of Pinnacle West Energy in January 2003. Prior to that time he was
Senior Vice President, Nuclear Generation of APS (September 1996-July 1999).

     Ms. Loftin was elected Vice President and General Counsel in July 1999 and
Secretary in October 2002. She was elected to the positions of Vice President
and Chief Legal Counsel of APS in September 1996. She was also elected Vice
President and General Counsel of APS in July 1999 and Secretary of APS in
October 2002.

     Mr. Overbeck was elected to his present position in July 1999. Prior to
that time he was Vice President, Nuclear Production of APS (September 1996 to
July 1999) and Vice President, Nuclear Support of APS (July 1995 to September
1996).

     Mr. Shultz was elected to his current position in July 1999. Prior to that
time he held the position of Director of Government Relations for APS (1988-July
1999).

     Mr. Wheeler was elected to his present position in October 2002. Prior to
that time he was Senior Vice President, Transmission, Regulation and Planning of
Pinnacle West and APS (June 2001 - October 2002). Prior to that time he was a
partner with Snell & Wilmer L.L.P.

                                       29
<PAGE>
                                     PART II

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

     Our common stock is publicly held and is traded on the New York and Pacific
Stock Exchanges. At the close of business on March 26, 2003, our common stock
was held of record by approximately 36,876 shareholders.

     See "Quarterly Stock Prices and Dividends Per Share" in Item 6 for a
description of the common stock price ranges on the composite tape, as reported
in the Wall Street Journal for 2002 and 2001, and the dividends declared during
each of the four quarters for 2002 and 2001.

                                       30
<PAGE>
                  ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

<TABLE>
<CAPTION>
                                                    2002            2001            2000           1999            1998
                                                ------------    ------------    ------------   ------------    ------------
OPERATING RESULTS                                        (dollars in thousands, except shares and per share amounts)
<S>                                             <C>             <C>             <C>            <C>             <C>
Operating revenues:
  Regulated electricity segment                 $  2,013,023    $  2,562,089    $  2,538,752   $  1,915,108    $  1,741,148
  Marketing and trading segment                      325,931         651,230         418,532        154,125         180,145
  Real estate segment                                236,388         168,908         158,365        130,169         124,188
  Other revenues                                      61,937          11,771           3,873            439              --
Income from continuing operations               $    215,153    $    327,367    $    302,332   $    269,772    $    242,892
Discontinued operations (a)                               --              --              --         38,000              --
Extraordinary charge - net of
  income taxes (b)                                        --              --              --       (139,885)             --
Cumulative effect of change in
  accounting-net of income taxes (c) (d)             (65,745)        (15,201)             --             --              --
                                                ------------    ------------    ------------   ------------    ------------
  Net income                                    $    149,408    $    312,166    $    302,332   $    167,887    $    242,892
                                                ============    ============    ============   ============    ============
COMMON STOCK DATA
Book value per share - year-end                 $      29.40    $      29.46    $      28.09   $      26.00    $      25.50
Earnings (loss) per weighted average
  common share outstanding:
  Continuing operations - basic                 $       2.53    $       3.86    $       3.57   $       3.18    $       2.87
  Discontinued operations                                 --              --              --           0.45              --
  Extraordinary charge                                    --              --              --          (1.65)             --
  Cumulative effect of change
    in accounting                                      (0.77)          (0.18)             --             --              --
                                                ------------    ------------    ------------   ------------    ------------
  Net income - basic                            $       1.76    $       3.68    $       3.57   $       1.98    $       2.87
                                                ============    ============    ============   ============    ============
  Continuing operations - diluted               $       2.53    $       3.85    $       3.56   $       3.17    $       2.85
  Net income - diluted                          $       1.76    $       3.68    $       3.56   $       1.97    $       2.85
Dividends declared per share                    $      1.625    $      1.525    $      1.425   $      1.325    $      1.225
Indicated annual dividend rate
  per share - year-end                          $       1.70    $       1.60    $       1.50   $       1.40    $       1.30
Weighted-average common shares
  outstanding - basic                             84,902,946      84,717,649      84,732,544     84,717,135      84,774,218
Weighted-average common shares
  outstanding - diluted                           84,963,921      84,930,140      84,935,282     85,008,527      85,345,946

BALANCE SHEET DATA
Total assets                                    $  8,425,806    $  7,939,399    $  7,122,667   $  6,571,023    $  6,789,975
                                                ============    ============    ============   ============    ============
Liabilities and equity:
Long-term debt less current
  maturities                                    $  2,881,695    $  2,673,078    $  1,955,083   $  2,206,052    $  2,048,961
Other liabilities                                  2,857,958       2,766,998       2,784,870      2,159,238       2,482,422
                                                ------------    ------------    ------------   ------------    ------------
  Total liabilities                                5,739,653       5,440,076       4,739,953      4,365,290       4,531,383
Minority interests:
  Non-redeemable preferred stock of APS                   --              --              --             --          85,840
  Redeemable preferred stock of APS                       --              --              --             --           9,401
Common stock equity                                2,686,153       2,499,323       2,382,714      2,205,733       2,163,351
                                                ------------    ------------    ------------   ------------    ------------
Total liabilities and equity                    $  8,425,806    $  7,939,399    $  7,122,667   $  6,571,023    $  6,789,975
                                                ============    ============    ============   ============    ============
</TABLE>

(a)  Tax benefit stemming from the resolution of income tax matters related to a
     former subsidiary MeraBank, A Federal Savings Bank.
(b)  Charges associated with a regulatory disallowance. See "Regulatory
     Accounting" in Note 1.
(c)  Change in accounting standards related to derivatives in 2001. See Note 18.
(d)  Change in accounting standards related to trading activities in 2002. See
     Note 18.

                                       31
<PAGE>
REGULATED ELECTRICITY AND MARKETING AND
TRADING SEGMENTS' REVENUES

<TABLE>
<CAPTION>
                                              2002            2001           2000           1999          1998
                                           -----------    -----------    -----------    -----------   -----------
Regulated electricity segment:                                      (dollars in thousands)
<S>                                        <C>            <C>            <C>            <C>           <C>
  Retail:
    Residential                            $   906,069    $   914,711    $   880,468    $   805,173   $   766,378
    Business                                   927,773        952,627        935,214        911,449       889,244
                                           -----------    -----------    -----------    -----------   -----------
  Total retail                               1,833,842      1,867,338      1,815,682      1,716,622     1,655,622

  Wholesale revenue on
    delivered electricity:
      Traditional contracts                      8,616         73,305        120,618         60,486        58,184
      Retail load hedge
        management (a)                         122,630        577,784        560,493        108,153            --
  Transmission for others                       29,803         25,971         14,765         11,348        11,058
  Other miscellaneous services                  18,132         17,691         27,194         18,499        16,284
                                           -----------    -----------    -----------    -----------   -----------
Total regulated electricity revenue          2,013,023      2,562,089      2,538,752      1,915,108     1,741,148
                                           -----------    -----------    -----------    -----------   -----------
Marketing and trading segment:
  Delivered marketing and
    trading:
      Generation sales other than
        Native Load (a)                         50,364        148,316        115,476         29,551            --
      Realized margin on
        electricity trading                     47,897         62,067         55,910          8,565         2,157
      Other delivered
        electricity (a)                        207,810        328,972        244,183        112,551       170,796
                                           -----------    -----------    -----------    -----------   -----------
  Total delivered marketing
    and trading                                306,071        539,355        415,569        150,667       172,953
                                           -----------    -----------    -----------    -----------   -----------
  Other marketing and trading:
    Realized margins on
      delivered commodities
      other than electricity                     7,771        (13,646)        (8,789)         2,483         7,192
    Prior period mark-to-
      market gains on
      contracts delivered
      during current period                    (40,072)        (1,059)        (2,079)            --            --
    Change in mark-to-
      market for future
      period deliveries                         52,161        126,580         13,831            975            --
                                           -----------    -----------    -----------    -----------   -----------
  Total other marketing and
    trading                                     19,860        111,875          2,963          3,458         7,192
                                           -----------    -----------    -----------    -----------   -----------
Total marketing and trading revenue            325,931        651,230        418,532        154,125       180,145
                                           -----------    -----------    -----------    -----------   -----------

Total regulated electricity and
  marketing and trading
  segments' revenues                       $ 2,338,954    $ 3,213,319    $ 2,957,284    $ 2,069,233   $ 1,921,293
                                           ===========    ===========    ===========    ===========   ===========
</TABLE>

(a)  The breakout of retail load hedge management and generation sales other
     than Native Load is not available for 1998. These amounts are included in
     other delivered electricity in the marketing and trading segment for 1998.

                                       32
<PAGE>
<TABLE>
<CAPTION>
                                            2002         2001         2000         1999         1998
                                         ----------   ----------   ----------   ----------   ----------
<S>                                      <C>          <C>           <C>          <C>          <C>
ELECTRIC SALES (MWH)
Regulated electricity segment:
  Retail:
    Residential                          10,443,820   10,334,860    9,780,680    8,774,822    8,310,689
    Business                             12,917,935   13,064,152   12,753,844   12,299,748   12,152,394
                                         ----------   ----------   ----------   ----------   ----------
  Total retail                           23,361,755   23,399,012   22,534,524   21,074,570   20,463,083
  Wholesale electricity
    delivered:
      Traditional contracts                 473,699    1,213,704    1,610,032    1,421,522    1,410,392
      Retail load hedge
        management (a)                    2,641,714    3,039,905    6,673,658      630,945           --
                                         ----------   ----------   ----------   ----------   ----------
Total regulated electricity              26,477,168   27,652,621   30,818,214   23,127,037   21,873,475
                                         ----------   ----------   ----------   ----------   ----------
Delivered marketing and trading:
  Generation sales other than
    Native Load (a)                       1,791,319    1,387,860    1,494,299    1,267,349           --
  Electricity trading                    16,924,509   12,031,055    9,259,054    5,679,023      846,864
  Other delivered electricity (a)         4,138,055    2,581,942    2,960,314    6,694,995    8,060,135
                                         ----------   ----------   ----------   ----------   ----------
Total delivered marketing
  and trading                            22,853,883   16,000,857   13,713,667   13,641,367    8,906,999
                                         ----------   ----------   ----------   ----------   ----------
Total regulated electricity
  and marketing and
  trading sales                          49,331,051   43,653,478   44,531,881   36,768,404   30,780,474
                                         ==========   ==========   ==========   ==========   ==========

ELECTRIC CUSTOMERS -
  AVERAGE
Retail:
  Residential                               801,801      776,339      749,285      719,774      689,871
  Business                                  100,228       98,198       94,128       90,496       87,831
                                         ----------   ----------   ----------   ----------   ----------
Total retail                                902,029      874,537      843,413      810,270      777,702
Wholesale                                        67           66           67           69           60
                                         ----------   ----------   ----------   ----------   ----------
Total average electric customers            902,096      874,603      843,480      810,339      777,762
                                         ==========   ==========   ==========   ==========   ==========
</TABLE>

(a)  The breakout of retail load hedge management and generation sales other
     than Native Load is not available for 1998. These amounts are included in
     other delivered electricity in the marketing and trading segment for 1998.

See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" for a discussion of certain information in the tables above.

                                       33
<PAGE>
QUARTERLY STOCK PRICES AND DIVIDENDS PER SHARE
STOCK SYMBOL: PNW
                                                                     Dividends
                                                                        Per
   2002                                High       Low       Close      Share
-----------                           ------     ------     ------     ------
1st Quarter                           $45.60     $39.36     $45.35     $0.400
2nd Quarter                            46.68      37.08      39.50      0.400
3rd Quarter                            39.72      25.82      27.76      0.400
4th Quarter                            34.36      21.70      34.09      0.425

                                                                     Dividends
                                                                        Per
   2001                                High       Low       Close      Share
-----------                           ------     ------     ------     ------
1st Quarter                           $47.96     $39.06     $45.87     $0.375
2nd Quarter                            50.70      45.20      47.40      0.375
3rd Quarter                            49.93      37.65      39.70      0.375
4th Quarter                            43.50      38.00      41.85      0.400

                                       34
<PAGE>
                  ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
                OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

                                  INTRODUCTION

     In this Item, we explain the results of operations, general financial
condition and outlook for Pinnacle West and our subsidiaries: APS, Pinnacle West
Energy, APS Energy Services, SunCor and El Dorado, including:

     *    the changes in our earnings from 2001 to 2002 and from 2000 to 2001;

     *    our capital needs, liquidity and capital resources;

     *    our critical accounting policies;

     *    our business outlook and major factors that affect our financial
          outlook; and

     *    our management of market risks.

     Throughout this Item, we refer to specific "Notes" in the Notes to
Consolidated Financial Statements in Item 8 of this report. These Notes add
further details to the discussion.

                                BUSINESS OVERVIEW

     The Company owns all of the outstanding common stock of APS. APS is an
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 owned by APS. APS also
generates, sells and delivers electricity to wholesale customers in the western
United States. The marketing and trading division sells, in the wholesale
market, APS and Pinnacle West Energy generation output that is not needed for
APS' Native Load, which includes loads for retail customers and traditional
cost-of-service wholesale customers. APS does not distribute any products.

     Our other major subsidiaries are:

     *    Pinnacle West Energy, through which we conduct our competitive
          electricity generation operations;

     *    APS Energy Services, which provides competitive commodity-related
          energy services (such as direct access commodity contracts, energy
          procurement and energy supply consultation) and energy-related
          products and services (such as energy master planning, energy use
          consultation and facility audits, cogeneration analysis and
          installation and project management) to commercial, industrial and
          institutional retail customers in the western United States;

     *    SunCor, a developer of residential, commercial and industrial real
          estate projects in Arizona, New Mexico and Utah; and

                                       35
<PAGE>
     *    El Dorado, which owns a majority interest in NAC (specializing in
          spent nuclear fuel technology) and holds miscellaneous small
          investments, including interests in Arizona community-based ventures.

             SUMMARY OF KEY FACTORS AFFECTING OUR FINANCIAL OUTLOOK

     We believe the following are among the key factors affecting our financial
outlook:

     *    The following ACC regulatory matters:

          *    APS' $500 million financing application, which the ACC approved
               on March 27, 2003;

          *    the implementation of the ACC-mandated process by which APS must
               competitively procure energy; and

          *    APS' general rate case to be filed in 2003.

     *    Wholesale power market conditions in the western United States.

We discuss each of these, and other factors in detail below in the section
entitled "Factors Affecting Our Financial Outlook."

            EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENT

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

     *    Our regulated electricity segment, which consists of regulated
          traditional retail and wholesale electricity businesses and related
          activities and includes electricity transmission, distribution and
          generation;

     *    our marketing and trading segment, which consists of our competitive
          energy business activities, including wholesale marketing and trading
          and APS Energy Services' commodity-related energy services; and

     *    our real estate segment, which consists of SunCor's real estate
          development and investment activities.

     The following tables summarize net income and segment details for the years
ended December 31, 2002, 2001 and 2000 for Pinnacle West and each of our
subsidiaries (dollars in millions):

                                       36
<PAGE>
<TABLE>
<CAPTION>
                                                      REGULATED    MARKETING AND
                                         TOTAL       ELECTRICITY      TRADING      REAL ESTATE    OTHER (a)
                                       ---------     -----------   -------------   -----------    ---------
<S>                                    <C>            <C>            <C>            <C>           <C>
2002
----
APS (b)                                $     199      $     198      $       1      $      --     $      --
Pinnacle West Energy (b)                     (19)           (21)             2             --            --
APS Energy Services (c)                       28             --             23             --             5
SunCor                                        19             --             --             19            --
El Dorado (principally NAC) (c)              (55)            --             --             --           (55)
Parent company (c)                            43             (7)            32             --            18
                                       ---------      ---------      ---------      ---------     ---------
  Income (loss) before
    accounting change                        215            170             58             19           (32)
Cumulative effect of change in
  accounting - net of income
  taxes (d)                                  (66)            --            (66)            --            --
                                       ---------      ---------      ---------      ---------     ---------
Net income (loss)                      $     149      $     170      $      (8)     $      19     $     (32)
                                       =========      =========      =========      =========     =========

                                                      REGULATED    MARKETING AND
                                         TOTAL       ELECTRICITY      TRADING      REAL ESTATE      OTHER
                                       ---------     -----------   -------------   -----------    ---------
2001
----
APS (b)                                $     281      $     139      $     142      $      --     $      --
Pinnacle West Energy (b)                      18             18             --             --            --
APS Energy Services (c)                      (10)            --            (11)            --             1
SunCor                                         3             --             --              3            --
El Dorado                                     --             --             --             --            --
Parent company                                35             (5)            40             --            --
                                       ---------      ---------      ---------      ---------     ---------
  Income before
    accounting change                        327            152            171              3             1
Cumulative effect of change in
  accounting - net of income
  taxes (e)                                  (15)           (15)            --             --            --
                                       ---------      ---------      ---------      ---------     ---------
Net income                             $     312      $     137      $     171      $       3     $       1
                                       =========      =========      =========      =========     =========

                                                      REGULATED    MARKETING AND
                                         TOTAL       ELECTRICITY      TRADING      REAL ESTATE      OTHER
                                       ---------     -----------   -------------   -----------    ---------
2000
----
APS                                    $     307      $     228      $      79      $      --     $      --
Pinnacle West Energy                          (2)            (2)            --             --            --
APS Energy Services (c)                      (13)            --            (16)            --             3
SunCor                                        11             --             --             11            --
El Dorado                                      2             --             --             --             2
Parent company                                (3)            (5)             2             --            --
                                       ---------      ---------      ---------      ---------     ---------
Net income                             $     302      $     221      $      65      $      11     $       5
                                       =========      =========      =========      =========     =========
</TABLE>

                                       37
<PAGE>
     (a)  Primarily includes activities related to El Dorado, principally NAC.
          See Note 22.

     (b)  Consistent with APS' October 2001 ACC filing, APS entered into
          agreements with its affiliates to buy power. The agreements reflected
          a price based on the fully-dispatchable dedication of the Pinnacle
          West Energy generating assets to APS' Native Load customers. In 2002,
          Pinnacle West Energy recorded a $49 million pretax write-off related
          to the cancellation of Redhawk Units 3 and 4.

     (c)  APS Energy Services' and El Dorado's net income is primarily reported
          before income taxes. The income tax expense or benefit for these
          subsidiaries is recorded at the parent company.

     (d)  We recorded a $66 million after-tax charge in 2002 for the cumulative
          effect of a change in accounting for trading activities, for the early
          adoption of EITF 02-3," Issues Involved in Accounting for Derivative
          Contracts Held for Trading Purposes and Contracts Involved in Energy
          Trading and Risk Management Activities," as of October 1, 2002. See
          Note 18.

     (e)  APS recorded a $15 million after-tax charge in 2001 for the cumulative
          effect of a change in accounting for derivatives related to the
          adoption of SFAS No. 133, "Accounting for Derivative Instruments and
          Hedging Activities." See Note 18.

     See Note 17 for additional financial information regarding our business
segments.

                              RESULTS OF OPERATIONS

GENERAL

     Throughout the following explanations of our results of operations, we
refer to "gross margin." With respect to our regulated electricity segment and
marketing and trading segment, gross margin refers to electric operating
revenues less purchased power and fuel costs. Our real estate segment gross
margin refers to real estate revenues less real estate operations costs of
SunCor. Other gross margin refers to other operating revenues less other
operating expenses, which includes El Dorado's investment in NAC, which we began
consolidating in our financial statements in July 2002 (see Note 22). Other
gross margin also includes amounts related to APS Energy Services' energy
consulting services.

2002 COMPARED WITH 2001

     Our consolidated net income for the year ended December 31, 2002 was $149
million compared with $312 million for the prior year. We recognized a $66
million after-tax charge in 2002 for the cumulative effect of a change in
accounting for trading activities for the early adoption of EITF 02-3 on October
1, 2002 (see Note 18). In 2001, we recognized a $15 million after-tax charge for
the cumulative effect of a change in accounting for derivatives, as required by
SFAS No. 133 (see Note 18).

     Our income before accounting change for the year ended December 31, 2002
was $215 million compared with $327 million for the prior year. The
period-to-period comparison was lower due to:

                                       38
<PAGE>
     *    lower earnings contributions from our marketing and trading
          activities, reflecting lower liquidity and lower price volatility in
          the wholesale power markets in the western United States;

     *    pretax losses of $59 million related to our investment in NAC;

     *    a $49 million pretax write-off related to the cancellation of Redhawk
          Units 3 and 4, of which $47 million was recorded in operations and
          maintenance expense and $2 million was recorded in capitalized
          interest; and

     *    severance costs of approximately $36 million pretax recorded in the
          second half of 2002 relating to a voluntary workforce reduction.

     The above decreases were partially offset by:

     *    increased earnings contributions from our regulated electricity
          activities, reflecting lower replacement power costs for power plant
          outages, retail customer growth and higher average usage per customer,
          partially offset by the effects of milder weather, retail electricity
          price decreases and higher costs for purchased power and gas due to
          higher hedged gas and power prices; and

     *    increased earnings contributions from real estate operations,
          primarily as a result of increased sales activities.

     For additional details, see the following discussion.

                                       39
<PAGE>
     The major factors that increased (decreased) income before accounting
change were as follows (dollars in millions):

<TABLE>
<CAPTION>
                                                                                  Increase
                                                                                 (Decrease)
                                                                                 ----------
<S>                                                                               <C>
Regulated electricity segment gross margin:
  Lower replacement power costs for plant outages due to lower
    market prices and fewer unplanned outages                                     $    127
  Increased purchased power and fuel costs due to higher hedged gas
    and power prices, partially offset by improved hedge management,
    net of mark-to-market reversals                                                     (9)
  Higher retail sales volumes due to customer growth and higher
    average usage, excluding weather effects                                            38
  2001 charges related to purchased power contracts with Enron
    and its affiliates                                                                  13
  Retail price reductions effective July 1, 2001 and July 1, 2002                      (28)
  Effects of milder weather on retail sales                                            (27)
  Miscellaneous factors, net                                                            (2)
                                                                                  --------
        Net increase in regulated electricity segment gross margin                     112
                                                                                  --------
Marketing and trading segment gross margin:
  Decrease in generation sales other than Native Load due to lower
    market prices partially offset by higher sales volumes                             (66)
  Lower realized wholesale margins net of related mark-to-market
    reversals due to lower prices and volumes                                          (91)
  Higher competitive retail sales in California by APS Energy Services                  32
  2001 write-off of prior period mark-to-market value related to trading
    with Enron and its affiliates                                                        8
  Lower mark-to-market reversals due to the adoption of EITF 02-3                        8
  Lower mark-to-market gains for future delivery due to lower market
    liquidity and lower price volatility                                               (76)
                                                                                  --------
        Net decrease in marketing and trading segment gross margin                    (185)
                                                                                  --------
Net decrease in regulated electricity and marketing and trading segments'
  gross margins                                                                        (73)
Higher real estate segment gross margin primarily due to increased sales
  activities                                                                            16
Lower other gross margin primarily related to NAC losses                               (44)
Higher operations and maintenance expense related to a $47 million
  write-off of Redhawk Units 3 and 4 and 2002 severance costs of
  approximately $36 million, partially offset by lower generation
  reliability costs                                                                    (54)
Higher taxes other than income taxes                                                    (7)
Lower other income primarily due to a 2001 insurance recovery of
  environmental remediation costs                                                      (11)
Higher net interest expense primarily due to higher debt balances and lower
  capitalized interest                                                                 (16)
Miscellaneous factors, net                                                               2
                                                                                  --------
        Net decrease in income before income taxes                                    (187)
Lower income taxes primarily due to lower income                                        75
                                                                                  --------
        Net decrease in income before accounting change                           $   (112)
                                                                                  ========
</TABLE>

                                       40
<PAGE>
     REGULATED ELECTRICITY SEGMENT GROSS MARGIN

     Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $549 million lower in the year ended
December 31, 2002, compared with the prior year as a result of:

     *    decreased revenues related to traditional wholesale sales as a result
          of lower sales volumes and lower prices ($64 million);
     *    decreased revenues related to retail load hedge management wholesale
          sales, primarily as a result of lower prices and lower sales volumes
          ($455 million);
     *    decreased retail revenues related to milder weather ($60 million);
     *    increased retail revenues related to customer growth and higher
          average usage, excluding weather effects ($69 million);
     *    decreased retail revenues related to reductions in retail electricity
          prices ($28 million); and
     *    other miscellaneous factors ($11 million net decrease).

     Regulated electricity segment purchased power and fuel costs were $661
million lower in the year ended December 31, 2002, compared with the prior year
as a result of:

     *    decreased costs related to traditional wholesale sales as a result of
          lower sales volumes and lower prices ($64 million);
     *    decreased costs related to retail load hedge management wholesale
          sales, primarily as a result of lower prices and lower sales volumes
          ($460 million);
     *    increased costs related to higher prices for hedged natural gas and
          purchased power, net of mark-to-market reversals ($14 million);
     *    decreased costs related to the effects of milder weather on retail
          sales ($33 million);
     *    increased costs related to retail sales growth, excluding weather
          effects ($31 million);
     *    charges in 2001 related to purchased power contracts with Enron and
          its affiliates ($13 million net decrease);
     *    decreased replacement power costs for power plant outages due to lower
          market prices and fewer unplanned outages ($127 million); and
     *    miscellaneous factors ($9 million net decrease).

     MARKETING AND TRADING SEGMENT GROSS MARGIN

     Marketing and trading segment revenues were $325 million lower in the year
ended December 31, 2002, compared with the prior year as a result of:

     *    decreased revenues from generation sales other than Native Load
          primarily due to lower market prices partially offset by higher sales
          volumes ($98 million);
     *    lower realized wholesale revenues net of related mark-to-market
          reversals primarily due to lower prices partially offset by higher
          volumes ($273 million);
     *    increased revenues from higher competitive retail sales in California
          by APS Energy Services ($105 million);
     *    2001 write-off of prior period mark-to-market value related to trading
          with Enron and its affiliates ($8 million increase);
     *    higher revenues related to the adoption of EITF 02-3 ($8 million); and

                                       41
<PAGE>
     *    lower mark-to-market gains for future delivery primarily as a result
          of lower market liquidity and lower price volatility, resulting in
          lower volumes ($75 million).

     Marketing and trading segment purchased power and fuel costs were $140
million lower in the year ended December 31, 2002, compared to the prior year as
a result of:

     *    decreased fuel costs related to generation sales other than Native
          Load primarily because of lower natural gas prices partially offset by
          higher sales volumes ($32 million);
     *    decreased purchased power costs related to other realized marketing
          activities in the current period primarily due to lower prices
          partially offset by higher volumes ($182 million);
     *    increased purchased power costs related to higher competitive retail
          sales in California by APS Energy Services ($73 million); and
     *    change in mark-to-market fuel costs for future delivery ($1 million
          increase).

     OTHER INCOME STATEMENT ITEMS

     The increase in real estate segment gross margin of $16 million was
primarily due to increased sales activities.

     The decrease in other gross margin of $44 million was primarily due to
losses on El Dorado's investment in NAC (see further discussion in Note 22).
These losses for 2002 totaled approximately $59 million on a pretax basis and
were primarily related to NAC contracts with two customers ($51 million was
recorded in other gross margin and $8 million was recorded in other expense). We
believe we have reserved our exposure with respect to these contracts in all
material respects and, as a result, we consider these charges to be
non-recurring.

     The increase in operations and maintenance expense of $54 million was due
to a $47 million write-off related to the cancellation of Redhawk Units 3 and 4,
severance costs of $36 million related to a 2002 voluntary workforce reduction
and other costs of $9 million, partially offset by lower costs related to
generation reliability, plant outages and maintenance costs of $38 million.

     The increase in taxes other than income taxes of $7 million is primarily
due to increased property taxes on higher property balances.

     Other income decreased $11 million primarily due to an insurance recovery
recorded in 2001 related to environmental remediation costs and other costs (see
Note 19).

     Other expense was comparable with the prior year primarily due to losses
recorded related to El Dorado's investment in NAC of approximately $8 million
(see further discussion in Note 22), offset by $8 million of lower miscellaneous
non-operating costs (see Note 19).

     Net interest expense increased $16 million primarily because of higher debt
balances related to our generation construction program and lower capitalized
interest on our generation construction program due to completion of Redhawk
Units 1 and 2 in mid-2002.

                                       42
<PAGE>
2001 COMPARED WITH 2000

     Our consolidated net income for the year ended December 31, 2001 was $312
million compared with $302 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 18).

     Our income before accounting change for the year ended December 31, 2001
was $327 million compared with $302 million for the prior year. The
period-to-period comparison benefited from:

     *    strong marketing and trading results, including significant benefits
          recognized in the third quarter of 2001 from structured trading
          activities; and

     *    retail customer growth.

     The above increases were partially offset by:

     *    lower earnings contributions from our regulated electricity
          activities, reflecting higher purchased power and fuel costs, due in
          part to increased power plant maintenance, generation reliability
          measures and continuing retail electricity price decreases; and

     *    2001 charges related to Enron and its affiliates.

     For additional details, see the following discussion.

                                       43
<PAGE>
     The major factors that increased (decreased) income before accounting
change were as follows (dollars in millions):

<TABLE>
<CAPTION>
                                                                                   Increase
                                                                                  (Decrease)
                                                                                  ----------
<S>                                                                                <C>
Regulated electricity segment gross margin:
  Higher replacement power costs for plant outages related to higher
    market prices                                                                  $    (70)
  Retail price reductions effective July 1, 2001 and July 1, 2000                       (27)
  Charges related to purchased power contracts with Enron and its affiliates            (13)(a)
  Higher retail sales primarily related to customer growth                               35
  Miscellaneous revenues                                                                  3
                                                                                   --------
        Net decrease in regulated electricity segment gross margin                      (72)
                                                                                   --------
Marketing and trading segment gross margin:
  Increase from generation sales other than Native Load due to higher
    market prices                                                                        25
  Higher realized wholesale margin net of related mark-to-market reversals               61
  Change in prior period mark-to-market value related to
    trading with Enron and its affiliates                                                (8)(a)
  Increase in mark-to-market value related to future periods                            113
                                                                                   --------
        Net increase in marketing and trading segment gross margin                      191
                                                                                   --------
Net increase in regulated electricity and marketing and trading segments'
  gross margins                                                                         119
Decrease in real estate segment contributions                                            (8)
Higher operations and maintenance expense related to 2001 generation
  reliability program                                                                   (42)
Higher operations and maintenance expense related primarily to employee
  benefits, plant outage and maintenance and other costs                                (38)
Lower net interest expense primarily due to higher capitalized interest                  17
Higher other net expense                                                                 (4)
                                                                                   --------
  Net increase in income before income taxes                                             44
Higher income taxes primarily due to higher income                                      (19)
                                                                                   --------
  Net increase in income before accounting change                                  $     25
                                                                                   ========
</TABLE>

     (a)  We recorded charges totaling $21 million before income taxes for
          exposure to Enron and its affiliates in the fourth quarter of 2001.

     REGULATED ELECTRICITY SEGMENT GROSS MARGIN

     Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $23 million higher in the year ended
December 31, 2001 compared to the prior year as a result of:

     *    decreased revenues related to other wholesale sales and miscellaneous
          revenues as a result of lower sales volumes ($28 million);

                                       44
<PAGE>
     *    increased retail revenues primarily related to higher sales volumes
          primarily due to customer growth ($78 million); and
     *    decreased retail revenues related to reductions in retail electricity
          prices ($27 million).

     Regulated electricity segment purchased power and fuel costs were $95
million higher in the year ended December 31, 2001 compared to the prior year as
a result of:

     *    decreased costs related to other wholesale sales as a result of lower
          volumes ($31 million);
     *    higher replacement power costs primarily due to higher market prices
          and increased plant outages ($70 million), including costs of $12
          million related to a Palo Verde outage extension to replace fuel
          control element assemblies;
     *    higher costs related to retail sales volumes due to customer growth
          ($43 million); and
     *    charges related to purchased power contracts with Enron and its
          affiliates ($13 million).

     MARKETING AND TRADING SEGMENT GROSS MARGIN

     Marketing and trading segment revenues were $233 million higher in the year
ended December 31, 2001 compared with the prior year as a result of:

     *    increased revenues related to generation sales other than Native Load
          as a result of higher average market prices ($32 million);
     *    increased realized wholesale revenues net of related mark-to-market
          reversals primarily due to more transactions ($96 million);
     *    decreased prior period mark-to-market value related to trading with
          Enron and its affiliates ($8 million); and
     *    increased mark-to-market value for future periods primarily as a
          result of more forward sales volumes ($113 million).

     Marketing and trading segment purchased power and fuel costs were $42
million higher in the year ended December 31, 2001 compared to the prior year as
a result of:

     *    increased fuel costs related to generation sales other than Native
          Load as a result of higher fuel prices ($7 million); and
     *    increased purchased power and fuel costs net of related mark-to-market
          reversals primarily due to more transactions ($35 million).

     OTHER INCOME STATEMENT ITEMS

     The decrease in real estate segment profits of $8 million resulted
primarily from reduced sales of land and homes by SunCor.

     The increase in operations and maintenance expenses of $80 million
primarily related to the 2001 generation summer reliability program (the
addition of generating capability to enhance reliability for the summer of 2001
($42 million)) and increased employee benefit costs, plant outage and

                                       45
<PAGE>
maintenance and other costs ($38 million). The comparison reflects Pinnacle
West's $10 million provision for our credit exposure related to the California
energy situation, $5 million of which was recorded in the fourth quarter of 2000
and $5 million of which was recorded in the first quarter of 2001.

     Net other expense increased $4 million primarily because of a change in the
market value of El Dorado's investment in a technology-related venture capital
partnership in 2000 and other nonoperating costs partially offset by an
insurance recovery of environmental remediation costs (see Note 19).

     Interest expense decreased by $17 million primarily because of increased
capitalized interest resulting from our generation construction plan partially
offset with higher interest expense due to higher debt balances.

     See "Regulatory Matters - 1999 Settlement Agreement" in Note 3 for a
discussion of the 1999 Settlement Agreement under which, among other things, APS
agreed to five annual retail electricity price reductions of 1.5%, with the last
decrease to take effect July 1, 2003.

                         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, 2002 and estimated capital expenditures for the next three
years.

                              CAPITAL EXPENDITURES
                              (dollars in millions)

                                             Actual             Estimated
                                             ------     ------------------------
                                              2002      2003      2004      2005
                                              ----      ----      ----      ----
APS
  Delivery                                    $369      $273      $275      $329
  Generation (a)                               132       123        99       164
  Other (e)                                     --         5         5         5
                                              ----      ----      ----      ----
     Subtotal                                  501       401       379       498
Pinnacle West Energy (a) (b)                   374       268        31        20
SunCor (c)                                      72        64        23        20
Other (d)                                       37        17        13        14
                                              ----      ----      ----      ----
     Total                                    $984      $750      $446      $552
                                              ====      ====      ====      ====

(a)  As discussed below under "Factors Affecting Our Financial Outlook," as part
     of its 2003 general rate case, APS intends to seek rate base treatment of
     certain power plants in Arizona currently owned by Pinnacle West Energy
     (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and
     Saguaro Unit 3).

                                       46
<PAGE>
(b)  See Note 11 for further discussion of Pinnacle West Energy's generation
     construction program and "Capital Resources and Cash Requirements -
     Pinnacle West Energy" below. These amounts do not include an expected
     reimbursement in 2004 by SNWA of about $100 million, assuming SNWA
     exercises its option to purchase a 25% interest in the Silverhawk project
     at that time.
(c)  Consists primarily of capital expenditures for land development and retail
     and office building construction reflected in the "Change in real estate
     investments" in the Consolidated Statements of Cash Flows.
(d)  Primarily related to the parent company and APS Energy Services.
(e)  The other amounts relate to capital expenditures for our marketing and
     trading segment. These costs were in the parent company for 2002.

     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
systems. In addition, APS began several major transmission projects in 2001.
These projects are periodic in nature and are driven by strong regional customer
growth. APS expects to spend about $105 million on major transmission projects
during the 2003 to 2005 time frame, and these amounts are included in
"APS-Delivery" in the table above.

     Generation capital expenditures are comprised of various improvements for
APS' existing fossil and nuclear plants and the replacement of Palo Verde steam
generators. Examples of the types of projects included in this category are
additions, upgrades and capital replacements of various power plant equipment
such as turbines, boilers and environmental equipment. Generation also contains
nuclear fuel expenditures of approximately $30 million annually for 2003 to
2005.

     Replacement of the steam generators in Palo Verde Unit 2 is presently
scheduled for completion during the fall outage of 2003. The Palo Verde owners
have approved the manufacture of two additional sets of steam generators. We
expect that these generators will be installed in Units 1 and 3 in the 2005 to
2008 time frame. Our portion of steam generator expenditures for Units 1, 2 and
3 is approximately $145 million, which will be spent from 2003 through 2008. In
2003 through 2005, $94 million of the costs are included in the generation
capital expenditures table above and would be funded with internally-generated
cash or external financings.

     CONTRACTUAL OBLIGATIONS

     The following table summarizes actual contractual requirements for the year
ended December 31, 2002 and estimated contractual commitments for the next five
years and thereafter (dollars in millions):

                                       47
<PAGE>
<TABLE>
<CAPTION>
                                           Actual                       Estimated
                                           ------   ---------------------------------------------------
                                                                                                 There-
                                            2002     2003     2004     2005     2006     2007    after
                                           ------   ------   ------   ------   ------   ------   ------
<S>                                        <C>      <C>      <C>      <C>      <C>      <C>      <C>
Long-term debt payments:
  APS                                      $  337   $   --   $  205   $  400   $   84   $   --   $1,518
  Pinnacle West                                --      275      215       --      300       --       --
  SunCor                                        3       --      126       --        3       --       15
  El Dorado                                    13        1        1        1       --       --       --
                                           ------   ------   ------   ------   ------   ------   ------
Total long-term debt payments                 353      276      547      401      387       --    1,533
Capital lease payments                          1        5        5        4        3        3        6
Operating lease payments                       69       70       66       64       63       63      478
Purchase power and fuel commitments           338      173       82       28       31       17      162
                                           ------   ------   ------   ------   ------   ------   ------
Total contractual commitments              $  761   $  524   $  700   $  497   $  484   $   83   $2,179
                                           ======   ======   ======   ======   ======   ======   ======
</TABLE>

     OFF-BALANCE SHEET ARRANGEMENTS

     In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities." FIN No. 46 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.
FIN No. 46 is effective immediately for any VIE created after January 31, 2003
and is effective July 1, 2003 for VIEs created before February 1, 2003.

     In 1986, APS entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. See Note 9 for
further information about the sale-leaseback transactions. Based on our
preliminary assessment of FIN No. 46, we do not believe we will be required to
consolidate the Palo Verde SPEs. However, we continue to evaluate the
requirements of the new guidance to determine what impact, if any, it will have
on our financial statements.

     APS is also exposed to losses under the Palo Verde sale-leaseback
agreements upon the occurrence of certain events that APS does not consider to
be reasonably likely to occur. Under certain circumstances (for example, the NRC
issuing specified violation orders with respect to Palo Verde or the occurrence
of specified nuclear events), APS would be required to assume the debt
associated with the transactions, make specified payments to the equity
participants and take title to the leased Unit 2 interests, which, if
appropriate, may be required to be written down in value. If such an event had
occurred as of December 31, 2002, APS would have been required to assume
approximately $285 million of debt and pay the equity participants approximately
$200 million.

     GUARANTEES

     We and certain of our subsidiaries have issued guarantees in support of our
unregulated businesses. We have also obtained surety bonds on behalf of APS

                                       48
<PAGE>
Energy Services. We have not recorded any liability on our Consolidated Balance
Sheets with respect to these obligations. See Note 23 for additional information
regarding guarantees.

     CREDIT RATINGS

     The ratings of securities of Pinnacle West and APS as of March 28, 2003 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 Pinnacle West's or APS' securities and
serve to increase those companies' cost of and access to capital.

                             Moody's      Standard & Poor's       Fitch
                             -------      -----------------       -----
PINNACLE WEST
  Senior unsecured            Baa2               BBB-              BBB
  Commercial paper            P-2                A-2               F-2

APS
  Senior secured              A3                 A-                A-
  Senior unsecured            Baa1               BBB               BBB+
  Secured lease
    obligation bonds          Baa2               BBB               BBB
  Commercial paper            P-2                A-2               F-2

     On November 4, 2002, Standard & Poor's affirmed the APS debt ratings in the
above chart, but lowered Pinnacle West's senior unsecured debt rating from BBB
to BBB- "because of the structural subordination of this debt as compared to the
unsecured debt at APS." On that same date, Standard & Poor's lowered APS'
corporate credit rating from BBB+ to BBB and affirmed the BBB corporate credit
rating of Pinnacle West. Standard & Poor's assigned a stable outlook to the
ratings. All of Pinnacle West's and APS' credit ratings remain investment grade.
In December 2002, Fitch placed certain of our debt and that of APS on Ratings
Watch Negative. The ratings watch affects our senior unsecured debt and
commercial paper ratings. It also affects all of APS' debt ratings, with the
exception of its commercial paper rating.

     On December 31, 2002, Moody's affirmed the ratings set forth above.

     DEBT PROVISIONS

     Pinnacle West's and APS' significant debt covenants related to their
respective financing arrangements include a debt-to-total-capitalization ratio
and an interest coverage test. Pinnacle West and APS are in compliance with such
covenants and each anticipates it will continue to meet all the significant
covenant requirement levels. The ratio of debt to total capitalization cannot
exceed 65% for both the Company and APS. At December 31, 2002, the ratios are
approximately 54% and 48% for the parent company and APS, respectively. The
provisions regarding interest coverage require a minimum cash coverage of two
times the interest requirements for both the Company and APS. The coverages are
approximately 4 times for the parent company, 5 times for the APS bank
agreements and 15 times for the APS mortgage indenture. Failure to comply with

                                       49
<PAGE>
such covenant levels would result in an event of default which, generally
speaking, would require the immediate repayment of the debt subject to the
covenants.

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

     All of Pinnacle West's bank agreements contain "cross-default" provisions
that would result in defaults and the potential acceleration of payment under
these loan agreements if Pinnacle West or APS were to default under other
agreements. All of APS' bank agreements contain cross-default provisions that
would result in defaults and the potential acceleration of payment under these
bank agreements if APS were to default under other agreements. Pinnacle West's
and APS' credit agreements generally contain provisions under which the lenders
could refuse to advance loans in the event of a material adverse change in our
financial condition or financial prospects.

     PINNACLE WEST (PARENT COMPANY)

     Our primary cash needs are for dividends to our shareholders; equity
infusions into our subsidiaries, primarily Pinnacle West Energy; and interest
payments and optional and mandatory repayments of principal on our long-term
debt (see the table above for our contractual requirements, including our debt
repayment obligations, but excluding optional repayments). On October 23, 2002,
our board of directors increased the common stock dividend to an indicated
annual rate of $1.70 per share from $1.60 per share, effective with the December
1, 2002 dividend payment. The level of our common dividends and future dividend
growth will be dependent on a number of factors including, but not limited to,
payout ratio trends, free cash flow and financial market conditions.

     Our primary sources of cash are dividends from APS, external financings and
cash distributions from our other subsidiaries, primarily SunCor. For the years
2000 through 2002, total dividends from APS were $510 million and total
distributions from SunCor were $33 million. For the year ended December 31,
2002, dividends from APS were approximately $170 million and distributions from
SunCor were approximately $13 million. We expect SunCor to make cash
distributions to the parent company of $80 million to $100 million annually in
2003 through 2005 due to anticipated accelerated asset sales activity.

     On December 23, 2002, we issued 6,555,000 shares of common stock, no par
value, which resulted in net proceeds of $199 million. See Note 7.

     We have financed Pinnacle West Energy's generation construction program
premised upon Pinnacle West Energy's receipt of APS' generation assets by the
end of 2002. On November 22, 2002, the ACC approved APS' request (Interim
Financing Application) to permit APS to (a) make short-term advances to Pinnacle
West in the form of an inter-affiliate line of credit in the amount of $125
million, or (b) guarantee $125 million of Pinnacle West's short-term debt,
subject to certain conditions. As of December 31, 2002, there were no borrowings
outstanding under this financing arrangement. On March 27, 2003, the ACC
authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up
to $500 million of Pinnacle West Energy debt, or a combination of both, not to

                                       50
<PAGE>
exceed $500 million in the aggregate. See "Factors Affecting our Financial
Outlook - Regulatory Matters" and "ACC Applications" in Note 3 for additional
information.

     In 2002, the parent company issued $215 million in long-term debt and had
no repayments of long-term debt (see Note 6).

     The parent company's outstanding long and short-term debt was approximately
$887 million at December 31, 2002. At December 31, 2002, our commitments totaled
$475 million, which were available to support the issuance of commercial paper
or to be used as bank borrowings. At December 31, 2002, we had about $24 million
of commercial paper outstanding and $72 million of short-term borrowings. Our
long-term debt including current maturities totaled $791 million at December 31,
2002.

     In mid-2003, we will need to refinance approximately $475 million of parent
company indebtedness, including a total of $225 million we expect to borrow
under an existing credit facility. We expect that this indebtedness will be
repaid through funds borrowed by Pinnacle West Energy from APS under the $500
million financing arrangement recently approved by the ACC.

     As part of a multi-employer pension plan sponsored by Pinnacle West, we
contribute at least the minimum amount required under IRS regulations, but no
more than the maximum tax-deductible amount. The minimum required funding takes
into consideration the value of the fund assets and our pension obligation. We
elected to contribute cash to our pension plan in each of the last five years;
our minimum required contributions during each of those years was zero.
Specifically, we contributed $27 million for 2002, $24 million for 2001, $44
million for 2000, $25 million for 1999 and $14 million for 1998. APS and other
subsidiaries fund their share of the pension contribution, of which APS
represents approximately 90% of the total funding amounts described above. The
assets in the plan are mostly domestic common stocks, bonds and real estate. We
currently forecast a pension contribution in 2003 of approximately $50 million,
all or part of which may be required. If the fund performance continues to
decline as a result of a continued decline in equity markets, larger
contributions may be required in future years.

     As a result of a change in IRS guidance, we claimed a tax deduction related
to an APS tax accounting method change on the 2001 federal consolidated income
tax return. The accelerated deduction has resulted in a $200 million reduction
in the current income tax liability. In 2002, we received an income tax refund
of approximately $115 million related to our 2001 federal consolidated income
tax return.

     APS

     APS' capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. See "Factors Affecting Our
Financial Outlook - Regulatory Matters" below and Note 3 for discussion of the
$500 million financing arrangement between APS and Pinnacle West Energy recently
approved by the ACC. See "Pinnacle West (Parent Company)" above and Note 3 for
discussion of a $125 million financing arrangement between APS and Pinnacle
West.

                                       51
<PAGE>
     APS pays for its capital requirements with cash from operations and, to the
extent necessary, external financings. APS has historically paid for its
dividends to Pinnacle West with cash from operations.

     In 2002, APS issued $375 million in long-term debt, refinanced $90 million
in long-term debt and redeemed approximately $247 million in long-term debt (see
Note 6). On April 7, 2003, APS will redeem $33 million of its first mortgage
bonds.

     APS' outstanding debt was approximately $2.2 billion at December 31, 2002.
At December 31, 2002, APS had 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, 2002, APS had
no outstanding commercial paper or bank borrowings.

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

     PINNACLE WEST ENERGY

     The costs of Pinnacle West Energy's construction of generating capacity
from 2000 through 2004 are expected to be about $1.4 billion. This does not
reflect an expected reimbursement in 2004 by SNWA of about $100 million of
Pinnacle West Energy's cumulative capital expenditures in the Silverhawk
project, assuming SNWA exercises its option to purchase a 25% interest in the
project. Pinnacle West Energy is currently funding its capital requirements
through capital infusions from Pinnacle West, which finances those infusions
through debt and equity financings and internally-generated cash. See the
capital expenditures table above for actual capital expenditures in 2002 and
projected capital expenditures for the next three years.

     See "Factors Affecting Our Financial Outlook - Regulatory Matters" below
and Note 3 for discussion of the $500 million.

     OTHER SUBSIDIARIES

     During the past three years, SunCor funded its cash requirements with cash
from operations and its own external financings. SunCor's capital needs consist
primarily of capital expenditures for land development and retail and office
building construction. See the capital expenditures table above for actual
capital expenditures in 2002 and projected capital expenditures for the next
three years. SunCor expects to fund its capital requirements with cash from
operations and external financings.

     In 2002, SunCor issued $50 million in long-term debt, and redeemed,
refinanced or repaid $53 million in long-term debt (see Note 6).

     SunCor's outstanding long and short-term debt was approximately $153
million as of December 31, 2002. As of December 31, 2002, SunCor had a $140
million line of credit, under which $126 million of borrowings were outstanding.
SunCor's short-term debt was $6 million and other long-term debt, including
current maturities, totaled $21 million at December 31, 2002.

                                       52
<PAGE>
     We expect SunCor to make cash distributions to the parent company of $80 to
$100 million annually in 2003 through 2005 due to anticipated accelerated asset
sales activity.

     El Dorado funded its cash requirements during the past three years,
primarily for NAC in 2002, with cash infused by the parent company and with cash
from operations. El Dorado expects minimal capital requirements over the next
three years and intends to focus on prudently realizing the value of its
existing investments. El Dorado's long-term debt was approximately $3 million at
December 31, 2002 and it had no long-term debt outstanding at December 31, 2001.
El Dorado's long-term debt increased primarily due to its consolidation of NAC
for financial reporting purposes (see Notes 6 and 22).

     APS Energy Services' cash requirements during the past three years were
funded with cash infusions from the parent company. APS Energy Services' capital
expenditures and other cash requirements are increasingly funded by operations,
with some funding from cash infused by Pinnacle West. See the capital
expenditures table above regarding APS Energy Services' actual capital
expenditures for 2002 and projected capital expenditures for the next three
years.

                          CRITICAL ACCOUNTING POLICIES

     In preparing the financial statements in accordance with GAAP, management
must often make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses and related disclosures at the date of
the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from
those estimates. We consider the following accounting policies to be our most
critical because of the uncertainties, judgments and complexities of the
underlying accounting standards and operations involved.

     *    Regulatory Accounting - Regulatory accounting allows for the actions
          of regulators, such as the ACC and the FERC, to be reflected in the
          financial statements. Their actions may cause us to capitalize costs
          that would otherwise be included as an expense in the current period
          by unregulated companies.

     *    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 the expected long-term rate of return on plan assets
          used to estimate earnings on invested funds over the long-term.

     *    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 other comprehensive income.

                                       53
<PAGE>
     *    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 the discussion below for further details on our critical accounting
policies.

REGULATORY ACCOUNTING

     For our 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 obligations to make
refunds to customers for previous collections of costs not likely to be
incurred.

     We are required to discontinue applying SFAS No. 71 when deregulatory
legislation is passed or a rate order is issued that contains sufficient detail
to determine its effect on the portion of the business being deregulated. In
1999, we discontinued the application of SFAS No. 71 for APS' generation
operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a
discussion of the 1999 Settlement Agreement.

     In 2002, the ACC directed APS not to transfer its generation assets, as
previously required by the 1999 Settlement Agreement (see "Track A Order" in
Note 3). Accordingly, we now consider APS generation to be cost-based,
rate-regulated and subject to the requirements of SFAS No. 71. The impact of
this change was immaterial to our consolidated financial statements.

     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 to current period earnings. We had $241 million of regulatory assets
included on the Consolidated Balance Sheets at December 31, 2002. See Notes 1
and 3 for more information.

PENSIONS AND OTHER POSTRETIREMENT BENEFIT ACCOUNTING

     We sponsor a qualified defined benefit pension plan and a non-qualified
supplemental excess benefit retirement plan for our employees and employees of
our subsidiaries. Our reported costs of providing defined pension and other
postretirement benefits are dependent upon numerous factors resulting from
actual plan experience and assumptions of future experience. Pension and other
postretirement benefit costs, for example, are impacted by actual employee
demographics (including age, compensation levels and employment periods), the
level of contributions we make to the plans and earnings on plan assets. Changes
made to the provisions of the plans may also impact current and future pension
and other postretirement benefit costs. Pension and other postretirement benefit

                                       54
<PAGE>
costs may also be significantly affected by changes in key actuarial
assumptions, including the expected long-term rate of return on plan assets and
the discount rates used in determining the projected benefit obligation and
pension and other postretirement benefit costs.

     Pinnacle West's pension and other postretirement plan assets are primarily
made up of equity and fixed income investments. Fluctuations in actual equity
market returns as well as changes in general interest rates may result in
increased or decreased pension and other postretirement benefit costs in future
periods. Likewise, changes in assumptions regarding current discount rates and
the expected long-term rate of return on plan assets could also increase or
decrease recorded pension and other postretirement benefit costs.

     We account for our defined benefit pension plans in accordance with SFAS
No. 87, "Employers' Accounting for Pensions," which requires amounts recognized
in our financial statements to be determined on an actuarial basis. Changes in
pension obligations associated with these factors may not be immediately
recognized as pension costs on the income statement, but generally are
recognized in future years over the remaining average service period of plan
participants. As such, significant portions of pension costs recorded in any
period may not reflect the actual level of cash benefits provided to plan
participants.

     The following chart reflects the sensitivities associated with a one
percent increase or decrease in certain actuarial assumptions related to our
defined benefit pension plans. Each sensitivity below reflects the impact of
changing only that assumption. The chart shows the increase (decrease) each
change in assumption would have on the 2002 projected benefit obligation, our
2002 reported pension liability on the Consolidated Balance Sheets and our 2002
reported annual pension expense, after consideration of amounts capitalized or
billed to electric plant participants, on the Consolidated Statements of Income
(dollars in millions).

                                            Increase/(Decrease)
     -------------------------------------------------------------------
                                  Impact on
                                  Projected      Impact on     Impact on
                                   Benefit        Pension       Pension
     Actuarial Assumption         Obligation     Liability      Expense
     -------------------------------------------------------------------
     Discount rate:
         Increase 1%                $ (143)        $ (107)       $  (4)
         Decrease 1%                   177            130            9
     Expected long-term rate
       of return on plan assets:
         Increase 1%                    --             --           (4)
         Decrease 1%                    --             --            4

     At the end of each year, we determine the discount rate to be used to
calculate the present value of plan liabilities. The discount rate is an
estimate of the current interest rate at which the pension liabilities could be
effectively settled at the end of the year. The discount rate is selected by
comparison to current yields on high-quality, long-term bonds. We changed our
discount rate assumption from 7.5% at December 31, 2001 to 6.75% at December 31,
2002.

                                       55
<PAGE>
     In 2002, we assumed that the expected long-term rate of return on plan
assets would be 10%. However, the plan assets have earned a rate of return
substantially less than 10% in the last three years due to sharp declines in the
equity markets. For 2003, we decreased our expected long-term rate of return on
plan assets to 9%, as a result of continued declines in general equity and bond
market returns.

     The following chart reflects the sensitivities associated with a one
percent increase or decrease in certain actuarial assumptions related to our
other postretirement benefit plans. Each sensitivity below reflects the impact
of changing only that assumption. The chart shows the increase (decrease) each
change in assumption would have on the 2002 accumulated other postretirement
benefit obligation and our 2002 reported other postretirement benefit expense,
after consideration of amounts capitalized or billed to electric plant
participants, on the Consolidated Statements of Income (dollars in millions).

                                          Increase/(Decrease)
     ----------------------------------------------------------------------
                             Impact on Accumulated       Impact on Other
                             Postretirement Benefit  Postretirement Benefit
     Actuarial Assumption         Obligation                Expense
     ----------------------------------------------------------------------
     Discount rate:
         Increase 1%                 $(38)                   $ (2)
         Decrease 1%                   43                       2
     Health care cost trend
       rate (a):
         Increase 1%                   54                       5
         Decrease 1%                  (43)                     (4)
     Expected long-term rate
       of return on plan
       assets - pretax:
         Increase 1%                   --                      (1)
         Decrease 1%                   --                       1

(a)  This assumes a 1% change in the initial and ultimate health care cost trend
     rate.

     The discount rate is selected by comparison to current yields on
high-quality, long-term bonds. We changed our discount rate assumption from 7.5%
at December 31, 2001 to 6.75% at December 31, 2002.

     In selecting our health care cost trend rate, we consider past performance
and forecasts of health care costs. In 2002, we increased our initial health
care cost trend rate to 8% from 7% based on an analysis of our actual plan
experience. We also assume an ultimate health care cost trend rate of 5% is
reached in 2007.

     In selecting the pretax expected long-term rate of return on plan assets,
we consider past performance and economic forecasts for the types of investments
held by the plan. The market value of the plan assets has been affected by sharp
declines in the equity markets. For 2003, we decreased our pretax expected
long-term rate of return on plan assets from 10% to 9%, as a result of continued
declines in general equity and bond market returns.

                                       56
<PAGE>
     Pension and other postretirement benefit costs and cash funding
requirements may increase in future years without a substantial recovery in the
equity markets. Due to the actual investment performance of our pension and
other postretirement benefit funds and the changes in the actuarial assumptions
discussed above, we expect an increase of approximately $29 million before
income taxes in 2003 expense over 2002. See Note 8 for further details about our
pension and other postretirement benefit plans.

DERIVATIVE ACCOUNTING

     We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We manage risks associated with these market fluctuations by utilizing various
commodity derivatives, including exchange-traded futures and options and
over-the-counter forwards, options and swaps. As part of our risk management
program, we enter into derivative transactions to hedge purchases and sales of
electricity, fuels and emissions allowances and credits. The changes in market
value of such contracts have a high correlation to price changes in the hedged
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.

     We examine contracts at inception to determine the appropriate accounting
treatment. If a contract does not meet the derivative criteria or if it
qualifies for a SFAS No. 133 scope exception, we account for the contract on an
accrual basis with associated revenues and costs recorded at the time the
contracted commodities are delivered or received. SFAS No. 133 provides a scope
exception for contracts that meet the normal purchases and sales criteria
specified in the standard. Most 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.

     For contracts that qualify as a derivative and do not meet a SFAS No. 133
scope exception, we further examine the contract to determine if it will qualify
for hedge accounting. Changes in the fair value of the effective portion of
derivative instruments that qualify for cash flow hedge accounting treatment are
recognized as either an asset or liability and in common stock equity (as a
component of accumulated other comprehensive income (loss)). Gains and losses
related to 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 a contract does not meet the hedging criteria in SFAS No.
133, we recognize the changes in the fair value of the derivative instrument in
income each period through mark-to-market accounting.

     On October 1, 2002, we adopted EITF 02-3, which rescinded EITF 98-10. As a
result, our energy trading contracts that are derivatives continue to be
accounted for at fair value under SFAS No. 133. Contracts that were previously
marked-to-market as trading activities under EITF 98-10 that do not meet the
accounting 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. Additionally, all gains and losses
(realized and unrealized) on energy trading contracts that qualify as
derivatives are included in marketing and trading segment revenues on the
Consolidated Statements of Income on a net basis. The rescission of EITF 98-10
has no effect on the accounting for derivative instruments used for non-trading
activities, which continue to be accounted for in accordance with SFAS No. 133.
See "Other Accounting Matters - Accounting for Derivative and Trading

                                       57
<PAGE>
Activities" below for details on the change in accounting for energy trading
contracts. See Note 18 for further discussion on derivative accounting.

MARK-TO-MARKET ACCOUNTING

     Under mark-to-market accounting, the purchase or sale of energy commodities
is reflected at fair market value, net of valuation adjustments, with resulting
unrealized gains and losses recorded as assets and liabilities from risk
management and trading activities in the Consolidated Balance Sheets.

     We determine fair market value using actively-quoted prices when available.
We consider quotes for exchange-traded contracts and over-the-counter quotes
obtained from independent brokers to be actively-quoted.

     When actively-quoted prices are not available, we use prices provided by
other external sources. This includes quarterly and calendar year quotes from
independent brokers. We shape quarterly and calendar year quotes into monthly
prices based on historical relationships.

     For options, long-term contracts and other contracts for which price quotes
are not available, we use models and other valuation methods. The valuation
models we employ utilize spot prices, forward prices, historical market data and
other factors to forecast future prices. The primary valuation technique we use
to calculate the fair value of contracts where price quotes are not available is
based on the extrapolation of forward pricing curves using observable market
data for more liquid delivery points in the same region and actual transactions
at the more illiquid delivery points. We also value option contracts using a
variation of the Black-Scholes option-pricing model.

     For non-exchange traded contracts, we calculate fair market value based on
the average of the bid and offer price, and we discount to reflect net present
value. We maintain certain valuation 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.

     A credit valuation adjustment is also recorded to represent 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
"Factors Affecting our Financial Outlook - Market Risks - Commodity Price Risk"
below and Note 18 for further discussion on credit risk.

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

                                       58
<PAGE>
transactions. To illustrate, as presented in the "Factors Affecting our
Financial Outlook - Market Risks - Commodity Price Risk" section below, a 10%
increase in the price of trading commodities would result in only a $2 million
decrease in pretax income. Our practice is to hedge within timeframes
established by the ERMC.

                            OTHER ACCOUNTING MATTERS

ACCOUNTING FOR DERIVATIVE AND TRADING ACTIVITIES

     During 2002, the EITF discussed EITF 02-3 and reached a consensus on
certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25,
2002 for any new contracts, and on January 1, 2003 for existing contracts, with
early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in
the fourth quarter of 2002. We recorded a $66 million after-tax charge in net
income as a cumulative effect adjustment for the previously recorded accumulated
unrealized mark-to-market on energy trading contracts that did not meet the
accounting definition of a derivative. As a result, our energy trading contracts
that are derivatives continue to be accounted for at fair value under SFAS No.
133. Contracts that were previously marked-to-market as trading activities under
EITF 98-10 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. Additionally, all gains
and losses (realized and unrealized) on energy trading contracts that qualify as
derivatives are included in marketing and trading segment revenues on the
Consolidated Statements of Income on a net basis. The rescission of EITF 98-10
has no effect on the accounting for derivative instruments used for non-trading
activities, which continue to be accounted for in accordance with SFAS No. 133.

     EITF 02-3 requires that derivatives held for trading purposes, whether
settled financially or physically, be reported in the income statement on a net
basis. Previous guidance under EITF 98-10 permitted physically settled energy
trading contracts to be reported either gross or net in the income statement.
Beginning in the third quarter of 2002, we netted all of our energy trading
activities on the Consolidated Statements of Income and restated prior year
amounts for all periods presented. Reclassification of such trading activity to
a net basis of reporting resulted in reductions in both revenues and purchased
power and fuel costs, but did not have any impact on our financial condition,
results of operations or cash flows.

     In 2001, we adopted SFAS No. 133 and recorded a $15 million after-tax
charge in net income and a $72 million after-tax credit in common stock equity
(as a component of other comprehensive income), both as a cumulative effect of a
change in accounting for derivatives. See Notes 1 and 18 for further information
on accounting for derivatives under SFAS No. 133.

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 will be 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.)

                                       59
<PAGE>
     We determined that we have asset retirement obligations for our nuclear
facilities (nuclear decommissioning) and certain other generation, transmission
and distribution assets. On January 1, 2003 we recorded a liability of $219
million for our asset retirement obligations including the accretion impacts; a
$67 million increase in the carrying amount of the associated assets; and a net
reduction of $192 million in accumulated depreciation related primarily to the
reversal of previously recorded accumulated decommissioning and other removal
costs related to these obligations. Additionally, we recorded a regulatory
liability of $40 million for our asset retirement obligations related to our
regulated utility. This regulatory liability represents the difference between
the amount currently being recovered in regulated rates and the amount
calculated under SFAS No. 143. We believe we can recover in regulated rates the
transition costs and ongoing current period costs calculated in accordance with
SFAS No. 143.

STOCK-BASED COMPENSATION

     In the third quarter of 2002, we began applying the fair value method of
accounting for stock-based compensation, as provided for in SFAS No. 123,
"Accounting for Stock-Based Compensation." We recorded approximately $500,000 in
stock option expense before income taxes in our Consolidated Statements of
Income for 2002. See Notes 1 and 16 for further information on the impacts of
adopting the fair value method provided in SFAS No. 123.

VARIABLE INTEREST ENTITIES

     See "Liquidity and Capital Resources - Off-Balance Sheet Arrangements" and
Note 20 for discussion of VIEs.

OTHER

     See Note 2 for discussion of other new accounting standards that are not
expected to have a material impact on the Company.

                     FACTORS AFFECTING OUR FINANCIAL OUTLOOK

REGULATORY MATTERS

     GENERAL

     On September 21, 1999, the ACC approved Rules that provide a framework for
the introduction of retail electric competition in Arizona. On September 23,
1999, the ACC approved a comprehensive settlement agreement among APS and
various parties related to the implementation of retail electric competition in
Arizona. Under the Rules, as modified by the 1999 Settlement Agreement, APS was
required to transfer all of its competitive electric assets and services to an
unaffiliated party or parties or to a separate corporate affiliate or affiliates
no later than December 31, 2002. Consistent with that requirement, APS had been
addressing the legal and regulatory requirements necessary to complete the
transfer of its generation assets to Pinnacle West Energy on or before that
date. On September 10, 2002, the ACC issued the Track A Order, which, among
other things, directed APS not to transfer its generation assets to Pinnacle
West Energy.

                                       60
<PAGE>
     1999 SETTLEMENT AGREEMENT

     The 1999 Settlement Agreement has affected, and will affect, our results of
operations. As part of the 1999 Settlement Agreement, APS agreed to reduce
retail electricity prices for standard-offer, full-service customers with loads
less than three megawatts in a series of annual decreases of 1.5% on July 1,
1999 through July 1, 2003, for a total of 7.5%. For customers with loads three
megawatts or greater, standard-offer rates were reduced in annual increments
totaling 5% in the years 1999 through 2002.

     The 1999 Settlement Agreement also removed, as a regulatory disallowance,
$234 million before income taxes ($183 million net present value) from ongoing
regulatory cash flows. APS recorded this regulatory disallowance as a net
reduction of regulatory assets and reported it as a $140 million after-tax
extraordinary charge on the 1999 Consolidated Statement of Income. As discussed
under "APS General Rate Case" below, APS intends to seek recovery of this $234
million write-off in its next general rate case.

     Prior to the 1999 Settlement Agreement, the ACC accelerated the
amortization of substantially all of APS' regulatory assets to an eight-year
period that would have ended June 30, 2004. 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

     See Note 3 for additional information regarding the 1999 Settlement
Agreement.

     APS FINANCING APPLICATION

     On September 16, 2002, APS filed an application with the ACC requesting the
ACC to allow APS to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to the Company; to guarantee up to $500 million of
Pinnacle West Energy's or the Company's debt; or a combination of both, not to
exceed $500 million in the aggregate. In its application, APS stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between APS and Pinnacle West Energy under
different regulatory regimes result in Pinnacle West Energy being unable to
attain investment-grade credit ratings. This, in turn, precludes Pinnacle West
Energy from accessing capital markets to refinance the bridge financing that we
provided to fund the construction of Pinnacle West Energy generation assets or
from effectively competing in the wholesale markets. On March 27, 2003, the ACC
authorized APS to lend up to $500 million to Pinnacle West Energy, guarantee up
to $500 million of Pinnacle West Energy debt, or a combination of both, not to
exceed $500 million in the aggregate. See "ACC Applications" in Note 3 for
further discussion of the approval and related conditions.

     TRACK A ORDER

     On September 10, 2002, the ACC issued the Track A Order. See "Track A
Order" in Note 3.

                                       61
<PAGE>
     COMPETITIVE PROCUREMENT PROCESS

     On September 10, 2002, the ACC issued an order that, among other things,
established a requirement that APS competitively procure certain power
requirements. On March 14, 2003, the ACC issued the Track B Order, which
documented the decision made by the ACC at its open meeting on February 27, 2003
addressing this requirement. Under the ACC's Track B Order, APS will be required
to solicit bids for certain estimated capacity and energy requirements for
periods beginning July 1, 2003. For 2003, APS will be required to solicit
competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours
of energy, or approximately 20% of APS' total retail energy requirements. The
bid amounts are expected to increase in 2004 and 2005 based largely on growth in
APS' retail load and APS' retail energy sales. The Track B Order also confirmed
that it was "not intended to change the current rate base status of [APS']
existing assets." The order recognizes APS' right to reject any bids that are
unreasonable, uneconomical or unreliable.

     APS expects to issue requests for proposals in March 2003 and to complete
the selection process by June 1, 2003. Pinnacle West Energy will be eligible to
bid to supply APS' electricity requirements. See "Track B Order" in Note 3 for
additional information.

     APS GENERAL RATE CASE

     As required by the 1999 Settlement Agreement, on or before June 30, 2003,
APS will file a general rate case with the ACC. In this rate case, APS will
update its cost of service and rate design. In addition, APS expects to seek:

     *    rate base treatment of certain power plants currently owned by
          Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West
          Phoenix Units 4 and 5 and Saguaro Unit 3);

     *    recovery of the $234 million pretax asset write-off recorded by APS
          as part of the 1999 Settlement Agreement ($140 million extraordinary
          charge recorded on the 1999 Consolidated Statement of Income); and

     *    recovery of costs incurred by APS in preparation for the previously
          required transfer of generation assets to Pinnacle West Energy.

We assume that the ACC will make a decision in this general rate case by the end
of 2004.

     WHOLESALE POWER MARKET CONDITIONS

     The marketing and trading division, which we moved to APS in early 2003 for
future marketing and trading activities (existing wholesale contracts will
remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting APS'
transfer of generating assets to Pinnacle West Energy, focuses primarily on
managing APS' purchased power and fuel risks in connection with its costs of
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. Earnings contributions
from our marketing and trading division were lower in 2002 compared to 2001 due
to weak wholesale power market conditions in the western United States, which

                                       62
<PAGE>
included a lack of market liquidity, fewer creditworthy counterparties, lower
wholesale market prices and resulting decreases in sales volumes. Our 2003
earnings will be affected by the strength (or weakness) of the wholesale power
market.

     GENERATION CONSTRUCTION

     See "Capital Needs and Resources - Pinnacle West Energy" above and Note 11
for information regarding Pinnacle West Energy's generation construction
program. The planned additional generation is expected to increase revenues,
fuel expenses, operating expenses and financing costs.

     FACTORS AFFECTING OPERATING REVENUES

     GENERAL Electric operating revenues are derived from sales of electricity
in regulated retail markets in Arizona and from competitive retail and wholesale
bulk power markets in the western United States. These revenues are expected to
be affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer as well as electricity prices and
variations in weather from period to period. Competitive sales of energy and
energy-related products and services are made by APS Energy Services in western
states that have opened to competitive supply.

     CUSTOMER GROWTH Customer growth in APS' service territory averaged about
3.6% a year for the three years 2000 through 2002; we currently expect customer
growth to average about 3.5% per year from 2003 to 2005. We currently estimate
that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in
2003 through 2005, before the retail effects of weather variations. The customer
growth and sales growth referred to in this paragraph applies to energy delivery
customers. As previously noted, under the 1999 Settlement Agreement, we agreed
to retail electricity price reductions of 1.5% annually through July 1, 2003
(see Note 3).

     OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS

     PURCHASED POWER AND FUEL COSTS Purchased power and fuel costs are impacted
by our electricity sales volumes, existing contracts for purchased power and
generation fuel, our power plant performance, prevailing market prices, new
generating plants being placed in service and our hedging program for managing
such costs.

     OPERATIONS AND MAINTENANCE EXPENSES Operations and maintenance expenses are
expected to be affected by sales mix and volumes, power plant additions and
operations, inflation, outages, higher trending pension and other postretirement
benefit costs and other factors. In July 2002, we implemented a voluntary
workforce reduction as part of our cost reduction program. We recorded $36
million before taxes in voluntary severance costs in the second half of 2002. In
addition, we are expecting to produce annual operating expense savings of
approximately $30 million beginning in 2003 as a result of this workforce
reduction.

     DEPRECIATION AND AMORTIZATION EXPENSES Depreciation and amortization
expenses are expected to be affected by net additions to existing utility plant
and other property, changes in regulatory asset amortization and our generation
construction program. West Phoenix Unit 4 was placed in service in June 2001.
Redhawk Units 1 and 2 and the new Saguaro Unit 3 began commercial operations in

                                       63
<PAGE>
July 2002. West Phoenix Unit 5 is expected to be on line in mid-2003 and
Silverhawk is expected to be in service in mid-2004 (see Note 11 for further
details about 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 TAXES Taxes other than income taxes consist primarily of property
taxes, which are affected by tax rates and the value of property in-service and
under construction. The average property tax rate for APS, which currently owns
the majority of our property, was 9.7% of assessed value for 2002 and 9.3% for
2001. We expect property taxes to increase primarily due to our generation
construction program and our additions to existing facilities.

     INTEREST EXPENSE Interest expense is affected by the amount of debt
outstanding and the interest rates on that debt. The primary factors affecting
borrowing levels in the next several years are expected to be our capital
requirements and our internally-generated cash flow. Capitalized interest
offsets a portion of interest expense while capital projects are under
construction. We stop recording capitalized interest on a project when it is
placed in commercial operation. As noted above, we have placed new power plants
in commercial operation in 2001 and 2002 and we expect to bring additional
plants on-line in 2003 and 2004. We are continuing to evaluate our generation
construction program. Interest expense is affected by interest rates on
variable-rate debt and interest rates on the refinancing of the Company's future
liquidity needs.

     RETAIL COMPETITION The regulatory developments and legal challenges to the
Rules discussed in Note 3 have raised considerable uncertainty about the status
and pace of retail electric competition in Arizona. Although some very limited
retail competition existed in APS' service area in 1999 and 2000, there are
currently no active retail competitors providing unbundled energy or other
utility services to APS' customers. As a result, we cannot predict when, and the
extent to which, additional competitors will re-enter APS' service territory.

     SUBSIDIARIES In the case of SunCor, we are undertaking an aggressive effort
to accelerate asset sales activities to approximately double SunCor's annual
earnings in 2003 to 2005 compared to the $19 million in earnings recorded in
2002. A portion of these sales could be reported as discontinued operations on
the Consolidated Statements of Income.

     The annual earnings contribution from APS Energy Services is expected to be
positive over the next several years due primarily to a number of retail
electricity contracts in California. APS Energy Services' had pretax earnings of
$28 million in 2002.

     El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. El Dorado's strategies focus on prudently realizing
the value of its existing investments.

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

                                       64
<PAGE>
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 pension plan (see Note 8) and nuclear decommissioning
trust fund (see Note 12). Our policy is to manage interest rates through the use
of a combination of fixed-rate and floating-rate debt. The pension plan and
nuclear decommissioning fund also have risks associated with changing market
values of equity investments. Pension (APS only) and nuclear decommissioning
costs are recovered in regulated electricity prices. See "Critical Accounting
Policies - Pension and Other Postretirement Benefit Accounting" for a
sensitivity analysis on the long-term rate of return on plan assets.

     The tables below present contractual balances of our consolidated long-term
debt and commercial paper at the expected maturity dates as well as the fair
value of those instruments on December 31, 2002 and 2001. The interest rates
presented in the tables below represent the weighted-average interest rates for
the years ended December 31, 2002 and 2001.

Expected Maturity/Principal Repayment
December 31, 2002
(dollars in thousands)

<TABLE>
<CAPTION>
                                                Variable-Rate                Fixed-Rate
                       Short-Term Debt          Long-Term Debt             Long-Term Debt
                     -------------------     --------------------      ---------------------
                     Interest                 Interest                 Interest
                      Rates     Amount         Rates      Amount         Rates      Amount
                      -----     ------         -----      ------         -----      ------
<S>                   <C>      <C>            <C>       <C>              <C>     <C>
2003                  2.59%    $ 102,183       2.68%    $ 250,800        6.73%   $    30,223
2004                    --            --       3.76%      126,813        5.32%       424,697
2005                    --            --       3.39%        1,294        7.27%       403,931
2006                    --            --      10.10%        2,954        6.47%       387,018
2007                    --            --       8.00%          209        6.04%         2,738
Years thereafter        --            --       2.00%      390,537        6.08%     1,148,371
                               ---------                ---------                -----------
Total                          $ 102,183                $ 772,607                $ 2,396,978
                               =========                =========                ===========
Fair value                     $ 102,183                $ 772,607                $ 2,501,073
                               =========                =========                ===========
</TABLE>

                                       65
<PAGE>
Expected Maturity/Principal Repayment
December 31, 2001
(dollars in thousands)

<TABLE>
<CAPTION>
                                                Variable-Rate                Fixed-Rate
                       Short-Term Debt          Long-Term Debt             Long-Term Debt
                     -------------------     --------------------      ---------------------
                     Interest                 Interest                 Interest
                      Rates     Amount         Rates      Amount         Rates      Amount
                      -----     ------         -----      ------         -----      ------
<S>                   <C>      <C>            <C>       <C>              <C>     <C>
2002                  4.01%    $ 405,762       7.76%    $     207        8.10%   $   125,933
2003                    --            --       4.75%      292,912        6.87%        25,829
2004                    --            --       5.32%       85,601        6.08%       205,677
2005                    --            --       7.70%          294        7.59%       400,380
2006                    --            --       7.30%        3,018        6.48%       384,085
Years thereafter        --            --       2.63%      480,740        6.73%       799,808
                               ---------                ---------                -----------
Total                          $ 405,762                $ 862,772                $ 1,941,712
                               =========                =========                ===========
Fair value                     $ 405,762                $ 862,772                $ 1,963,389
                               =========                =========                ===========
</TABLE>

     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 derivatives, including exchange-traded futures and
options and over-the-counter forwards, options and swaps. The ERMC, consisting
of senior officers, 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 enter into derivative transactions to hedge purchases and
sales of electricity, fuels and emissions allowances and credits. The changes in
market value of such contracts have a high correlation to price changes in the
hedged 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.

     Prior to October 1, 2002, we accounted for our energy trading contracts at
fair value in accordance with EITF 98-10. On October 1, 2002, we adopted EITF
02-3, which rescinded EITF 98-10. As a result, our energy trading contracts that
are derivatives continue to be accounted for at fair value under SFAS No. 133.
Contracts that were previously marked-to-market as trading activities under EITF
98-10 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. Additionally, all gains and
losses (realized and unrealized) on energy trading contracts that qualify as
derivatives are included in marketing and trading segment revenues on the
Consolidated Statements of Income on a net basis. The rescission of EITF 98-10
has no effect on the accounting for derivative instruments used for non-trading
activities, which continue to be accounted for in accordance with SFAS No. 133.
See Note 18 for details on the change in accounting for energy trading contracts
and further discussion regarding derivative accounting.

                                       66
<PAGE>
     Both non-trading and trading derivatives are classified as assets and
liabilities from risk management and trading activities in the Consolidated
Balance Sheets. For non-trading derivative instruments that qualify for hedge
accounting treatment, changes in the fair value of the effective portion are
recognized in common stock equity (as a component of accumulated 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.

     Derivatives associated with trading activities are adjusted to fair value
through income. 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. Most 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.

     Our assets and liabilities from risk management and trading activities are
presented in two categories consistent with our business segments:

     *    System - our regulated electricity business segment, which consists of
          non-trading derivative instruments that hedge our purchases and sales
          of electricity and fuel for our Native Load requirements; and

     *    Marketing and Trading - our non-regulated, competitive business
          segment, which includes both non-trading and trading derivative
          instruments.

     The following tables show the changes in mark-to-market of our system and
marketing and trading derivative positions in 2002 and 2001 (dollars in
millions):

                                       67
<PAGE>
                                                                   Marketing
                                                                      and
                                                          System    Trading
                                                          ------    -------
     Mark-to-market of net positions
       at December 31, 2001                                $(107)    $ 138
     Cumulative effect adjustment due to
       adoption of  EITF 02-3                                 --      (109)
     Change in mark-to-market gains
       for future period deliveries                          (13)       47
     Changes in cash flow hedges
       recorded in OCI                                        57        16
     Ineffective portion of changes in fair value
       recorded in earnings                                   11        --
     Mark-to-market losses/(gains) realized
       during the year                                         3       (38)
     Change in valuation techniques                           --         3
                                                           -----     -----
     Mark-to-market of net positions
       at December 31, 2002                                $ (49)    $  57
                                                           =====     =====

                                                                   Marketing
                                                                      and
                                                          System    Trading
                                                          ------    -------
     Mark-to-market of net positions
       at December 31, 2000                                $  --     $  12
     Cumulative effect adjustment due to
       adoption of SFAS No. 133                               95        --
     Change in mark-to-market (losses)/gains
       for future period deliveries                          (12)      203
     Changes in cash flow hedges
       recorded in OCI                                      (166)       --
     Ineffective portion of changes in fair
       value recorded in earnings                             (6)       --
     Mark-to-market gains realized
       during the year                                       (18)      (77)
     Change in valuation techniques                           --        --
                                                           -----     -----
     Mark-to-market of net positions
       at December 31, 2001                                $(107)    $ 138
                                                           =====     =====

     The Company no longer reports non-derivative energy contracts or physical
inventories at fair value. Since July 1, 2002, the Company has not recognized a
dealer profit or unrealized gain or loss at the inception of a derivative unless
the fair value of that instrument (in its entirety) is evidenced by quoted
market prices or current market transactions. Prior to the change in our policy,
we recorded net gains at inception of $10 million in 2002 and $3 million in
2001. These amounts included a reasonable marketing margin.

     The tables below show the maturities of our system and marketing and
trading derivative positions at December 31, 2002 by the type of valuation that
is performed to calculate the fair value of the contract (dollars in millions).
See "Critical Accounting Policies - Mark-to-Market Accounting" above for more
discussion on our valuation methods.

                                       68
<PAGE>
SYSTEM

<TABLE>
<CAPTION>
                                                                              Years       Total
Source of Fair Value       2003      2004      2005      2006      2007    thereafter   fair value
--------------------       ----      ----      ----      ----      ----    ----------   ----------
<S>                        <C>       <C>       <C>       <C>       <C>        <C>         <C>
Prices actively quoted     $(23)     $(10)     $ --      $ --      $ --       $ --        $(33)
Prices provided by
  other external sources     (1)      (12)       --        --        --         --         (13)
Prices based on models
  and other valuation
  methods                    (1)       (2)       --        --        --         --          (3)
                           ----      ----      ----      ----      ----       ----        ----
Total by maturity          $(25)     $(24)     $ --      $ --      $ --       $ --        $(49)
                           ====      ====      ====      ====      ====       ====        ====
</TABLE>

MARKETING AND TRADING

<TABLE>
<CAPTION>
                                                                              Years       Total
Source of Fair Value       2003      2004      2005      2006      2007    thereafter   fair value
--------------------       ----      ----      ----      ----      ----    ----------   ----------
<S>                        <C>       <C>       <C>       <C>       <C>        <C>         <C>
Prices actively quoted     $ (1)     $  5      $  6      $  3      $  3       $  7        $ 23
Prices provided by
  other external sources      2         8         9        12        --         --          31
Prices based on models
  and other valuation
  methods                     6         3        (3)       (4)        5         (4)          3
                           ----      ----      ----      ----      ----       ----        ----
Total by maturity          $  7      $ 16      $ 12      $ 11      $  8       $  3        $ 57
                           ====      ====      ====      ====      ====       ====        ====
</TABLE>

     The table below shows the impact hypothetical price movements of 10% would
have on the market value of our risk management and trading assets and
liabilities included on the Consolidated Balance Sheets at December 31, 2002 and
2001 (dollars in millions).

                                       69
<PAGE>
<TABLE>
<CAPTION>
                                  December 31, 2002             December 31, 2001
                                     Gain (Loss)                   Gain (Loss)
                            -----------------------------  ----------------------------
      Commodity             Price Up 10%   Price Down 10%  Price Up 10%  Price Down 10%
      ---------             ------------   --------------  ------------  --------------
<S>                             <C>             <C>            <C>            <C>
Mark-to-market changes
  reported in earnings (a):
    Electricity                 $ (2)           $  3           $ (3)          $  3
    Natural gas                   (4)              4             (1)             1
    Other                          1              --             --              2
Mark-to-market changes
  reported in OCI (b):
    Electricity                   32             (32)            --             --
    Natural gas                   18             (16)            23            (23)
                                ----            ----           ----           ----
       Total                    $ 45            $(41)          $ 19           $(17)
                                ====            ====           ====           ====
</TABLE>

     (a)  These contracts are structured sales activities hedged with a
          portfolio of forward purchases that protects the economic value of the
          sales transactions.
     (b)  These contracts are hedges of our forecasted purchases of natural gas
          and electricity. The impact of these hypothetical price movements
          would substantially offset the impact that these same price movements
          would have on the physical exposures being hedged.

CREDIT RISK

     We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We have risk management and trading contracts with many
counterparties, including two counterparties for which a worst case exposure
represents approximately 33% of our $181 million of risk management and trading
assets as of December 31, 2002. Our risk management process assesses and
monitors the financial exposure of these and all other counterparties. Despite
the fact that the great majority of trading counterparties are rated as
investment grade by the credit rating agencies, including the counterparties
noted above, there is still a possibility that one or more of these companies
could default, resulting in a material impact on consolidated earnings for a
given period. Counterparties in the portfolio consist principally of major
energy companies, municipalities and local distribution companies. We maintain
credit policies that we believe minimize overall credit risk to within
acceptable limits. Determination of the credit quality of our counterparties is
based upon a number of factors, including credit ratings and our evaluation of
their financial condition. In many contracts, we employ collateral requirements
and standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Valuation adjustments are
established representing our estimated credit losses on our overall exposure to
counterparties. See "Critical Accounting Policies - Mark-to-Market Accounting"
above for a discussion of our credit valuation adjustment policy.

                                       70
<PAGE>
RISK FACTORS

     Exhibit 99.3, which is hereby incorporated by reference, contains a
discussion of risk factors affecting the Company.

FORWARD-LOOKING STATEMENTS

     The above discussion 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
laws. 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
the ongoing restructuring of the electric industry, including the introduction
of retail electric competition in Arizona and decisions impacting wholesale
competition; the outcome of regulatory and legislative proceedings relating to
the restructuring; state and federal regulatory and legislative decisions and
actions, including price caps and other market constraints imposed by the FERC;
regional economic and market conditions, including the California energy
situation and 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; weather
variations affecting local and regional customer energy usage; the effect of
conservation programs on energy usage; power plant performance; the successful
completion of our generation construction program; regulatory issues associated
with generation construction, such as permitting and licensing; our ability to
compete successfully outside traditional regulated markets (including the
wholesale market); our ability to manage our marketing and trading activities
and the use of derivative contracts in our business; technological developments
in the electric industry; the performance of the stock market, which affects the
amount of our required contributions to our pension plan and nuclear
decommissioning trust funds; the strength of the real estate market in SunCor's
market areas, which include Arizona, New Mexico and Utah; and other
uncertainties, all of which are difficult to predict and many of which are
beyond our control.

                      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.

                                       71
<PAGE>




















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                                       72
<PAGE>
               ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND
                          FINANCIAL STATEMENT SCHEDULE


Independent Auditors' Report................................................. 74
Consolidated Statements of Income for 2002, 2001 and 2000.................... 75
Consolidated Balance Sheets as of December 31, 2002 and 2001................. 76
Consolidated Statements of Cash Flows for 2002, 2001 and 2000................ 78
Consolidated Statements of Changes in Common Stock Equity
  for 2002, 2001 and 2000.................................................... 79
Notes to Consolidated Financial Statements................................... 80
Financial Statement Schedule for 2002, 2001 and 2000
  Schedule II - Valuation and Qualifying Accounts for 2002, 2001
  and 2000...................................................................138

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

                                       73
<PAGE>
                          INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Stockholders of
Pinnacle West Capital Corporation
Phoenix, Arizona

     We have audited the accompanying consolidated balance sheets of Pinnacle
West Capital Corporation and subsidiaries ("the Corporation") as of December 31,
2002 and 2001 and the related consolidated statements of income, changes in
common stock equity, and cash flows for each of the three years in the period
ended December 31, 2002. Our audits also included the financial statement
schedule listed in the Index. These financial statements and financial statement
schedule are the responsibility of the Corporation's management. Our
responsibility is to express an opinion on the financial statements and the
financial statement schedule based on our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

     In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Pinnacle West Capital
Corporation and subsidiaries at December 31, 2002 and 2001 and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2002 in conformity with accounting principles generally
accepted in the United States of America. Also, in our opinion, such financial
statement schedule, when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.

     As discussed in Note 18 to the consolidated financial statements, in 2002
Pinnacle West Capital Corporation changed its method of accounting for trading
activities in order to comply with the provisions of Emerging Issues Task Force
Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts Involved in Energy Trading and Risk Management
Activities."

     As discussed in Note 18 to the consolidated financial statements, in 2001
Pinnacle West Capital Corporation 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
February 3, 2003 (March 4, 14, 26 and 27, 2003 as to Note 24)

                                       74
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                        CONSOLIDATED STATEMENTS OF INCOME
           (dollars and shares in thousands, except per share amounts)

<TABLE>
<CAPTION>
                                                                   Year Ended December 31,
                                                       ---------------------------------------------
                                                           2002             2001             2000
                                                       -----------      -----------      -----------
<S>                                                    <C>              <C>              <C>
OPERATING REVENUES
    Regulated electricity segment                      $ 2,013,023      $ 2,562,089      $ 2,538,752
    Marketing and trading segment                          325,931          651,230          418,532
    Real estate segment                                    236,388          168,908          158,365
    Other revenues                                          61,937           11,771            3,873
                                                       -----------      -----------      -----------
         Total                                           2,637,279        3,393,998        3,119,522
                                                       -----------      -----------      -----------
OPERATING EXPENSES
    Regulated electricity segment purchased
      power and fuel                                       499,543        1,160,863        1,065,597
    Marketing and trading segment purchased
      power and fuel                                       194,039          334,209          292,669
    Operations and maintenance                             584,538          530,095          450,205
    Real estate operations segment                         205,315          153,462          134,422
    Depreciation and amortization                          424,886          427,903          431,229
    Taxes other than income taxes                          107,952          101,068           99,780
    Other expenses                                         104,959           10,375              782
                                                       -----------      -----------      -----------
         Total                                           2,121,232        2,717,975        2,474,684
                                                       -----------      -----------      -----------
OPERATING INCOME                                           516,047          676,023          644,838
                                                       -----------      -----------      -----------
OTHER
    Other income                                            15,104           26,416           21,832
    Other expenses                                         (33,655)         (33,577)         (25,329)
                                                       -----------      -----------      -----------
         Total                                             (18,551)          (7,161)          (3,497)
                                                       -----------      -----------      -----------
INTEREST EXPENSE
    Interest charges                                       188,353          175,822          166,447
    Capitalized interest                                   (44,110)         (47,862)         (21,638)
                                                       -----------      -----------      -----------
         Total                                             144,243          127,960          144,809
                                                       -----------      -----------      -----------

INCOME BEFORE INCOME TAXES                                 353,253          540,902          496,532
INCOME TAXES                                               138,100          213,535          194,200
                                                       -----------      -----------      -----------

INCOME BEFORE ACCOUNTING CHANGE                            215,153          327,367          302,332
    Cumulative effect of a change in
         accounting for derivatives -
         net of income taxes of $9,892                          --          (15,201)              --
    Cumulative effect of a change in
         accounting for trading activities -
         net of income taxes of $43,123                    (65,745)              --               --
                                                       -----------      -----------      -----------
NET INCOME                                             $   149,408      $   312,166      $   302,332
                                                       ===========      ===========      ===========
WEIGHTED-AVERAGE COMMON
  SHARES OUTSTANDING - BASIC                                84,903           84,718           84,733

WEIGHTED-AVERAGE COMMON
  SHARES OUTSTANDING - DILUTED                              84,964           84,930           84,935

EARNINGS PER WEIGHTED - AVERAGE
COMMON SHARE OUTSTANDING
    Income before accounting change - basic            $      2.53      $      3.86      $      3.57
    Net income - basic                                        1.76             3.68             3.57
    Income before accounting change - diluted                 2.53             3.85             3.56
    Net income - diluted                                      1.76             3.68             3.56
DIVIDENDS DECLARED PER SHARE                           $     1.625      $     1.525      $     1.425
</TABLE>

See Notes to Consolidated Financial Statements.

                                       75
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                           CONSOLIDATED BALANCE SHEETS
                             (dollars in thousands)

<TABLE>
<CAPTION>
                                                                               December 31,
                                                                        -------------------------
                                                                           2002           2001
                                                                        ----------     ----------
<S>                                                                     <C>            <C>
ASSETS

CURRENT ASSETS
  Cash and cash equivalents                                             $   77,707     $   28,619
  Customer and other receivables - net                                     374,995        367,241
  Accrued utility revenues                                                  72,915         76,131
  Materials and supplies (at average cost)                                  91,652         81,215
  Fossil fuel (at average cost)                                             28,185         27,023
  Deferred income taxes (Note 4)                                             4,094             --
  Assets from risk management and trading activities
    (Note 18)                                                               59,162         66,973
  Other current assets                                                     103,978         80,203
                                                                        ----------     ----------
         Total current assets                                              812,688        727,405
                                                                        ----------     ----------
INVESTMENTS AND OTHER ASSETS
  Real estate investments - net (Notes 1 and 6)                            425,331        418,673

  Assets from risk management and trading activities -
    long term (Note 18)                                                    122,336        200,351
  Other assets                                                             229,891        304,453
                                                                        ----------     ----------
         Total investments and other assets                                777,558        923,477
                                                                        ----------     ----------
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 6, 9 and 10)
  Plant in service and held for future use                               9,058,900      8,030,847
  Less accumulated depreciation and amortization                         3,474,325      3,290,097
                                                                        ----------     ----------
         Total                                                           5,584,575      4,740,750
  Construction work in progress                                            777,542      1,047,072
  Intangible assets, net of accumulated amortization (Note 21)             109,815         86,782
  Nuclear fuel, net of accumulated amortization of
    $102,821 and $99,185                                                     7,466          6,933
                                                                        ----------     ----------
  Net property, plant and equipment                                      6,479,398      5,881,537
                                                                        ----------     ----------
DEFERRED DEBITS
  Regulatory assets (Notes 1, 3 and 4)                                     241,045        342,383
  Other deferred debits                                                    115,117         64,597
                                                                        ----------     ----------
         Total deferred debits                                             356,162        406,980
                                                                        ----------     ----------

TOTAL ASSETS                                                            $8,425,806     $7,939,399
                                                                        ==========     ==========
</TABLE>

See Notes to Consolidated Financial Statements.

                                       76
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                           CONSOLIDATED BALANCE SHEETS
                             (dollars in thousands)

<TABLE>
<CAPTION>
                                                                      December 31,
                                                              ----------------------------
                                                                 2002             2001
                                                              -----------      -----------
<S>                                                           <C>              <C>
LIABILITIES AND EQUITY

CURRENT LIABILITIES
  Accounts payable                                            $   356,305      $   269,124
  Accrued taxes                                                    71,109           96,729
  Accrued interest                                                 53,018           48,806
  Short-term borrowings (Note 5)                                  102,183          405,762
  Current maturities of long-term debt (Note 6)                   281,023          126,140
  Customer deposits                                                55,838           30,232
  Deferred income taxes (Note 4)                                       --            3,244
  Liabilities from risk management and trading
    activities (Note 18)                                           70,667           35,994
  Other current liabilities                                        64,972           69,475
                                                              -----------      -----------
          Total current liabilities                             1,055,115        1,085,506
                                                              -----------      -----------
LONG-TERM DEBT LESS CURRENT
  MATURITIES (Note 6)                                           2,881,695        2,673,078
                                                              -----------      -----------
DEFERRED CREDITS AND OTHER
  Liabilities from risk management and trading
    activities-long term (Note 18)                                 75,642          207,576
  Deferred income taxes (Note 4)                                1,209,074        1,064,993
  Unamortized gain - sale of utility plant (Note 9)                59,484           64,060
  Pension liability (Note 8)                                      183,880           49,032
  Other                                                           274,763          295,831
                                                              -----------      -----------
          Total deferred credits and other                      1,802,843        1,681,492
                                                              -----------      -----------
COMMITMENTS AND CONTINGENCIES (NOTES
  3, 11 AND 12)

COMMON STOCK EQUITY (Note 7)
  Common stock, no par value; authorized
    150,000,000 shares; issued 91,379,947 at end
    of 2002 and 84,824,947 at end of 2001                       1,737,258        1,536,924
  Treasury stock; 124,830 shares at end of 2002 and
    101,307 shares at end of 2001                                  (4,358)          (5,886)
                                                              -----------      -----------
          Total common stock                                    1,732,900        1,531,038
                                                              -----------      -----------
  Accumulated other comprehensive loss:
    Minimum pension liability adjustment                          (71,264)            (966)
    Derivative instruments                                        (20,020)         (63,599)
                                                              -----------      -----------
          Total accumulated other comprehensive loss              (91,284)         (64,565)
                                                              -----------      -----------
  Retained earnings                                             1,044,537        1,032,850
                                                              -----------      -----------
          Total common stock equity                             2,686,153        2,499,323
                                                              -----------      -----------

TOTAL LIABILITIES AND EQUITY                                  $ 8,425,806      $ 7,939,399
                                                              ===========      ===========
</TABLE>

See Notes to Consolidated Financial Statements.

                                       77
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                             (dollars in thousands)

<TABLE>
<CAPTION>
                                                                        Year Ended December 31,
                                                             ---------------------------------------------
                                                                2002             2001             2000
                                                             -----------      -----------      -----------
<S>                                                          <C>              <C>              <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Income before accounting change                              $   215,153      $   327,367      $   302,332
Items not requiring cash:
  Depreciation and amortization                                  424,886          427,903          431,229
  Nuclear fuel amortization                                       31,185           28,362           30,083
  Deferred income taxes                                          196,324          (17,203)         (37,885)
  Change in mark-to-market                                       (18,146)        (133,573)         (11,752)
  Redhawk Units 3 and 4 cancellation                              49,192               --               --
Changes in current assets and liabilities:
  Customer and other receivables                                  18,615          146,581         (269,223)
  Materials, supplies and fossil fuel                            (11,599)         (16,867)             475
  Other current assets                                            (9,784)          (1,276)         (39,083)
  Accounts payable                                                74,833         (127,782)         193,502
  Accrued taxes                                                  (36,039)           7,483           18,736
  Accrued interest                                                 4,212            5,852            9,701
  Other current liabilities                                       17,489            5,260           98,493
Change in real estate investments                                 (6,112)         (44,173)         (25,937)
Increase in regulatory assets                                    (11,029)         (17,516)         (14,138)
Change in risk management and trading - assets                   (11,700)         (51,894)              --
Change in risk management and trading - liabilities              (22,783)          45,330           13,834
Change in customer advances                                      (23,780)          28,599            2,544
Change in pension liability                                       (1,571)         (28,347)         (16,575)
Change in long-term assets                                       (16,918)          13,874           54,829
Change in long-term liabilities                                    8,346          (26,937)         (27,771)
                                                             -----------      -----------      -----------
Net cash flow provided by operating activities                   870,774          571,043          713,394
                                                             -----------      -----------      -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures                                            (895,522)      (1,055,574)        (658,608)
Capitalized interest                                             (44,110)         (47,862)         (21,638)
Other                                                             36,635          (16,481)         (55,595)
                                                             -----------      -----------      -----------
Net cash flow used for investing activities                     (902,997)      (1,119,917)        (735,841)
                                                             -----------      -----------      -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt                                       725,419          995,447          651,000
Short-term borrowings and payments - net                        (303,579)         322,987           44,475
Dividends paid on common stock                                  (137,721)        (129,199)        (120,733)
Repayment of long-term debt                                     (404,670)        (621,057)        (558,019)
Common stock equity issuance                                     199,238               --               --
Other                                                              2,624           (1,048)          (4,618)
                                                             -----------      -----------      -----------
Net cash flow provided by financing activities                    81,311          567,130           12,105
                                                             -----------      -----------      -----------

NET CASH FLOW                                                     49,088           18,256          (10,342)

CASH AND CASH EQUIVALENTS AT
  BEGINNING OF YEAR                                               28,619           10,363           20,705
                                                             -----------      -----------      -----------

CASH AND CASH EQUIVALENTS AT END OF YEAR                     $    77,707      $    28,619      $    10,363
                                                             ===========      ===========      ===========
Supplemental disclosure of cash flow information
Cash paid during the period for:
  Income taxes paid/(refunded) (Note 4)                      $   (17,918)     $   223,037      $   219,411
  Interest paid, net of amounts capitalized                  $   126,322      $   115,276      $   132,434
</TABLE>

See Notes to Consolidated Financial Statements.

                                       78
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
            CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
              For the Years Ended December 31, 2002, 2001 and 2000
                             (dollars in thousands)

<TABLE>
<CAPTION>
                                                          2002             2001             2000
                                                      -----------      -----------      -----------
<S>                                                   <C>              <C>              <C>
COMMON STOCK (Note 7)
Balance at beginning of year                          $ 1,536,924      $ 1,537,920      $ 1,540,197
Issuance of common stock                                  199,238               --               --
Other                                                       1,096             (996)          (2,277)
                                                      -----------      -----------      -----------
Balance at end of year                                  1,737,258        1,536,924        1,537,920
                                                      -----------      -----------      -----------

TREASURY STOCK (Note 7)
Balance at beginning of year                               (5,886)          (5,089)          (2,748)
Purchase of treasury stock                                 (5,971)         (16,393)         (12,968)
Reissuance of treasury stock used for stock
  compensation, net                                         7,499           15,596           10,627
                                                      -----------      -----------      -----------
Balance at end of year                                     (4,358)          (5,886)          (5,089)
                                                      -----------      -----------      -----------

RETAINED EARNINGS
Balance at beginning of year                            1,032,850          849,883          668,284
Net income                                                149,408          312,166          302,332
Common stock dividends                                   (137,721)        (129,199)        (120,733)
                                                      -----------      -----------      -----------
Balance at end of year                                  1,044,537        1,032,850          849,883
                                                      -----------      -----------      -----------
ACCUMULATED OTHER
  COMPREHENSIVE LOSS
Balance at beginning of year                              (64,565)              --               --
Minimum pension liability adjustment, net of
  tax of $46,109 and $634                                 (70,298)            (966)              --
Cumulative effect of a change in accounting
  for derivatives, net of tax of $47,404                       --           72,274               --
Unrealized gain/(loss) on derivative
  instruments, net of tax of $28,820 and
  $71,720                                                  43,939         (109,346)              --
Reclassification of realized gain to
  income, net of tax of $237 and $17,399                     (360)         (26,527)              --
                                                      -----------      -----------      -----------
Balance at end of year                                    (91,284)         (64,565)              --
                                                      -----------      -----------      -----------

TOTAL COMMON STOCK EQUITY                             $ 2,686,153      $ 2,499,323      $ 2,382,714
                                                      ===========      ===========      ===========
COMPREHENSIVE INCOME
Net income                                            $   149,408      $   312,166      $   302,332
Other comprehensive loss                                  (26,719)         (64,565)              --
                                                      -----------      -----------      -----------
Comprehensive income                                  $   122,689      $   247,601      $   302,332
                                                      ===========      ===========      ===========
</TABLE>

See Notes to Consolidated Financial Statements.

                                       79
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

CONSOLIDATION AND NATURE OF OPERATIONS

     The consolidated financial statements include the accounts of Pinnacle West
and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and
El Dorado (principally NAC). Significant intercompany accounts and transactions
between the consolidated companies have been eliminated.

     APS is an 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 half of the Phoenix
metropolitan area. Electricity is delivered through a distribution system owned
by APS. APS also generates, sells and delivers electricity to wholesale
customers in the western United States. In early 2003, the marketing and trading
division of Pinnacle West was moved to APS for future marketing and trading
activities (existing wholesale contracts will remain at Pinnacle West) as a
result of the ACC's Track A Order prohibiting the previously required transfer
of APS' generating assets to Pinnacle West Energy. See Note 3 for a discussion
of the Track A Order. Pinnacle West Energy, which was formed in 1999, is the
subsidiary through which we conduct our competitive generation operations. APS
Energy Services was formed in 1998 and provides competitive commodity energy and
energy-related products to key customers in competitive markets in the western
United States. SunCor is a developer of residential, commercial and industrial
real estate projects in Arizona, New Mexico and Utah. El Dorado is an investment
firm, and its principal investment is in NAC, which is a company specializing in
spent nuclear fuel technology.

ACCOUNTING RECORDS AND USE OF ESTIMATES

     Our accounting records are maintained in accordance with accounting
principles generally accepted in the United States of America (GAAP). The
preparation of financial statements in accordance with GAAP requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities, disclosure of contingent assets and liabilities at the date of the
financial statements and reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. We have
reclassified certain prior year amounts to conform to the current year
presentation.

DERIVATIVE ACCOUNTING

     We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We manage risks associated with these market fluctuations by utilizing various
commodity derivatives, including exchange-traded futures and options and
over-the-counter forwards, options and swaps. As part of our overall risk
management program, we enter into derivative transactions to hedge purchases and
sales of electricity, fuels and emissions allowances and credits. The changes in
market value of such contracts have a high correlation to price changes in the
hedged commodities. In addition, subject to specified risk parameters monitored
by the ERMC, we engage in marketing and trading activities intended to profit
from market price movements.

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                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     We examine contracts at inception to determine the appropriate accounting
treatment. If a contract does not meet the derivative criteria or if it
qualifies for a SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," scope exception, we account for the contract on an accrual basis
with associated revenues and costs recorded at the time the contracted
commodities are delivered or received. SFAS No. 133 provides a scope exception
for contracts that meet the normal purchases and sales criteria specified in the
standard. Most 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.

     For contracts that qualify as a derivative and do not meet a SFAS No. 133
scope exception, we further examine the contract to determine if it will qualify
for hedge accounting. Changes in the fair value of the effective portion of
derivative instruments that qualify for cash flow hedge accounting treatment are
recognized as either an asset or liability and in common stock equity (as a
component of accumulated other comprehensive income (loss)). Gains and losses
related to 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 a contract does not meet the hedging criteria in SFAS No.
133, we recognize the changes in the fair value of the derivative instrument in
income each period through mark-to-market accounting.

     On October 1, 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. As a
result, our energy trading contracts that are derivatives continue to be
accounted for at fair value under SFAS No. 133. Contracts that were previously
marked-to-market as trading activities under EITF 98-10 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. Additionally, all gains and losses (realized and
unrealized) on energy trading contracts that qualify as derivatives are included
in marketing and trading segment revenues on the Consolidated Statements of
Income on a net basis. The rescission of EITF 98-10 has no effect on the
accounting for derivative instruments used for non-trading activities, which
continue to be accounted for in accordance with SFAS No. 133. See Note 18 for
more details on the change in accounting for energy trading contracts and for
further discussion on derivative accounting.

MARK-TO-MARKET ACCOUNTING

     Under mark-to-market accounting, the purchase or sale of energy commodities
is reflected at fair market value, net of valuation adjustments, with resulting
unrealized gains and losses recorded as assets and liabilities from risk
management and trading activities in the Consolidated Balance Sheets.

     We determine fair market value using actively-quoted prices when available.
We consider quotes for exchange-traded contracts and over-the-counter quotes
obtained from independent brokers to be actively-quoted.

     When actively-quoted prices are not available, we use prices provided by
other external sources. This includes quarterly and calendar year quotes from
independent brokers. We convert quarterly and calendar year quotes into monthly
prices based on historical relationships.

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<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     For options, long-term contracts and other contracts for which price quotes
are not available, we use models and other valuation methods. The valuation
models we employ utilize spot prices, forward prices, historical market data and
other factors to forecast future prices. The primary valuation technique we use
to calculate the fair value of contracts where price quotes are not available is
based on the extrapolation of forward pricing curves using observable market
data for more liquid delivery points in the same region and actual transactions
at the more illiquid delivery points. We also value option contracts using a
variation of the Black-Scholes option-pricing model.

     For non-exchange traded contracts, we calculate fair market value based on
the average of the bid and offer price, and we discount to reflect net present
value. We maintain certain valuation 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.

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

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

REGULATORY ACCOUNTING

     APS is regulated by the ACC and the FERC. The accompanying financial
statements reflect the rate-making policies of these commissions. For regulated
operations, we prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements. As a result, we capitalize
certain costs that would be included as expense in the current period by
unregulated companies. Regulatory assets represent incurred costs that have been
deferred because they are probable of future recovery in customer rates.
Regulatory liabilities generally represent obligations to make refunds to
customers for previous collections of costs not likely to be incurred.

     We are required to discontinue applying SFAS No. 71 when deregulatory
legislation is passed or a rate order is issued that contains sufficient detail
to determine its effect on the portion of the business being deregulated. In
1999, we discontinued the application of SFAS No. 71 for APS' generation
operations due to the 1999 Settlement Agreement with the ACC. See Note 3 for a
discussion of the 1999 Settlement Agreement.

                                       82
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     As a result, we tested the generation assets for impairment and determined
the generation assets were not impaired. Pursuant to the 1999 Settlement
Agreement, a regulatory disallowance removed $234 million pretax ($183 million
net present value) from ongoing regulatory cash flows and was recorded as a net
reduction of regulatory assets. This reduction ($140 million after income taxes)
was reported as an extraordinary charge on the 1999 Consolidated Statement of
Income.

     In 2002, the ACC directed APS not to transfer its generation assets, as
previously required by the 1999 Settlement Agreement (see "Track A Order" in
Note 3). Accordingly, we now consider APS generation to be cost-based,
rate-regulated and subject to the requirements of SFAS No. 71. The impact of
this change was immaterial to our consolidated financial statements.

     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.

     Prior to the 1999 Settlement Agreement, the ACC accelerated the
amortization of substantially all of APS' regulatory assets to an eight-year
period that would have ended June 30, 2004. 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

     Regulatory assets are reported as deferred debits on the Consolidated
Balance Sheets. As of December 31, 2002 and 2001, they are comprised of the
following (dollars in millions):

                                                                   December 31,
                                                                  --------------
                                                                  2002      2001
                                                                  ----      ----
Remaining balance recoverable under the 1999
  Settlement Agreement (a)                                        $104      $219
Spent nuclear fuel storage (Note 11)                                46        43
Electric industry restructuring transition costs (Note 3)           40        34
Other                                                               51        46
                                                                  ----      ----
     Total regulatory assets                                      $241      $342
                                                                  ====      ====

(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).

                                       83
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Regulatory liabilities are included in deferred credits and other on the
Consolidated Balance Sheets. As of December 31, 2002 and 2001, they are
comprised of the following (dollars in millions):

                                                                   December 31,
                                                                  --------------
                                                                  2002      2001
                                                                  ----      ----
Deferred gains on utility property                                $ 20      $ 20
Other                                                                6         7
                                                                  ----      ----
     Total regulatory liabilities                                 $ 26      $ 27
                                                                  ====      ====

RATE SYNCHRONIZATION COST DEFERRALS

     As authorized by the ACC, operating costs (excluding fuel) and financing
costs of Palo Verde Units 2 and 3 were deferred from the commercial operation
dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the
units were included in a rate order (April 1988 for Unit 2 and December 1991 for
Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to
accelerate the amortization of the deferrals over an eight-year period that will
end June 30, 2004. Amortization of the deferrals is included in depreciation and
amortization expense in the Consolidated Statements of Income.

UTILITY PLANT AND DEPRECIATION

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

     *    material and labor;
     *    contractor costs;
     *    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, plus removal costs
less salvage realized, to accumulated depreciation. See Note 2 for information
on a new accounting standard that impacts accounting for removal costs.

     We record depreciation on utility property 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, 2002 were as
follows:

     *    Fossil plant - 22 years;
     *    Nuclear plant - 22 years;
     *    Transmission - 34 years;
     *    Distribution - 28 years; and
     *    Other utility property - 9 years.

                                       84
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     For the years 2000 through 2002 the depreciation rates, as prescribed by
our regulators, ranged from a low of 1.51% to a high of 20%. The
weighted-average rate was 3.35% for 2002 and 3.40% for 2001 and 2000. We
depreciate non-utility property and equipment over the estimated useful lives of
the related assets, ranging from 3 to 30 years.

EL DORADO INVESTMENTS

     El Dorado accounts for its investments using the consolidated (if
controlled), equity (if significant influence) and cost (less than 20%
ownership) methods. Beginning in the third quarter of 2002, El Dorado began
consolidating the operations of NAC. See Note 22 for further details on El
Dorado's investment in NAC.

CAPITALIZED INTEREST

     Capitalized interest represents the cost of debt funds used to finance
construction projects. Plant construction costs, including capitalized interest,
are expensed through depreciation when completed projects are placed into
commercial operation. Capitalized interest does not represent current cash
earnings. The rate used to calculate capitalized interest was a composite rate
of 4.80% for 2002, 6.13% for 2001 and 6.62% for 2000.

ELECTRIC REVENUES

     Revenues related to the sale of energy are generally recorded when service
is rendered or energy is delivered to customers. However, the determination of
energy 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 energy delivered to customers since the date of
the last meter reading and the corresponding unbilled revenue are estimated. We
exclude sales taxes on electric revenues from both revenue and taxes other than
income taxes. Other than revenues and purchased power costs related to energy
trading activities, revenues are reported on a gross basis in our Consolidated
Statements of Income.

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

SUNCOR

     SunCor recognizes revenue from land, home and qualifying commercial
operating assets sales in full, provided (a) the income is determinable, that
is, the collectibility of the sales price is reasonably assured or the amount
that will not be collectible can be estimated, and (b) the earnings process is
virtually complete, that is, SunCor is not obligated to perform significant
activities after the sale to earn the income. Unless both conditions exist,
recognition of all or part of the income is postponed. A single method of
recognizing income is applied to all sales transactions within an entire home,
land or commercial development project. Commercial property and management
revenues are recorded over the term of the lease or period in which services are
provided.

                                       85
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PERCENTAGE OF COMPLETION - NAC

     Certain NAC contract revenues are accounted for under the
percentage-of-completion method. Revenues are recognized based upon total costs
incurred to date compared to total costs expected to be incurred for each
contract. Revisions in contract revenue and cost estimates are reflected in the
accounting period when known. Provisions are made for the full amounts of
anticipated losses in the periods in which they are first determined. Changes in
job performance, job conditions and estimated profitability, including those
arising from contract penalty provisions and final contract settlements, may
result in revisions to costs and income, and are recognized in the period in
which revisions are determined. Profit incentives are included in revenues when
their realization is reasonably assured.

     Contract costs include all direct material and labor costs and those
indirect costs related to contract performance, such as indirect labor,
supplies, tools, repairs and depreciation costs. General and administrative
costs are charged to expense as incurred.

CASH AND CASH EQUIVALENTS

     For purposes of the Consolidated Statements of Cash Flows, we consider all
highly liquid debt instruments purchased with an initial maturity of three
months or less to be cash equivalents.

NUCLEAR FUEL

     APS charges nuclear fuel to fuel expense by using the unit-of-production
method. The unit-of-production method is an amortization method based on actual
physical usage. APS divides the cost of the fuel by the estimated number of
thermal units it expects to produce with that fuel. APS then multiplies that
rate by the number of thermal units produced within the current period. This
calculation determines the current period nuclear fuel expense.

     APS also charges nuclear fuel expense for the permanent disposal of spent
nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear
fuel, and it charges APS $0.001 per kWh of nuclear generation. See Note 11 for
information about spent nuclear fuel disposal and Note 12 for information on
nuclear decommissioning costs.

INCOME TAXES

     Income taxes are provided using the asset and liability approach prescribed
by SFAS No. 109, "Accounting for Income Taxes." We file our federal income tax
return on a consolidated basis and we file our state income tax returns on a
consolidated or unitary basis. In accordance with our intercompany tax sharing
agreement, federal and state income taxes are allocated to each subsidiary as
though each first-tier subsidiary filed a separate income tax return. Any
difference between the aforementioned allocations and the consolidated (and
unitary) income tax liability is attributed to the parent company.

                                       86
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

REACQUIRED DEBT COSTS

     For debt related to the regulated portion of APS' business, APS amortizes
those gains and losses incurred upon early retirement over the original
remaining life of the debt. In accordance with the 1999 Settlement Agreement,
APS is continuing to accelerate reacquired debt costs over an eight-year period
that will end June 30, 2004. All regulatory asset amortization is included in
depreciation and amortization expense in the Consolidated Statements of Income.

REAL ESTATE INVESTMENTS

     Real estate investments primarily include SunCor's land, home inventory and
investments in joint ventures. Land includes acquisition costs, infrastructure
costs, property taxes and capitalized interest directly associated with the
acquisition and development of each project. Land under development and land
held for future development are stated at accumulated cost, except to the extent
that such land is believed to be impaired, it is written down to fair value.
Land held for sale is stated at the lower of accumulated cost or estimated fair
value less costs to sell. Home inventory consists of construction costs,
improved lot costs, capitalized interest and property taxes on homes under
construction. Home inventory is stated at the lower of accumulated cost or
estimated fair value less costs to sell. Investments in joint ventures for which
SunCor does not have a controlling financial interest are not consolidated but
are accounted for using the equity method of accounting.

STOCK-BASED COMPENSATION

     In 2002, we began applying the fair value method of accounting for
stock-based compensation, as provided for in SFAS No. 123, "Accounting for
Stock-Based Compensation." The fair value method of accounting is the preferred
method. In accordance with the transition requirements of SFAS No. 123, we
applied the fair value method prospectively, beginning with 2002 stock grants.
In prior years, we recognized stock compensation expense based on the intrinsic
value method allowed in Accounting Principles Board Opinion (APB) No. 25,
"Accounting for Stock Issued to Employees."

     The following chart compares our net income, stock compensation expense and
earnings per share to what those items would have been if we had recorded stock
compensation expense based on the fair value method for all stock grants through
2002 (dollars in thousands, except per share amounts):

                                       87
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                              2002         2001          2000
                                            ---------    ---------    ---------
Net Income:
  As reported                               $ 149,408    $ 312,166    $ 302,332
  Pro forma (fair value method)               148,013      309,874      301,102
Stock compensation expense (net of tax):
  As reported                                     300           --           --
  Pro forma (fair value method)                 1,395        2,292        1,230

Earnings per share - basic:
  As reported                               $    1.76    $    3.68    $    3.57
  Pro forma (fair value method)             $    1.74    $    3.66    $    3.55
Earnings per share - diluted:
  As reported                               $    1.76    $    3.68    $    3.56
  Pro forma (fair value method)             $    1.74    $    3.65    $    3.55

     In order to calculate the fair value of the 2002 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:

                                                2002         2001         2000
                                               ------       ------       ------
Risk-free interest rate                          4.17%        4.08%        5.81%
Dividend yield                                   4.17%        3.70%        3.48%
Volatility                                      22.59%       27.66%       32.00%
Expected life (months)                             60           60           60

     See Note 16 for further discussion about our stock compensation plans.

2.   ACCOUNTING MATTERS

     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 will be 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 fossil 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
net regulatory liability of $40 million for our asset retirement obligations

                                       88
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

related to our regulated utility. This regulatory liability represents the
difference between the amount currently being recovered in regulated rates and
the amount calculated under SFAS No. 143. We believe we can recover in regulated
rates the transition costs and ongoing current period costs calculated in
accordance with SFAS No. 143.

     In November 2002, the EITF reached a consensus on EITF 00-21, "Revenue
Arrangements with Multiple Deliverables." EITF 00-21 addresses certain aspects
of the accounting by a vendor for arrangements under which it will perform
multiple revenue-generating activities. EITF 00-21 specifically addresses how to
determine whether an arrangement has identifiable, separable revenue-generating
activities. EITF 00-21 does not address when the criteria for revenue
recognition are met or provide guidance on the appropriate revenue recognition
convention. EITF 00-21 is effective for revenue arrangements entered into after
July 1, 2003. We are currently evaluating the impacts of this new guidance, but
we do not believe it will have a material impact on our financial statements.

     On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the accounting and reporting provisions for the disposal of
a segment of a business. This standard did not impact our financial statements
at adoption. For each of the years 2002, 2001 and 2000, items requiring
discontinued operations reporting were immaterial.

     In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
Nos. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections," which, among other things, supersedes previous guidance for
reporting gains and losses from extinguishment of debt. This standard did not
impact our financial statements at adoption.

     In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities." The standard requires companies to
recognize costs associated with exit or disposal activities when they are
incurred rather than at the date of a commitment to an exit or disposal plan.
The guidance will be applied to exit or disposal activities initiated after
December 31, 2002. This standard did not impact our financial statements at
adoption.

     In 2001, the American Institute of Certified Public Accountants (AICPA)
issued an exposure draft of a proposed Statement of Position (SOP), "Accounting
for Certain Costs Related to Property, Plant, and Equipment." This proposed SOP
would create a project timeline framework for capitalizing costs related to
property, plant and equipment construction. It would require that property,
plant and equipment assets be accounted for at the component level and require
administrative and general costs incurred in support of capital projects to be
expensed in the current period. In November 2002, the AICPA announced they would
no longer issue general purpose SOPs. The work they have performed on the
proposed SOP will be transitioned to the FASB staff. In February 2003, the FASB
determined that the AICPA should continue their deliberations on certain aspects
of the proposed SOP. We are waiting for further guidance from the FASB staff and
the AICPA on the timing of the final guidance.

     See the following Notes for other new accounting standards:

                                      89
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     *    Notes 1 and 16 for a new accounting standard (SFAS No. 148) related to
          stock-based compensation;

     *    Note 18 for a new EITF issue (EITF 02-3) related to accounting for
          energy trading contracts;

     *    Note 20 for a new interpretation (FIN No. 46) related to VIEs;

     *    Note 21 for a new standard (SFAS No. 142) related to goodwill and
          intangible assets; and

     *    Note 23 for a new interpretation (FIN No. 45) on guarantees.

3.   REGULATORY MATTERS

ELECTRIC INDUSTRY RESTRUCTURING

STATE

     OVERVIEW On September 21, 1999, the ACC approved Rules that provide a
framework for the introduction of retail electric competition in Arizona. On
September 23, 1999, the ACC approved a comprehensive settlement agreement among
APS and various parties related to the implementation of retail electric
competition in Arizona. Under the Rules, as modified by the 1999 Settlement
Agreement, APS was required to transfer all of its competitive electric assets
and services to an unaffiliated party or parties or to a separate corporate
affiliate or affiliates no later than December 31, 2002. Consistent with that
requirement, APS had been addressing the legal and regulatory requirements
necessary to complete the transfer of its generation assets to Pinnacle West
Energy on or before that date. On September 10, 2002, the ACC issued the Track A
Order, which, among other things, directed APS not to transfer its generation
assets to Pinnacle West Energy. See "Track A Order" below.

     On September 16, 2002, APS filed an application with the ACC requesting the
ACC to allow APS to borrow up to $500 million and to lend the proceeds to
Pinnacle West Energy or to the Company; to guarantee up to $500 million of
Pinnacle West Energy's or the Company's debt; or a combination of both, not to
exceed $500 million in the aggregate. In its application, APS stated that the
ACC's reversal of the generation asset transfer requirement and the resulting
bifurcation of generation assets between APS and Pinnacle West Energy under
different regulatory regimes result in Pinnacle West Energy being unable to
attain investment-grade credit ratings. This, in turn, precludes Pinnacle West
Energy from accessing capital markets to refinance the bridge financing provided
by the Company to fund the construction of Pinnacle West Energy generation
assets or from effectively competing in the wholesale markets. On March 27,
2003, the ACC authorized APS to lend up to $500 million to Pinnacle West Energy,
guarantee up to $500 million of Pinnacle West Energy debt, or a combination of
both, not to exceed $500 million in the aggregate. See "ACC Applications" below.

                                       90
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     COMPETITIVE PROCUREMENT PROCESS

     On September 10, 2002, the ACC issued an order that, among other things,
established a requirement that APS competitively procure certain power
requirements. On March 14, 2003, the ACC issued the Track B Order which
documented the decision made by the ACC at its open meeting on February 27,
2003, addressing this requirement. Under the order, APS will be required to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, APS will be required to solicit competitive
bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of
energy, or approximately 20% of APS' total retail energy requirements. The bid
amounts are expected to increase in 2004 and 2005 based largely on growth in
APS' retail load and APS' retail energy sales. The Track B Order also confirmed
that it was "not intended to change the current rate base status of [APS']
existing assets." The order recognizes APS' right to reject any bids that are
unreasonable, uneconomical or unreliable.

     APS expects to issue requests for proposals in March 2003 and to complete
the selection process by June 1, 2003. Pinnacle West Energy will be eligible to
bid to supply APS' electricity requirements. See "Track B Order" below.

     These regulatory developments and legal challenges to the Rules have raised
considerable uncertainty about the status and pace of retail electric
competition in Arizona. These matters are discussed in more detail below.

     1999 SETTLEMENT AGREEMENT

     The following are the major provisions of the 1999 Settlement Agreement, as
approved by the ACC:

     *    APS has reduced, and will reduce, 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; and approximately $28 million
          ($17 million after taxes), effective July 1, 2002. The final price
          reduction is to be implemented July 1, 2003. For customers having
          loads of three MW or greater, standard-offer rates have been reduced
          in varying annual increments that total 5% in the years 1999 through
          2002.

     *    Unbundled rates being charged by APS for competitive direct access
          service (for example, distribution services) became effective upon
          approval of the 1999 Settlement Agreement, retroactive to July 1,
          1999, and also became subject to annual reductions beginning January
          1, 2000, that vary by rate class, through January 1, 2004.

     *    There will be 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

                                       91
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                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

          limited circumstances. Neither the ACC nor APS will be prevented from
          seeking or authorizing rate changes prior to July 1, 2004 in the event
          of conditions or circumstances that constitute an emergency, such as
          an inability to finance on reasonable terms; material changes in APS'
          cost of service for ACC-regulated services resulting from federal,
          tribal, state or local laws; regulatory requirements; or judicial
          decisions, actions or orders.

     *    APS will be permitted to defer for later recovery prudent and
          reasonable costs of complying with the Rules, system benefits costs in
          excess of the levels included in then-current (1999) rates, and costs
          associated with the "provider of last resort" and standard-offer
          obligations for service after July 1, 2004. These costs are to be
          recovered through an adjustment clause or clauses commencing on July
          1, 2004.

     *    APS' distribution system opened for retail access effective September
          24, 1999. Customers were eligible for retail access in accordance with
          the phase-in adopted by the ACC under the Rules (see "Retail Electric
          Competition Rules" below), including an additional 140 MW being made
          available to eligible non-residential customers. APS opened its
          distribution system to retail access for all customers on January 1,
          2001. The regulatory developments and legal challenges to the Rules
          discussed in this note have raised considerable uncertainty about the
          status and pace of electric competition in Arizona. Although some very
          limited retail competition existed in APS' service area in 1999 and
          2000, there are currently no active retail competitors providing
          unbundled energy or other utility services to APS' customers. As a
          result, we cannot predict when, and the extent to which, additional
          competitors will re-enter APS' service territory.

     *    Prior to the 1999 Settlement Agreement, APS was recovering
          substantially all of its regulatory assets through July 1, 2004,
          pursuant to a 1996 regulatory agreement. In addition, the 1999
          Settlement Agreement states that APS has demonstrated that its
          allowable stranded costs, after mitigation and exclusive of regulatory
          assets, are at least $533 million net present value (in 1999 dollars).
          APS will not be allowed to recover $183 million net present value (in
          1999 dollars) of the above amounts. The 1999 Settlement Agreement
          provides that APS will have the opportunity to recover $350 million
          net present value (in 1999 dollars) through a competitive transition
          charge that will remain in effect through December 31, 2004, at which
          time it will terminate. The costs subject to recovery under the
          adjustment clause described above will be decreased or increased by
          any over/under-recovery due to sales volume variances.

     *    APS will form, or cause to be formed, a separate corporate affiliate
          or affiliates and transfer to such affiliate(s) its competitive
          electric assets and services at book value as of the date of transfer,
          and will complete the transfers no later than December 31, 2002. APS
          will be allowed to defer and later collect, beginning July 1, 2004,
          67% of its costs to accomplish the required transfer of generation
          assets to an affiliate. However, as noted above and discussed in
          greater detail below, in 2002 the ACC unilaterally modified this
          aspect of the 1999 Settlement Agreement by issuing an order preventing
          APS from transferring its generation assets.

                                       92
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     RETAIL ELECTRIC COMPETITION RULES

     The Rules approved by the ACC included the following major provisions:

     *    They apply to virtually all Arizona electric utilities regulated by
          the ACC, including APS.

     *    Effective January 1, 2001, retail access became available to all APS
          retail electricity customers.

     *    Electric service providers that get CC&N's from the ACC can supply
          only competitive services, including electric generation, but not
          electric transmission and distribution.

     *    Affected utilities must file ACC tariffs that unbundle rates for
          noncompetitive services.

     *    The ACC shall allow a reasonable opportunity for recovery of
          unmitigated stranded costs.

     *    Absent an ACC waiver, prior to January 1, 2001, each affected utility
          (except certain electric cooperatives) must transfer all competitive
          electric assets and services to an unaffiliated party or parties or to
          a separate corporate affiliate or affiliates. Under the 1999
          Settlement Agreement, APS received a waiver to allow transfer of its
          competitive electric assets and services to affiliates no later than
          December 31, 2002. However, as noted above and discussed in greater
          detail below, in 2002 the ACC reversed its decision, as reflected in
          the Rules, to require APS to transfer its generation assets.

     Under the 1999 Settlement Agreement, the Rules are to be interpreted and
applied, to the greatest extent possible, in a manner consistent with the 1999
Settlement Agreement. If the two cannot be reconciled, APS must seek, and the
other parties to the 1999 Settlement Agreement must support, a waiver of the
Rules in favor of the 1999 Settlement Agreement.

     On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers,
including APS Energy Services, to operate in Arizona. We do not believe the
ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was
not at issue in the consolidated cases before the judge. Further, the ACC made
findings related to the fair value of APS' property in the order approving the
1999 Settlement Agreement. The ACC and other parties aligned with the ACC have

                                       93
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                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

appealed the ruling to the Arizona Court of Appeals, as a result of which the
Superior Court's ruling is automatically stayed pending further judicial review.
That appeal is still pending. In a similar appeal concerning the issuance of
competitive telecommunications CC&N's, the Arizona Court of Appeals invalidated
rates for competitive carriers due to the ACC's failure to establish a fair
value rate base for such carriers. That decision was upheld by the Arizona
Supreme Court.

     PROVIDER OF LAST RESORT OBLIGATION

     Although the Rules allow retail customers to have access to competitive
providers of energy and energy services, APS is the "provider of last resort"
for standard-offer, full-service customers under rates that have been approved
by the ACC. These rates are established until at least July 1, 2004. The 1999
Settlement Agreement allows APS to seek adjustment of these rates in the event
of emergency conditions or circumstances, such as the inability to secure
financing on reasonable terms; material changes in APS' cost of service for
ACC-regulated services resulting from federal, tribal, state or local laws;
regulatory requirements; or judicial decisions, actions or orders. Energy prices
in the western wholesale market vary and, during the course of the last two
years, have been volatile. At various times, prices in the spot wholesale market
have significantly exceeded the amount included in APS' current retail rates. In
the event of shortfalls due to unforeseen increases in load demand or generation
or transmission outages, APS may need to purchase additional supplemental power
in the wholesale spot market. Unless APS is able to obtain an adjustment of its
rates under the emergency provisions of the 1999 Settlement Agreement, there can
be no assurance that APS would be able to fully recover the costs of this power.

     GENERIC DOCKET

     In January 2002, the ACC opened a "generic" docket to "determine if changed
circumstances require the [ACC] to take another look at electric restructuring
in Arizona." In February 2002, the ACC docket relating to APS' October 2001
filing was consolidated with several other pending ACC dockets, including the
generic docket. On May 2, 2002, the ACC issued a procedural order stating that
hearings would begin on June 17, 2002 on various issues, including APS' planned
divestiture of generation assets to Pinnacle West Energy and associated market
and affiliate issues. The procedural order also stated that consideration of the
competitive bidding process required by the Rules would proceed concurrently
with the Track A issues.

     TRACK A ORDER

     On September 10, 2002, the ACC issued the Track A Order, which documents
decisions made by the ACC at an open meeting on August 27, 2002. The major
provisions of the Track A Order include, among other things:

     Provisions related to the reversal of the generation asset transfer
requirement:

     *    The ACC reversed its decision, as reflected in the Rules, to require
          APS to transfer its generation assets either to an unrelated third
          party or to a separate corporate affiliate; and

     *    the ACC unilaterally modified the 1999 Settlement Agreement, which
          authorized APS' transfer of its generating assets, and directed APS to
          cancel its activities to transfer its generation assets to Pinnacle
          West Energy.

                                       94
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Provisions related to the wholesale competitive energy procurement process
(Track B issues):

     *    The ACC stayed indefinitely the requirement of the Rules that APS
          acquire 100% of its energy needs for its standard offer customers from
          the competitive market, with at least 50% obtained through a
          competitive bid process;

     *    the ACC established a requirement that APS competitively procure, at a
          minimum, any required power that it cannot produce from its existing
          assets in accordance with the ultimate outcome of the Track B
          proceedings;

     *    the ACC directed the parties to develop a competitive procurement
          ("bidding") process that can begin by March 1, 2003; and

     *    the ACC stated that "the [Pinnacle West Energy] generating assets that
          APS may acquire from [Pinnacle West Energy] shall not be counted as
          APS assets in determining the amount, timing and manner of the
          competitive solicitation" for Track B purposes, thereby bifurcating
          the regulatory treatment of the existing APS assets and the Pinnacle
          West Energy assets.

     On November 15, 2002, APS filed appeals of the Track A Order in the
Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals.
ARIZONA PUBLIC SERVICE COMPANY VS. ARIZONA CORPORATION COMMISSION, CV 2002-0222
32. ARIZONA PUBLIC SERVICE COMPANY VS. ARIZONA CORPORATION COMMISSION, 1CA CC
02-0002. On December 13, 2002, APS and the ACC staff agreed to principles for
resolving certain issues raised by APS in its appeals of the Track A Order. APS
and the ACC are the only parties to the Track A Order appeals. The major
provisions of this document include, among other things, the following:

     *    The parties agreed that it would be appropriate for the ACC to
          consider the following matters in APS' upcoming general rate case,
          anticipated to be filed before June 30, 2003:

          *    the generating assets to be included in APS' rate base, including
               the question of whether certain power plants currently owned by
               Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West
               Phoenix Units 4 and 5, and Saguaro Unit 3) should be included in
               APS' rate base;

          *    the appropriate treatment of the $234 million pretax asset
               write-off agreed to by APS as part of a 1999 settlement agreement
               approved by the ACC among APS and various parties related to the
               implementation of retail competition in Arizona; and

          *    the appropriate treatment of costs incurred by APS in preparation
               for the previously anticipated transfer of generation assets to
               Pinnacle West Energy.

     *    Upon the ACC's issuance of a final decision that is no longer subject
          to appeal approving the Financing Application, with appropriate
          conditions, APS' appeals of the Track A Order would be limited to the
          issues described in the preceding bullet points, each of which would
          be presented to the ACC for consideration prior to any final judicial
          resolution.

                                       95
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     On February 21, 2003, a Notice of Claim was filed with the ACC and the
Arizona Attorney General on behalf of APS, Pinnacle West and Pinnacle West
Energy to preserve their and our rights relating to the Track A Order.

     TRACK B ORDER

     The ACC Staff has conducted workshops on the Track B issues with various
parties to determine and define the appropriate process to be used for
competitive power procurement. On September 10, 2002, the ACC issued an order
that, among other things, established a requirement that APS competitively
procure certain power requirements. On March 14, 2003, the ACC issued the Track
B Order which documented the decision made by the ACC at its open meeting on
February 27, 2003 addressing this requirement. The order adopted most of the
provisions of an ACC ALJ's recommendation that was issued on January 30, 2003.
Under the ACC's Track B Order, APS will be required to solicit bids for certain
estimated capacity and energy requirements for periods beginning July 1, 2003.
For 2003, APS will be required to solicit competitive bids for about 2,500
megawatts of capacity and about 4,600 gigawatt-hours of energy, or approximately
20% of APS' total retail energy requirements. The bid amounts are expected to
increase in 2004 and 2005 based largely on growth in APS' retail load and APS'
retail energy sales. The Track B Order also confirmed that it was "not intended
to change the current rate base status of [APS'] existing assets."

     The order recognizes APS' right to reject any bids that are unreasonable,
uneconomical or unreliable. The Track B procurement process will involve the ACC
Staff and an independent monitor. The Track B Order also contains requirements
relating to standards of conduct between APS and any affiliate of APS that may
participate in the competitive solicitation, requires that APS treat bidders in
a non-discriminatory manner and requires APS to file a protocol regarding
short-term and emergency procurements. The order permits the provision of
corporate oversight, support and governance as long as such activities do not
favor Pinnacle West Energy in the procurement process or provide Pinnacle West
Energy with confidential APS bidding information that is not available to other
bidders. The order directs APS to evaluate bids on cost, reliability and
reasonableness. The decision requires bidders to allow the ACC to inspect their
plants and requires assurances of appropriate competitive market conduct from
senior officers of such bidders. Following the solicitation, APS will prepare a
report evaluating environmental issues relating to the procurement and a series
of workshops on environmental risk management will be commenced thereafter.

     APS expects to issue requests for proposals in March 2003 and to complete
the selection process by June 1, 2003. Pinnacle West Energy will be eligible to
bid to supply APS' electricity requirements.

                                       96
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                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     ACC APPLICATIONS

     On September 16, 2002, APS filed a Financing Application requesting the ACC
to allow APS to borrow up to $500 million and to lend the proceeds to Pinnacle
West Energy or the Company; to guarantee up to $500 million of Pinnacle West
Energy's or the Company's debt; or a combination of both, not to exceed $500
million in the aggregate. The loan and/or the guarantee would be used to
refinance debt incurred to fund the construction of Pinnacle West Energy
generation assets.

     The Financing Application addressed, among other things, the following
matters:

     *    APS noted that its April 19, 2002 filing with the ACC had sought
          unification of "[Pinnacle West Energy] Assets" (West Phoenix Units 4
          and 5, Redhawk Units 1 and 2, and Saguaro Unit 3) and APS generation
          assets under a common financial and regulatory regime. APS further
          noted that the Track A Order's language regarding the treatment of the
          Pinnacle West Energy Assets for Track B purposes appears to postpone a
          decision regarding the inclusion of the Pinnacle West Energy Assets in
          APS' rate base, thereby effectively precluding the consolidation of
          the Pinnacle West Energy Assets at APS under a common financial and
          regulatory regime at the present time.

     *    APS stated that it did not intend or desire to foreclose the
          possibility that it would acquire all or part of the Pinnacle West
          Energy Assets or that it may propose that the Pinnacle West Energy
          Assets be included in APS' rate base or afforded cost-of-service
          regulatory treatment to the extent the Pinnacle West Energy Assets are
          used by APS customers. APS stated that these issues would be
          appropriate topics in APS' 2003 general rate case and noted that the
          Track A Order specifically stated that the ACC would not pre-judge the
          eventual rate treatment of the Pinnacle West Energy Assets.

     *    APS stated that the Track A Order's reversal of the generation asset
          transfer requirement and the resulting bifurcation of generation
          assets between APS and Pinnacle West Energy under different regulatory
          regimes result in Pinnacle West Energy being unable to attain
          investment-grade credit ratings. This, in turn, precludes Pinnacle
          West Energy from accessing capital markets to refinance the bridge
          financing provided by the Company to fund the construction of the
          Pinnacle West Energy Assets or from effectively competing in the
          wholesale markets. APS noted that Pinnacle West Energy had previously
          received investment-grade credit ratings contingent upon its receipt
          of APS generation assets and that the Company's credit ratings could
          be adversely affected if Pinnacle West Energy is unable to finance its
          capital requirements. On November 4, 2002, Standard & Poor's lowered
          the Company's senior unsecured debt rating from "BBB" to "BBB-."

     *    APS stated that the amount of the requested loan and/or guarantee is
          APS' present estimate of the amount of credit support necessary
          through APS to restore Pinnacle West Energy and the Company to their
          credit status prior to the ACC's issuance of the Track A Order. APS
          further stated that if the requested amount proves to be inadequate,
          APS reserves the right to submit a second financing application
          seeking additional credit support.

                                       97
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     On March 27, 2003, the ACC approved the Financing Application, subject to
the following principal conditions:

     *    any debt issued by APS pursuant to the order must be unsecured;

     *    APS will be permitted to loan up to $500 million to Pinnacle West
          Energy (the "APS Loan"), guarantee up to $500 million of Pinnacle West
          Energy debt, or a combination of both, not to exceed $500 million in
          the aggregate;

     *    the APS Loan must be callable and secured by certain Pinnacle West
          Energy assets;

     *    the APS Loan must bear interest at a rate equal to 264 basis points
          above the interest rate on APS debt that could be issued and sold on
          equivalent terms (including, but not limited to, maturity and
          security);

     *    the 264 basis points referred to in the previous bullet point will be
          capitalized as a deferred credit and used to offset retail rates in
          the future, with the deferred credit balance bearing an interest rate
          of six percent per annum;

     *    the APS Loan must have a maturity date of not more than four years,
          unless otherwise ordered by the ACC;

     *    any demonstrable increase in APS' cost of capital as a result of the
          transaction (such as from a decline in bond rating) will be excluded
          from future rate cases;

     *    APS must maintain a common equity ratio of at least forty percent and
          may not pay common dividends if such payment would reduce its common
          equity ratio below that threshold, unless otherwise waived by the ACC.
          The ACC will process any waiver request within sixty days, and for
          this sixty-day period this condition will be suspended. However, this
          condition, which will continue indefinitely, will not be permanently
          waived without an order of the ACC; and

     *    certain waivers of the ACC's affiliated interest rules previously
          granted to APS and its affiliates will be 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

                                       98
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                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

          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, with an expected commercial operation
               date in mid-2003, and (b) Silverhawk plant, located near Las
               Vegas, with an expected commercial operation date in mid-2004;
               and

          *    Covered Transactions related to the sale of 25% of the Silverhawk
               plant to SNWA if SNWA exercises its existing purchase option to
               do so.

     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.

     In mid-2003, the Company will need to refinance approximately $475 million
of parent company indebtedness. We expect that this indebtedness will be repaid
through funds borrowed by Pinnacle West Energy from APS under the APS Loan.

     On November 22, 2002, the ACC approved APS' request to permit APS to (a)
make short-term advances to Pinnacle West in the form of an inter-affiliate line
of credit in the amount of $125 million, or (b) guarantee $125 million of
Pinnacle West's short-term debt, subject to certain conditions. See Note 5.

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 has 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, and
the FERC has announced that it will issue an additional white paper on the
proposed Standard Market Design in April 2003. We are reviewing the proposed
rulemaking and 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 in Arizona. Although some very limited retail
competition existed in APS' service area in 1999 and 2000, there are currently
no active retail competitors providing unbundled energy or other utility
services to APS' customers. As a result, we cannot predict when, and the extent
to which, additional competitors will re-enter APS' service territory. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete in the new
regulatory environment.

                                       99
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                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     4.   INCOME TAXES

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

     APS has recorded a regulatory asset related to income taxes on its Balance
Sheets in accordance with SFAS No. 71. This regulatory asset is for certain
temporary differences, primarily the allowance for equity funds used during
construction. APS amortizes this amount as the differences reverse. In
accordance with ACC settlement agreements, APS is continuing to accelerate
amortization of a regulatory asset related to income taxes over an eight-year
period that will end June 30, 2004 (see Note 1). Accordingly, we are including
this accelerated amortization in depreciation and amortization expense on our
Consolidated Statements of Income.

     As a result of a change in IRS guidance, we claimed a tax deduction related
to an APS tax accounting method change on the 2001 federal consolidated income
tax return. The accelerated deduction has resulted in a $200 million reduction
in the current income tax liability and a corresponding increase in the
plant-related deferred tax liability. In 2002, we received an income tax refund
of approximately $115 million related to our 2001 federal consolidated income
tax return.

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

                                                Year Ended December 31,
                                      -----------------------------------------
                                         2002            2001            2000
                                      ---------       ---------       ---------
Current:
  Federal                             $ (43,492)      $ 184,893       $ 189,779
  State                                 (14,732)         45,845          42,306
                                      ---------       ---------       ---------
Total current                           (58,224)        230,738         232,085

Deferred                                196,324         (17,203)        (37,885)
                                      ---------       ---------       ---------
Total income tax expense              $ 138,100       $ 213,535       $ 194,200
                                      =========       =========       =========

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

                                       100
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                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                                    Year Ended December 31,
                                              ----------------------------------
                                                2002         2001        2000
                                              ---------    ---------   ---------
Federal income tax expense at 35%
  statutory rate                              $ 123,639    $ 189,316   $ 173,786
Increases (reductions) in tax expense
  resulting from:
  State income tax net of federal income
    tax benefit                                  16,478       23,353      19,848
  Other                                          (2,017)         866         566
                                              ---------    ---------   ---------
Income tax expense                            $ 138,100    $ 213,535   $ 194,200
                                              =========    =========   =========

     The following table sets forth the net deferred income tax liability
recognized on the Consolidated Balance Sheets at December 31, 2002 and 2001
(dollars in thousands):

                                                             December 31,
                                                      -------------------------
                                                          2002          2001
                                                      -----------   -----------
Current asset/(liability)                             $     4,094   $    (3,244)
Long term liability                                    (1,209,074)   (1,064,993)
                                                      -----------   -----------
Accumulated deferred income taxes - net               $(1,204,980)  $(1,068,237)
                                                      ===========   ===========

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

                                                             December 31,
                                                      -------------------------
                                                          2002          2001
                                                      -----------   -----------
DEFERRED TAX ASSETS
  Pension liability                                   $    72,835   $    19,422
  Risk management and trading activities                   43,542        73,043
  Deferred gain on Palo Verde Unit 2 sale-leaseback        23,562        25,374
  Other                                                    99,054        90,580
                                                      -----------   -----------
Total deferred tax assets                                 238,993       208,419
                                                      -----------   -----------
DEFERRED TAX LIABILITIES
  Plant-related                                        (1,316,636)   (1,069,207)
  Regulatory asset for income taxes                       (80,635)     (121,757)
  Risk management and trading activities                  (46,702)      (85,692)
                                                      -----------   -----------
Total deferred tax liabilities                         (1,443,973)   (1,276,656)
                                                      -----------   -----------
Accumulated deferred income taxes - net               $(1,204,980)  $(1,068,237)
                                                      ===========   ===========

5.   LINES OF CREDIT AND SHORT-TERM BORROWINGS

     APS had committed lines of credit with various banks of $250 million at
December 31, 2002 and 2001, which were available either to support the issuance
of commercial paper or to be used for bank borrowings. These lines of credit

                                       101
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                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

mature in June 2003. The commitment fees at December 31, 2002 and 2001 for these
lines of credit were 0.09% per annum. APS had no bank borrowings outstanding
under these lines of credit at December 31, 2002 and 2001.

     APS had no commercial paper borrowings outstanding at December 31, 2002 and
$171 million at December 31, 2001. The weighted average interest rate on
commercial paper borrowings was 2.47% for the year ended December 31, 2002 and
4.72% for the year ended December 31, 2001. By Arizona statute, APS' short-term
borrowings cannot exceed 7% of its total capitalization unless approved by the
ACC.

     Pinnacle West had committed lines of credit of $475 million at December 31,
2002 and $250 million at December 31, 2001, which were available either to
support the issuance of commercial paper or to be used for bank borrowings.
Outstanding amounts at December 31, 2002 were $72 million, and there were no
short-term bank borrowings outstanding at December 31, 2001. The commitment fees
ranged from 0.10% to 0.15% in 2002 and 2001. Pinnacle West commercial paper
borrowings outstanding were $24 million at December 31, 2002 and $235 million at
December 31, 2001. The weighted average interest rate on commercial paper
borrowings was 2.06% for the year ended December 31, 2002 and 3.50% for the year
ended December 31, 2001.

     On July 31, 2002, Pinnacle West completed a $300 million bank credit
facility, which was subsequently reduced to $225 million by applying $75 million
of the proceeds from the equity offering in December 2002 (see Note 7). The
borrowings are LIBOR-based, can be drawn upon as needed and are expected to be
used primarily to fund Pinnacle West Energy capital requirements. The facility
matures in July 2003. The majority of these borrowings were used to fund
Pinnacle West Energy capital expenditures. At December 31, 2002, Pinnacle West
had borrowed $67 million under the credit facility.

     On November 22, 2002, the ACC approved APS' request to permit APS to (a)
make short-term advances to Pinnacle West in the form of an inter-affiliate line
of credit in the amount of $125 million, or (b) guarantee $125 million of
Pinnacle West's short-term debt, subject to certain conditions. This interim
loan matures in December 2003. There have been no borrowings on this line.

     SunCor had revolving lines of credit totaling $140 million at December 31,
2002 and 2001. The commitment fees were 0.125% in 2002 and 2001. SunCor had $126
million outstanding at December 31, 2002 and $128 million outstanding at
December 31, 2001. The balance is included in long-term debt on the Consolidated
Balance Sheets (see Note 6). SunCor had short-term loans in the amount of $6
million at December 31, 2002 and no short-term loans outstanding at December 31,
2001.

                                       102
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6.   LONG-TERM DEBT

     Borrowings under the APS mortgage bond indenture are secured by
substantially all utility plant. APS also has unsecured debt. SunCor's debt is
collateralized by interests in certain real property and Pinnacle West's debt is
unsecured. The following table presents the components of long-term debt on the
Consolidated Balance Sheets outstanding at December 31, 2002 and 2001 (dollars
in thousands):

                                       103
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                                      December 31,
                                             Maturity           Interest      ----------------------------
                                             Dates (a)            Rates           2002            2001
                                             ---------            -----       -----------      -----------
<S>                                            <C>                <C>         <C>              <C>
APS
First mortgage bonds                           2002               8.125%(b)   $        --      $   125,000
                                               2004               6.625%           80,000           80,000
                                               2023               7.25%            54,150           54,150
                                               2024               8.75%(c)             --          121,668
                                               2025               8.0%             33,075           33,075
                                               2028               5.5%             25,000           25,000
                                               2028               5.875%          154,000          154,000
Unamortized discount and premium                                                   (6,337)          (5,266)
Pollution control bonds                      2024-2034           (d)              386,860          386,860
Pollution control bonds                        2029               3.30%(e)             --           90,000
Pollution control bonds with senior
  notes (f)                                    2029               5.05%            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               --
Senior notes (g)                               2006               6.75%            83,695           83,695
Capitalized lease obligations                2003-2012            5.78%            20,400            1,343
                                                                              -----------      -----------
  Subtotal                                                                      2,220,843        2,074,525
                                                                              -----------      -----------
SUNCOR
Revolving credit                             2003-2004           (h)              125,500          128,000
Notes payable                                2003-2008           (i)                7,646            7,912
Bonds payable                                  2024               5.95%             5,090            5,215
Bonds payable                                  2026               6.75%             7,500            7,500
Capitalized lease obligations                2003-2007            8.91%             1,299               --
                                                                              -----------      -----------
  Subtotal                                                                        147,035          148,627
                                                                              -----------      -----------
PINNACLE WEST
Senior notes                                 2003-2006           (j)              540,000          325,000
Unamortized discount and premium                                                     (530)              --
Floating rate notes                            2003              (k)              250,000          250,000
Capitalized lease obligations                2004-2007            5.48%             1,999            1,066
                                                                              -----------      -----------
  Subtotal                                                                        791,469          576,066
                                                                              -----------      -----------
EL DORADO
Construction loan                              2005               1.77%             2,600               --
Capitalized lease obligations                2004-2005            7.04%               771               --
                                                                              -----------      -----------
  Subtotal                                                                          3,371               --
                                                                              -----------      -----------
Total long-term debt                                                            3,162,718        2,799,218
  Less current maturities                                                         281,023          126,140
                                                                              -----------      -----------
TOTAL LONG-TERM DEBT
  LESS CURRENT
  MATURITIES                                                                  $ 2,881,695      $ 2,673,078
                                                                              ===========      ===========
</TABLE>

                                       104
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(a)  This schedule does not reflect the timing of redemptions that may occur
     prior to maturity.
(b)  On March 15, 2002, APS redeemed at maturity $125 million of its First
     Mortgage Bonds, 8.125% Series due 2002.
(c)  On April 15, 2002, APS redeemed $122 million of its First Mortgage Bonds,
     8.75% Series due 2024.
(d)  The weighted-average rate was 1.94% at December 31, 2002 and 2.55% at
     December 31, 2001. Changes in short-term interest rates would affect the
     costs associated with this debt.
(e)  In November 2001, these bonds were converted to a one-year fixed rate of
     3.30%. These bonds were previously adjustable rate and, from January 1,
     2001 until October 31, 2001, the weighted average rate was 2.72%.
(f)  On November 1, 2002, Maricopa County, Arizona Pollution Control Corporation
     issued $90 million of 5.05% Pollution Control Revenue Refunding Bonds
     (Arizona Public Service Company Palo Verde Project) 2002 Series A, due
     2029, and loaned the proceeds to APS pursuant to a loan agreement. The
     bonds were issued to refinance $90 million of outstanding pollution control
     bonds. The bondholders were issued $90 million of first mortgage bonds
     (senior note mortgage bonds) as collateral.
(g)  APS currently has outstanding $84 million of first mortgage bonds (senior
     note mortgage bonds) issued to the senior note trustee as collateral for
     the senior notes, as well as the $90 million issue discussed in footnote
     (f) above. The senior note mortgage bonds have the same interest rate,
     interest payment dates, maturity and redemption provisions as the senior
     notes. APS' payments of principal, premium and/or interest on the senior
     notes satisfy its corresponding payment obligations on the senior note
     mortgage bonds. As long as the senior note mortgage bonds secure the senior
     notes, the senior notes will effectively rank equally with the first
     mortgage bonds. When APS repays all of its first mortgage bonds, other than
     those that secure senior notes, the senior note mortgage bonds will no
     longer secure the senior notes and will cease to be outstanding.
(h)  The weighted-average rate was 3.75% at December 31, 2002 and was 5.31% at
     December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus 2% or
     prime plus 0.5%.
(i)  Multiple notes primarily with variable interest rates based mostly on the
     lenders' prime plus 1.75% and lenders' prime plus .25%.
(j)  Includes three series of notes: $25 million at 6.87% due in 2003, $300
     million at 6.4% due in 2006 and $215 million at 4.5% due in 2004 as of
     December 31, 2002.
(k)  The weighted average rate was 2.85% at December 31, 2002 and was 4.65% at
     December 31, 2001. Interest for 2002 and 2001 was based on LIBOR plus
     0.98%.

     Pinnacle West's and APS' significant debt covenants related to their
respective financing arrangements include a debt-to-total-capitalization ratio
and an interest coverage test. Pinnacle West and APS are in compliance with such
covenants and each anticipates it will continue to meet all the significant
covenant requirement levels. Failure to comply with such covenant levels would
result in an event of default which, generally speaking, would require the
immediate repayment of the debt subject to the covenants.

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

                                       105
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     All of Pinnacle West's bank agreements contain "cross-default" provisions
under which a default by it or APS in a specified amount under another agreement
would result in a default and the potential acceleration of payment under the
agreements. All of APS' bank agreements contain cross-default provisions under
which a default by APS in a specified amount under another agreement would
result in a default and the potential acceleration of payment under the
agreements. Pinnacle West's and APS' credit agreements generally contain
provisions under which the lenders could refuse to advance loans in the event of
a material adverse change in the borrower's financial condition or financial
prospects.

     The following is a list of payments due on total long-term debt and
capitalized lease requirements through 2007:

     *    $281 million in 2003;
     *    $552 million in 2004;
     *    $405 million in 2005;
     *    $390 million in 2006;
     *    $3 million in 2007; and
     *    $1,539 million, thereafter.

     APS' first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel and transportation equipment and other
excluded assets). The mortgage bond indenture restricts the payment of common
stock dividends under certain conditions. APS may pay dividends on its common
stock if there is a sufficient amount "available" from retained earnings and the
excess of cumulative book depreciation (since the mortgage's inception) over
mortgage depreciation, which is the cumulative amount of additional property
pledged each year to address collateral depreciation. As of December 31, 2002,
the amount "available" under the mortgage would have allowed APS to pay
approximately $3 billion of dividends compared to APS' current annual common
stock dividends of $170 million.

7.   COMMON STOCK AND TREASURY STOCK

     Our common stock and treasury stock activity during each of the three years
2002, 2001 and 2000 is as follows (dollars in thousands, except shares):

                                       106
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                               COMMON STOCK                 TREASURY STOCK
                                         -------------------------     -------------------------
                                           SHARES        AMOUNT          SHARES        AMOUNT
                                         ----------    -----------     ----------    -----------
<S>                                      <C>           <C>             <C>           <C>
Balance at December 31, 1999             84,824,947    $ 1,540,197        (74,844)   $    (2,748)
  Purchase of treasury stock                                             (300,800)       (12,968)
  Reissuance of treasury stock
    for stock compensation (net)                                          266,006         10,627
  Other                                                     (2,277)
                                         ----------    -----------     ----------    -----------
Balance at December 31, 2000             84,824,947      1,537,920       (109,638)        (5,089)

  Purchase of treasury stock                                             (334,600)       (16,393)
  Reissuance of treasury stock
    for stock compensation (net)                                          342,931         15,596
  Other                                                       (996)
                                         ----------    -----------     ----------    -----------
Balance at December 31, 2001             84,824,947      1,536,924       (101,307)        (5,886)

  Common stock issuance -
    December 23, 2002                     6,555,000        199,238
  Purchase of treasury stock                                             (150,500)        (5,971)
  Reissuance of treasury stock
    for stock compensation (net)                                          126,977          7,499
  Other                                                      1,096
                                         ----------    -----------     ----------    -----------
Balance at December 31, 2002             91,379,947    $ 1,737,258       (124,830)   $    (4,358)
                                         ==========    ===========     ==========    ===========
</TABLE>

8.   RETIREMENT PLANS AND OTHER BENEFITS

PENSION PLANS

     Pinnacle West sponsors a qualified defined benefit pension plan and a
non-qualified supplemental excess benefit retirement plan for the employees of
Pinnacle West and our subsidiaries. Effective January 1, 2003, Pinnacle West
sponsored a new account balance pension plan for all new employees in place of
the defined benefit plan and, effective April 1, 2003, the new plan will be
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 plan
covers officers of the company and highly compensated employees designated for
participation by the Board of Directors. Our employees do not contribute to the
plans. Generally, we calculate the benefits based on age, years of service and
pay. We fund the qualified plan by contributing at least the minimum amount
required under IRS regulations but no more than the maximum tax-deductible
amount. The assets in the qualified plan at December 31, 2002 were mostly
domestic common stocks and bonds and real estate.

     Total pension expense, including administrative costs and after
consideration of amounts capitalized or billed to electric plant participants,
was:

     *    $14 million in 2002;
     *    $11 million in 2001; and

                                       107
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     *    $6 million in 2000.

     The following table shows the components of net periodic pension cost
before consideration of amounts capitalized or billed to electric plant
participants for the years ended December 31, 2002, 2001 and 2000 (dollars in
thousands):

<TABLE>
<CAPTION>
                                                          2002        2001        2000
                                                        --------    --------    --------
<S>                                                     <C>         <C>         <C>
Service cost - benefits earned during the period        $ 30,333    $ 27,640    $ 26,040
Interest cost on projected benefit obligation             71,242      66,549      61,625
Expected return on plan assets                           (75,652)    (77,340)    (77,231)
Amortization of:
  Transition asset                                        (3,227)     (3,227)     (3,227)
  Prior service cost                                       2,912       3,008       2,370
  Net actuarial loss/(gain)                                1,846         907      (1,190)
                                                        --------    --------    --------
Net periodic pension cost                               $ 27,454    $ 17,537    $  8,387
                                                        ========    ========    ========
</TABLE>

     The following table shows a reconciliation of the funded status of the
plans to the amounts recognized in the Consolidated Balance Sheets as of
December 31, 2002 and 2001 (dollars in thousands):

                                                           2002         2001
                                                        ----------    ---------
Funded status - pension plan assets less than
  projected benefit obligation                          $ (348,770)   $(166,773)
Unrecognized net transition asset                          (10,327)     (13,554)
Unrecognized prior service cost                             23,148       26,170
Unrecognized net actuarial losses                          293,223      108,422
                                                        ----------    ---------
Accrued pension benefit liability recognized in the
  Consolidated Balance Sheets                           $  (42,726)   $ (45,735)
                                                        ==========    =========

     The following table sets forth the defined benefit pension plans' change in
projected benefit obligation for the plan years 2002 and 2001 (dollars in
thousands):

                                                           2002          2001
                                                        ----------    ---------
Projected pension benefit obligation at
  beginning of year                                     $  931,646    $ 840,485
Service cost                                                30,333       27,640
Interest cost                                               71,242       66,549
Benefit payments                                           (35,230)     (33,282)
Actuarial losses                                            71,696       21,632
Plan amendments                                               (110)       8,622
                                                        ----------    ---------
Projected pension benefit obligation at end of year     $1,069,577    $ 931,646
                                                        ==========    =========

     The following table sets forth the qualified defined benefit pension plans'
change in the fair value of plan assets for the plan years 2002 and 2001
(dollars in thousands):

                                       108
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                                                            2002         2001
                                                         ---------    ---------
Fair value of pension plan assets at beginning of year   $ 764,873    $ 775,196
Actual loss on plan assets                                 (36,966)     (22,876)
Employer contributions                                      26,600       44,200
Benefit payments                                           (33,700)     (31,647)
                                                         ---------    ---------
Fair value of pension plan assets at end of year         $ 720,807    $ 764,873
                                                         =========    =========

     The following table sets forth the defined benefit pension plans' amounts
recognized in the Consolidated Balance Sheets at December 31, 2002 and 2001
(dollars in thousands):

                                                            2002         2001
                                                         ---------    ---------
Accrued pension benefit liability                        $ (42,726)   $ (45,735)
Additional minimum liability                              (141,155)      (3,297)
Intangible asset                                            23,148        1,697
Accumulated other comprehensive loss - pretax              118,007        1,600

     The following table shows the accumulated benefit obligation in relation to
the fair value of plan assets for the plan years 2002 and 2001 (dollars in
thousands):

                                                            2002         2001
                                                         ----------   ---------
Projected benefit obligation                             $1,069,577   $ 931,646
Accumulated benefit obligation                              904,687     752,230
Fair value of plan assets                                   720,807     764,873

     The following are weighted-average assumptions as of December 31, 2002 and
2001:

                                                            2002         2001
                                                         ----------   ---------
Discount rate                                                6.75%       7.50%
Rate of increase in compensation levels                      4.00%       4.00%
Expected long-term rate of return on assets                  9.00%      10.00%

EMPLOYEE SAVINGS PLAN BENEFITS

     Pinnacle West sponsors a defined contribution savings plan for the
employees of Pinnacle West and our subsidiaries. In a defined contribution
savings plan, the benefits a participant will receive result from regular
contributions they make to a participant account. Under this plan, we make
matching contributions in Pinnacle West stock to participant accounts. After a
five-year vesting period, participants have a choice to change the employer

                                       109
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

contribution match to other investments. At December 31, 2002, approximately 25%
of total plan assets were in Pinnacle West stock. We recorded expenses for this
plan of approximately $5 million for 2002 and 2001 and $4 million for 2000.

OTHER POSTRETIREMENT BENEFITS

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

     Funding is based upon actuarially determined contributions that take tax
consequences into account. Plan assets consist primarily of domestic stocks and
bonds. The other postretirement benefit expense, after consideration of amounts
capitalized or billed to electric plant participants, was:

     *    $12 million for 2002;
     *    $6 million for 2001; and
     *    $3 million for 2000.

     The following table shows the components of net periodic other
postretirement benefit costs before consideration of amounts capitalized or
billed to electric plant participants for the years ended December 31, 2002,
2001 and 2000 (dollars in thousands):

<TABLE>
<CAPTION>
                                                          2002        2001        2000
                                                        --------    --------    --------
<S>                                                     <C>         <C>         <C>
Service cost - benefits earned during the period        $ 12,036    $  9,438    $  8,613
Interest cost on accumulated benefit obligation           25,235      21,585      19,315
Expected return on plan assets                           (21,116)    (21,985)    (22,381)
Amortization of:
  Transition obligation                                    4,001       7,698       7,698
  Prior service credit                                       (75)         --          --
  Net actuarial loss/(gain)                                3,072      (4,066)     (7,983)
                                                        --------    --------    --------
Net periodic other postretirement benefit cost          $ 23,153    $ 12,670    $  5,262
                                                        ========    ========    ========
</TABLE>

     The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in the Consolidated Balance Sheets at December 31,
2002 and 2001 (dollars in thousands):

                                       110
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                       2002           2001
                                                                    ---------      ---------
<S>                                                                 <C>            <C>
Funded status - other postretirement plan assets less
  than accumulated other postretirement benefit obligation          $(186,400)     $ (80,544)
Unrecognized net obligation at transition                              36,489         84,748
Unrecognized prior service credit                                      (1,673)            --
Unrecognized net actuarial loss/(gain)                                148,268         (8,606)
                                                                    ---------      ---------
Net other postretirement benefit liability recognized in the
  Consolidated Balance Sheets                                       $  (3,316)     $  (4,402)
                                                                    =========      =========
</TABLE>

     The following table sets forth the other postretirement benefit plan's
change in accumulated postretirement benefit obligation for the plan years 2002
and 2001 (dollars in thousands):

<TABLE>
<CAPTION>
                                                                       2002           2001
                                                                    ---------      ---------
<S>                                                                 <C>            <C>
Accumulated other postretirement benefit obligation at
  beginning of year                                                 $ 318,355      $ 264,006
Service cost                                                           12,036          9,438
Interest cost                                                          25,235         21,585
Benefit payments                                                      (10,473)       (10,194)
Actuarial losses                                                      108,979         33,520
Plan amendments                                                       (44,258)(a)         --
                                                                    ---------      ---------
Accumulated other postretirement benefit obligation at
  end of year                                                       $ 409,874      $ 318,355
                                                                    =========      =========
</TABLE>

(a)  The plan was amended January 1, 2002 to increase the deductibles,
     out-of-pocket maximums and prescription drug co-pays. The plan was amended
     in June 2002 to increase the participants' portion of premiums.

     The following table sets forth the other postretirement benefit plan's
change in the fair value of plan assets for the plan years 2002 and 2001
(dollars in thousands):

                                                            2002         2001
                                                         ---------    ---------
Fair value of other postretirement benefit plan
  assets at beginning of year                            $ 237,810    $ 249,154
Actual loss on plan assets                                 (27,802)     (12,550)
Employer contributions                                      23,600       11,400
Benefit payments                                           (10,134)     (10,194)
                                                         ---------    ---------
Fair value of other postretirement benefit plan
  assets at end of year                                  $ 223,474    $ 237,810
                                                         =========    =========

                                       111
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The following are weighted-average assumptions as of December 31, 2002 and
2001:

                                                               2002       2001
                                                             -------    -------
Discount rate                                                  6.75%      7.50%
Expected long-term rate of return on assets - pretax           9.00%     10.00%
Expected long-term rate of return on assets - after tax        7.84%      8.71%
Initial health care cost trend rate - under age 65             8.00%      7.00%
Initial health care cost trend rate - age 65 and over          8.00%      7.00%
Ultimate health care cost trend rate                           5.00%      5.00%
Year ultimate health care trend rate is reached                2007       2006

     The following table shows the effect of a 1% increase or decrease in the
initial and ultimate health care expense and cost trend rate (dollars in
millions):

<TABLE>
<CAPTION>
                                                               1% increase      1% decrease
                                                               -----------      -----------
<S>                                                                <C>            <C>
Effect on the 2002 other postretirement benefit expense,
  after consideration of amounts capitalized or billed
  to electric plant participants                                   $  5            $ (4)
Effect on the 2002 service and interest cost components of
  net periodic other postretirement benefit costs                     7              (6)
Effect on the accumulated other postretirement benefit
  obligation at December 31, 2002                                    54             (43)
</TABLE>

SEVERANCE CHARGES

     In July 2002, we implemented a voluntary workforce reduction as part of our
cost reduction program. We recorded $36 million before taxes in voluntary
severance costs in 2002. No further charges are expected.

9.   LEASES

     In 1986, APS sold about 42% of its share of Palo Verde Unit 2 and certain
common facilities in three separate sale-leaseback transactions. APS accounts
for these leases as operating leases. The gain resulting from the transaction of
approximately $140 million was deferred and is being amortized to operations and
maintenance expense over 29.5 years, the original term of the leases. There are
options to renew the leases for two additional years and to purchase the
property for fair market value at the end of the lease terms. Consistent with
the ratemaking treatment, a regulatory asset is recognized for the difference
between lease payments and rent expense calculated on a straight-line basis. See
Note 20 for a discussion of VIEs, including the SPEs involved in the Palo Verde
sale-leaseback transactions.

                                       112
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     In addition, we lease certain land, buildings, equipment, vehicles and
miscellaneous other items through operating rental agreements with varying
terms, provisions and expiration dates.

     Total lease expense recognized in the Consolidated Statements of Income was
$62 million in 2002, $56 million in 2001 and $58 million in 2000.

     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, APS is continuing to accelerate amortization of the regulatory asset
for leases over an eight-year period that will end June 30, 2004 (see Note 1).
All regulatory asset amortization is included in depreciation and amortization
expense in the Consolidated Statements of Income. The balance of this regulatory
asset at December 31, 2002 was $14 million.

     Estimated future minimum lease payments for our operating leases are
approximately as follows (dollars in millions):

                           Year
                    ------------------
                           2003              $  70
                           2004                 66
                           2005                 64
                           2006                 63
                           2007                 63
                        Thereafter             478
                                             -----
                    Total future lease
                        commitments          $ 804
                                             =====

10.  JOINTLY-OWNED FACILITIES

     APS shares ownership of some of its generating and transmission facilities
with other companies. The following table shows APS' interest in those
jointly-owned facilities recorded on the Consolidated Balance Sheets at December
31, 2002. APS' share of operating and maintaining these facilities is included
in the Consolidated Statements of Income in operations and maintenance expense.

                                       113
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                       PERCENT                             CONSTRUCTION
                                                       OWNED BY           PLANT IN         ACCUMULATED         WORK IN
                                                         APS              SERVICE          DEPRECIATION        PROGRESS
                                                         ---              -------          ------------        --------
                                                                              (dollars in thousands)
<S>                                                   <C>               <C>                <C>                 <C>
Generating facilities:
  Palo Verde Nuclear Generating Station
    Units 1 and 3                                      29.1%             $1,829,225         $(905,278)          $17,428
  Palo Verde Nuclear Generating Station
    Unit 2 (see Note 9)                                17.0%                574,745          (289,049)           68,475
  Four Corners Steam Generating Station
    Units 4 and 5                                      15.0%                153,559           (82,434)              500
  Navajo Steam Generating Station
    Units 1, 2 and 3                                   14.0%                235,743          (110,923)            3,010
  Cholla Steam Generating Station
    Common Facilities (a)                              62.8%(b)              76,322           (42,608)            1,733
Transmission facilities:
  ANPP 500KV System                                    35.8%(b)              68,314           (25,655)               31
  Navajo Southern System                               31.4%(b)              27,129           (17,405)              664
  Palo Verde-Yuma 500KV System                         23.9%(b)               9,591            (4,168)              383
  Four Corners Switchyards                             27.5%(b)               3,071            (1,979)               --
  Phoenix-Mead System                                  17.1%(b)              36,418            (2,906)               --
  Palo Verde - Estrella 500KV System                   50.0%(b)                  --                --            50,450
</TABLE>

(a)  PacifiCorp owns Cholla Unit 4 and APS operates the unit for PacifiCorp. The
     common facilities at the Cholla Plant are jointly-owned.

(b)  Weighted average of interests.

11.  COMMITMENTS AND CONTINGENCIES

ENRON

     We recorded charges totaling $21 million before income taxes for exposure
to Enron and its affiliates in the fourth quarter of 2001. This amount is
comprised of a $15 million reserve for the Company's net exposure to Enron and
its affiliates and additional expenses of $6 million primarily related to 2002
power contracts with Enron that were canceled. These charges take into
consideration our rights of set-off with respect to the Enron related
contractual obligations. The APS portion of the write-off was $13 million. The
basis of the set-offs included, but was not limited to, provisions in the
various contractual arrangements with Enron and its affiliates, including an
International Swaps and Derivative Agreement (ISDA) between APS and Enron North
America. The write-off is also net of the expected recovery based on secondary
market quotes from the bond market. The amounts were written-off from the
balances of the related assets and liabilities from risk management and trading
activities on the Consolidated Balance Sheets.

PALO VERDE NUCLEAR GENERATING STATION

     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

                                       114
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

before 2010 and it does not intend to begin accepting spent nuclear fuel prior
to that date. In November 1997, the United States Court of Appeals for the
District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE
from excusing its own delay, but refused to order the DOE to begin accepting
spent nuclear fuel. Based on this decision and the DOE's delay, a number of
utilities filed damages actions against the DOE in the Court of Federal Claims.

     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.

     APS has existing fuel storage pools at Palo Verde and is in the process of
completing construction of a new facility for on-site dry storage of spent
nuclear fuel. With the existing storage pools and the addition of the new
facility, APS believes spent nuclear fuel storage or disposal methods will be
available for use by Palo Verde to allow its continued operation through the
term of the operating license for each Palo Verde unit.

     Although some low-level waste has been stored on-site in a low-level waste
facility, APS is currently shipping low-level waste to off-site facilities. APS
currently believes interim low-level waste storage methods are or will be
available for use by Palo Verde to allow its continued operation and to safely
store low-level waste until a permanent disposal facility is available.

     APS currently estimates it will incur $115 million (in 2002 dollars) over
the life of Palo Verde for its share of the costs related to the on-site interim
storage of spent nuclear fuel. As of December 31, 2002, APS had spent $2 million
and recorded accumulated spent nuclear fuel amortization of $44 million and a
regulatory asset of $46 million for on-site interim spent nuclear fuel storage
costs related to nuclear fuel burned to date.

     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 $200 million ($300 million
effective January 1, 2003) and the balance by an industry-wide retrospective
assessment program. If losses at any nuclear power plant covered by the programs
exceed the accumulated funds, APS could be assessed retrospective premium
adjustments. The maximum assessment per reactor under the program for each
nuclear incident is approximately $88 million, subject to an annual limit of $10
million per incident. Based on APS' interest in the three Palo Verde units, APS'
maximum potential assessment per incident for all three units is approximately
$77 million, with an annual payment limitation of approximately $9 million.

     The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. APS has also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of

                                       115
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.

PURCHASED POWER AND FUEL COMMITMENTS

     APS and Pinnacle West are parties to various purchased power and fuel
contracts with terms expiring from 2003 through 2025 that include required
purchase provisions. We estimate the contract requirements to be approximately
$173 million in 2003; $82 million in 2004; $28 million in 2005; $31 million in
2006; $17 million in 2007 and $162 million thereafter. However, these amounts
may vary significantly pursuant to certain provisions in such contracts that
permit us to decrease required purchases under certain circumstances.

     Of the various purchased power and fuel contracts mentioned above some of
those contracts have take-or-pay provisions. The contracts APS has for the
supply of its coal and nuclear fuel supply have take-or-pay provisions. The
current take-or-pay nuclear fuel contracts expire in 2003 and had not been
renewed as of December 31, 2002. The current take-or-pay coal contracts have
terms that expire in 2007.

     The following table summarizes the estimated take-or-pay commitments for
the existing terms (dollars in millions):

                                                     Estimated
                                              Years Ending December 31,
                                    --------------------------------------------
                                    2003      2004      2005      2006      2007
                                    ----      ----      ----      ----      ----
Coal                                $ 43      $ 44      $  9      $  9      $  9
Nuclear Fuel                          22        --        --        --        --
                                    ----      ----      ----      ----      ----
Total take-or-pay
  commitments (a)                   $ 65      $ 44      $  9      $  9      $  9
                                    ====      ====      ====      ====      ====

(a)  Total take-or-pay commitments are approximately $136 million. The total net
     present value of these commitments is approximately $119 million.

COAL MINE RECLAMATION OBLIGATIONS

     APS must reimburse certain coal providers for amounts incurred for coal
mine reclamation. Our coal mine reclamation obligation is about $59 million at
December 31, 2002 and is included in deferred credits-other in the Consolidated
Balance Sheets.

     A regulatory asset has been established for amounts not yet recovered from
ratepayers related to the coal obligations. In accordance with the 1999
Settlement Agreement with the ACC, APS is continuing to accelerate the
amortization of the regulatory asset for coal mine reclamation over an
eight-year period that will end June 30, 2004. Amortization is included in
depreciation and amortization expense on the Consolidated Statements of Income.

CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST

     In July 2001, the FERC ordered an expedited fact-finding hearing to
calculate refunds for spot market transactions in California during a specified
time frame. This order calls for a hearing, with findings of fact due to the
FERC after the ISO and PX provide necessary historical data. The FERC directed

                                       116
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

an ALJ to make findings of fact with respect to: (1) the mitigated price in each
hour of the refund period; (2) the amount of refunds owed by each supplier
according to the methodology established in the order; and (3) the amount
currently owed to each supplier (with separate quantities due from each entity)
by the CAISO, the California Power Exchange, the investor-owned utilities and
the State of California.

     APS was a seller and a purchaser in the California markets at issue, and to
the extent that refunds are ordered, APS should be a recipient as well as a
payor of such amounts. On December 12, 2002, the ALJ issued Proposed Findings of
Fact with respect to the refunds. On March 26, 2003, the FERC adopted the great
majority of the proposed findings, revising only the calculation of natural gas
prices for the final determination of mitigated prices in the California
markets. Sellers who may actually have paid more for natural gas than the proxy
prices adopted by the FERC have 40 days in which to submit necessary data to the
FERC, after which a technical conference will be held. Finalization of refund
amounts is expected in mid-2003. APS does not anticipate material changes in its
exposure and still believes, subject to the finalization of the revised proxy
prices, that it will be entitled to a net refund.

     On November 20, 2002, the FERC reopened discovery in these proceedings
pursuant to instructions of the United States Court of Appeals for the Ninth
Circuit, that the FERC permit parties to offer additional evidence of potential
market manipulation for the period January 1, 2000 through June 20, 2001.
Parties have submitted additional evidence and proposed findings, which the FERC
continues to consider.

     The FERC also ordered an evidentiary proceeding to discuss and evaluate
possible refunds for the Pacific Northwest. The FERC required that the record
establish the volume of the transactions, the identification of the net sellers
and net buyers, the price and terms and conditions of the sales contracts and
the extent of potential refunds. On September 24, 2001, an ALJ concluded that
prices in the Pacific Northwest during the period December 25, 2000 through June
20, 2001 were the result of a number of factors in addition to price signals
from the California markets, including the shortage of supply, excess demand,
drought and increased natural gas prices. Under these circumstances, the ALJ
ultimately concluded that the prices in the Pacific Northwest were not
unreasonable or unjust and refunds should not be ordered in this proceeding. The
FERC is currently reviewing the ALJ's report and recommendations.

     On December 19, 2002, the FERC opened a new discovery period to permit the
parties to offer additional evidence for the period January 1, 2000 through June
20, 2001. Additional evidence has been submitted and a FERC decision on the
newly submitted evidence is expected soon. Based on public comments from the
FERC, it is anticipated that this case will be sent back to the ALJ for further
proceedings on spot market and balance of month transactions.

     Although the FERC has not yet made a final ruling in the Pacific Northwest
matter nor 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.

                                      117
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     On March 26, 2003, FERC made public a Final Report on Price Manipulation in
Western Markets, prepared by its Staff and covering spot markets in the West in
2000 and 2001. The report stated that a significant number of entities who
participated in the California markets during 2000-2001 time period, including
APS, may potentially have been involved in arbitrage transactions that allegedly
violated certain provisions of the ISO tariff. The report also recommended that
the FERC issue an order to show cause why these transactions did not violate the
ISO tariff, with potential disgorgement of any unjust profits. Although APS has
not yet had an opportunity to review the transactions at issue, it believes that
it was not engaged in any such improper transactions. Based on the information
available, it also appears that such transactions would not have a material
adverse impact on our financial position, results of operations or liquidity.

     SCE and PG&E have publicly disclosed that their liquidity has been
materially and adversely affected because of, among other things, their
inability to pass on to ratepayers the prices each has paid for energy and
ancillary services procured through the PX and the ISO. PG&E filed for
bankruptcy protection in 2001.

     We are closely monitoring developments in the California energy market and
the potential impact of these developments on us and our subsidiaries. Based on
our evaluations, we previously reserved $10 million before income taxes for our
credit exposure related to the California energy situation, $5 million of which
was recorded in the fourth quarter of 2000 and $5 million of which was recorded
in the first quarter of 2001. Our evaluations took into consideration our range
of exposure of approximately zero to $38 million before income taxes and review
of likely recovery rates in bankruptcy situations.

     In the second quarter of 2002, PG&E filed its Modified Second Amended
Disclosure Statement and the CPUC filed its Alternative Plan of Reorganization.
Both plans generally indicated that PG&E would, at the close of bankruptcy
proceedings, be able to pay in full all outstanding, undisputed debts. As a
result of these developments, the probable range of our total exposure now is
approximately zero to $27 million before income taxes, and our best estimate of
the probable loss is now approximately $6 million before income taxes.
Consequently, we reversed $4 million of the $10 million reserve in the second
quarter of 2002. We cannot predict with certainty, however, the impact that any
future resolution or attempted resolution, of the California energy market
situation may have on us, our subsidiaries or the regional energy market in
general.

     CALIFORNIA ENERGY MARKET LITIGATION On March 19, 2002, the State of
California filed a complaint with the FERC alleging that wholesale sellers of
power and energy, including the Company, failed to properly file rate
information at the FERC in connection with sales to California from 2000 to the
present. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER EXCHANGE ET AL., Docket
No. EL02-71-000. The complaint requests the FERC to require the wholesale
sellers to refund any rates that are "found to exceed just and reasonable
levels." This complaint has been dismissed by the FERC and the State of
California is now appealing the matter to the Ninth Circuit Court of Appeals. In
addition, the State of California and others have filed various claims, which
have now been consolidated, against several power suppliers to California
alleging antitrust violations. WHOLESALE ELECTRICITY ANTITRUST CASES I AND II,
Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005
and 4204-00006. Two of the suppliers who were named as defendants in those
matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke
Energy and Trading, LLP (and other Duke entities), filed cross-claims against
various other participants in the PX and ISO markets, including APS, attempting

                                      118
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to expand those matters to such other participants. APS has not yet filed a
responsive pleading in the matter, but APS believes the claims by Reliant and
Duke as they relate to APS are without merit.

     APS was also named in a lawsuit regarding wholesale contracts in
California. JAMES MILLAR, ET AL. V. ALLEGHENY ENERGY SUPPLY, ET AL., United
States District Court in and for the District of Northern California, Case No.
C02-2855 EMC. The complaint alleges basically that the contracts entered into
were the result of an unfair and unreasonable market. The PX has filed a lawsuit
against the State of California regarding the seizure of forward contracts and
the State has filed a cross complaint against APS and numerous other PX
participants. CAL PX V. THE STATE OF CALIFORNIA Superior Court in and for the
County of Sacramento, JCCP No. 4203. Various preliminary motions are being filed
and we cannot currently predict the outcome of this matter. The "United States
Justice Foundation" is suing numerous wholesale energy contract suppliers to
California, including us, as well as the California Department of Water
Resources, based upon an alleged conflict of interest arising from the
activities of a consultant for Edison International who also negotiated
long-term contracts for the California Department of Water Resources.
MCCLINTOCK, ET AL. V. YUDHRAJA, Superior Court in and for the County of Los
Angeles, Case No. GC 029447. The California Attorney General has indicated that
an investigation by his office did not find evidence of improper conduct by the
consultant. We believe the claims against APS and us in the lawsuits mentioned
in this paragraph are without merit and will have no material adverse impact on
our financial position, results of operations or liquidity.

POWER SERVICE AGREEMENT

     By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised APS that it believes APS overcharged Citizens by over $50 million under
a power service agreement. APS believes its charges under the agreement were
fully in accordance with the terms of the agreement. In addition, in testimony
filed with the ACC on March 13, 2002, Citizens acknowledged, based on its
review, "if Citizens filed a complaint with FERC, it probably would lose the
central issue in the contract interpretation dispute." APS and Citizens
terminated the power service agreement effective July 15, 2001. In replacement
of the power service agreement, the Company and Citizens entered into a power
sale agreement under which the Company will supply Citizens with future
specified amounts of electricity and ancillary services through May 31, 2008.
This new agreement does not address issues previously raised by Citizens with
respect to charges under the original power service agreement through June 1,
2001.

CONSTRUCTION PROGRAM

     Consolidated capital expenditures in 2003 are estimated to be (dollars in
millions):

     APS                                            $ 401
     Pinnacle West Energy                             268
     SunCor                                            64
     Other (primarily APS Energy
       Services and Pinnacle West)                     17
                                                    -----
            Total                                   $ 750
                                                    =====

                                      119
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

PINNACLE WEST ENERGY'S GENERATION CONSTRUCTION

     Pinnacle West Energy's generation construction plan is as follows:

     *    A 650 MW combined cycle expansion of the West Phoenix Power Plant in
          Phoenix. The 120 MW West Phoenix Unit 4 began commercial operation in
          June 2001. Construction has begun on the 530 MW West Phoenix Unit 5,
          with commercial operation expected to begin in mid-2003.

     *    The Redhawk Power Plant, two 530 MW combined cycle units, near Palo
          Verde. Commercial operation began in July 2002. Based on an analysis
          of the financial situation of the Company and the market as a whole,
          among other things, Pinnacle West has cancelled plans to construct the
          additional two 530 MW combined cycle units, Redhawk Units 3 and 4. As
          a result we recorded a pretax charge of approximately $49 million in
          December 2002.

     *    The construction of an 80 MW simple-cycle power plant at Saguaro in
          Southern Arizona. Commercial operation began in July 2002.

     *    Development of the 570 MW Silverhawk combined-cycle plant 20 miles
          north of Las Vegas, Nevada. Construction of the plant began in August
          2002, with an expected commercial operation date of mid-2004. Pinnacle
          West Energy has signed an agreement with Las Vegas-based SNWA under
          which SNWA has an option to purchase a 25% interest in the project for
          approximately $100 million.

     *    A Pinnacle West Energy affiliate is exploring the possibility of
          creating an underground natural gas storage facility on Company-owned
          land west of Phoenix. An analysis to determine the feasibility of the
          project is in progress.

LITIGATION

     We are party to various 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 ADEQ issues. In our
opinion, the ultimate resolution of these matters will not have a material
adverse effect on our consolidated financial statements, results of operations
or liquidity.

12.  NUCLEAR DECOMMISSIONING COSTS

     APS recorded $11 million for nuclear decommissioning expense in each of the
years 2002, 2001 and 2000. APS estimates it will cost approximately $1.8 billion
($528 million in 2002 dollars) to decommission its share of the three Palo Verde
units. The majority of decommissioning costs are expected to be incurred over a
14-year period beginning in 2024. APS charges decommissioning costs to expense
over each unit's operating license term and APS includes them in the accumulated
depreciation balance until each unit is retired. Nuclear decommissioning costs
are recovered in rates.

                                       120
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     APS' current estimates are based on a 2001 site-specific study for Palo
Verde that assumes the prompt removal/dismantlement method of decommissioning.
An independent consultant prepared this study. APS is required by the ACC to
update the study every three years.

     To fund the costs APS expects to incur to decommission the plant, APS
established external decommissioning trusts in accordance with NRC regulations
and ACC orders. APS invests the trust funds primarily in fixed income securities
and domestic stock and classifies them as available for sale. Realized and
unrealized gains and losses are reflected in accumulated depreciation in
accordance with industry practice. The following table shows the cost and fair
value of our nuclear decommissioning trust fund assets, which were reported in
investments and other assets on the Consolidated Balance Sheets at December 31,
2002 and 2001 (dollars in millions):

                                                 2002          2001
                                                -----         -----
     Trust fund assets - at cost:
       Fixed income securities                  $ 113         $ 103
       Domestic stock                              68            61
                                                -----         -----
     Total                                      $ 181         $ 164
                                                =====         =====

     Trust fund assets - fair value:
       Fixed income securities                  $ 117         $ 106
       Domestic stock                              77            96
                                                -----         -----
     Total                                      $ 194         $ 202
                                                =====         =====

     See Note 2 for information on a new accounting standard on accounting for
certain liabilities related to closure or removal of long-lived assets.

                                       121
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

13.  SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

     Consolidated quarterly financial information for 2002 and 2001 is as
follows:

<TABLE>
<CAPTION>
                                           (dollars in thousands, except per share amounts)
                                                               2002
                                     -------------------------------------------------------------
QUARTER ENDED                        March 31         June 30       September 30   December 31 (a)
                                     --------         -------       ------------   ---------------
<S>                                  <C>             <C>             <C>             <C>
Operating revenues (b)
  Regulated electricity segment      $ 380,241       $ 496,837       $ 719,361       $ 416,584
  Marketing and trading
    segment                             75,815          49,503          87,258         113,355
  Real estate segment                   41,185          69,152          45,108          80,943
  Other revenues (c)                     4,277           2,881          21,224          33,555
Operating income                     $ 119,438       $ 166,706       $ 213,025       $  16,878
Income (loss) before accounting
  change                             $  53,757       $  75,365       $ 100,916       $ (14,885)

Cumulative effect of change in
  accounting - net of income tax            --              --              --         (65,745)
                                     ---------       ---------       ---------       ---------
Net income (loss)                    $  53,757       $  75,365       $ 100,916       $ (80,630)
                                     =========       =========       =========       =========
Earnings (loss) per weighted
  average common share
  outstanding - basic:
  Income before accounting
    change                           $    0.63       $    0.89       $    1.19       $   (0.18)
  Cumulative effect of change
    in accounting                           --              --              --           (0.77)
                                     ---------       ---------       ---------       ---------
Earnings per weighted average
  common share outstanding -
  basic                              $    0.63       $    0.89       $    1.19       $   (0.95)
                                     =========       =========       =========       =========
Earnings (loss) per weighted
  average common share
  outstanding - diluted:
  Income before accounting
    change                           $    0.63       $    0.89       $    1.19       $   (0.18)
  Cumulative effect of change
    in accounting                           --              --              --           (0.77)
                                     ---------       ---------       ---------       ---------
Earnings per weighted average
  common share outstanding -
  diluted                            $    0.63       $    0.89       $    1.19       $   (0.95)
                                     =========       =========       =========       =========

Dividends declared per share         $    0.40       $    0.40       $    0.40       $   0.425
</TABLE>

                                       122
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                          (dollars in thousands, except per share amounts)
                                                              2001
                                     ----------------------------------------------------------
QUARTER ENDED                        March 31         June 30       September 30   December 31
                                     --------         -------       ------------   ------------
<S>                                  <C>             <C>             <C>             <C>
Operating revenues (b)
  Regulated electricity segment      $ 412,807       $ 739,317       $ 973,398        $ 436,569
  Marketing and trading
    segment                            258,296         233,841         141,674           17,419
  Real estate segment                   32,335          32,454          43,024           61,095
  Other revenues                         1,543           1,653           2,682            5,893
Operating income                     $ 136,646       $ 140,010       $ 298,752        $ 100,615
Income before accounting
  change                             $  62,205       $  66,857       $ 162,499        $  35,806

Cumulative effect of change in
  accounting - net of income tax        (2,755)             --         (12,446)              --
                                     ---------       ---------       ---------        ---------
Net income                           $  59,450       $  66,857       $ 150,053        $  35,806
                                     =========       =========       =========        =========
Earnings (loss) per weighted
  average common share
  outstanding - basic:
  Income before accounting
    change                           $    0.73       $    0.79       $    1.92        $    0.42
  Cumulative effect of change
    in accounting                        (0.03)             --           (0.15)              --
                                     ---------       ---------       ---------        ---------
Earnings per weighted average
  common share outstanding -
  basic                              $    0.70       $    0.79       $    1.77        $    0.42
                                     =========       =========       =========        =========
Earnings (loss) per weighted
  average common share
  outstanding - diluted:
  Income before accounting
    change                           $    0.73       $    0.79       $    1.91        $    0.42
  Cumulative effect of change
    in accounting                        (0.03)             --           (0.14)              --
                                     ---------       ---------       ---------        ---------
Earnings per weighted average
  common share outstanding -
  diluted                            $    0.70       $    0.79       $    1.77        $    0.42
                                     =========       =========       =========        =========
Dividends declared per share         $   0.375       $   0.375       $   0.375        $    0.40
</TABLE>

(a)  The fourth quarter of 2002 included pretax losses of $38 million related to
     our investment in NAC (see Note 22), a $49 million pretax write-off related
     to the cancellation of Redhawk Units 3 and 4 and pretax severance costs of
     approximately $11 million.

                                       123
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(b)  Electric revenues are seasonal in nature, with the peak sales periods
     generally occurring during the summer months. Comparisons among quarters of
     a year may not represent overall trends and changes in operations. We have
     reclassified certain operating revenues to conform to the current
     presentation of netting energy trading contracts (see Note 18).
(c)  NAC financial statements were fully consolidated starting in third quarter
     2002 (see Note 22).

14.  FAIR VALUE OF FINANCIAL INSTRUMENTS

     We believe that the carrying amounts of our cash equivalents and commercial
paper are reasonable estimates of their fair values at December 31, 2002 and
2001 due to their short maturities.

     We hold investments in debt and equity securities for purposes other than
trading. The December 31, 2002 and 2001 fair values of such investments, which
we determine by using quoted market prices, approximate their carrying amount.

     On December 31, 2002, the carrying value of our long-term debt (excluding
capitalized lease obligations) was $3.15 billion, with an estimated fair value
of $3.25 billion. The carrying value of our long-term debt (excluding
capitalized lease obligations) was $2.80 billion on December 31, 2001, with an
estimated fair value of $2.82 billion. The fair value estimates are based on
quoted market prices of the same or similar issues.

15.  EARNINGS PER SHARE

     The following table presents earnings per weighted average common share
outstanding for the years ended December 31, 2002, 2001 and 2000:

                                              2002          2001          2000
                                            --------      --------      --------
Basic earnings per share:
  Income before accounting
    change                                  $   2.53      $   3.86      $   3.57
  Cumulative effect of change in
    accounting                                 (0.77)        (0.18)           --
                                            --------      --------      --------
Earnings per share-basic                    $   1.76      $   3.68      $   3.57
                                            ========      ========      ========
Diluted earnings per share:
  Income before accounting
    change                                  $   2.53      $   3.85      $   3.56
  Cumulative effect of change in
    accounting                                 (0.77)        (0.17)           --
                                            --------      --------      --------
Earnings per share-diluted                  $   1.76      $   3.68      $   3.56
                                            ========      ========      ========

     Dilutive stock options increased average common shares outstanding by
60,975 shares in 2002, 212,491 shares in 2001 and 202,738 shares in 2000. Total
average common shares outstanding for the purposes of calculating diluted
earnings per share were 84,963,921 shares in 2002, 84,930,140 shares in 2001 and
84,935,282 shares in 2000.

                                       124
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Options to purchase 1,629,958 shares of common stock were outstanding at
December 31, 2002 but were not included in the computation of diluted earnings
per share because the options' exercise price was greater than the average
market price of the common shares. Options to purchase shares of common stock
that were not included in the computation of diluted earnings per share were
212,562 at December 31, 2001 and 517,614 at December 31, 2000.

16.  STOCK-BASED COMPENSATION

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

     In May 2002, shareholders approved the 2002 Long-term Incentive Plan (2002
plan), which allows Pinnacle West to grant performance shares, stock ownership
incentive awards and non-qualified and performance-accelerated stock options to
key employees. The Company has reserved 6 million shares of common stock for
issuance under the 2002 plan. No more than 1.8 million shares may be issued in
relation to performance share awards and stock ownership incentive awards. The
plan also provides for the granting of new non-qualified stock options at a
price per option 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 provides for the granting of new options (which may be
non-qualified stock options or incentive stock options) of up to 3.5 million
shares at a price per option not less than the fair market value on the date the
option is granted. The 1985 plan includes outstanding options but no new options
will be granted from the 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 provides for the granting of any
combination of shares of restricted stock, stock appreciation rights or dividend
equivalents.

     In the third quarter of 2002, we began applying the fair value method of
accounting for stock-based compensation, as provided for in SFAS No. 123. The
fair value method of accounting is the preferred method. In accordance with the
transition requirements of SFAS No. 123, we applied the fair value method
prospectively, beginning with 2002 stock grants. In prior years, we recognized
stock compensation expense based on the intrinsic value method allowed in APB
No. 25. We recorded approximately $500,000 in stock option expense before income
taxes in our Consolidated Statements of Income 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.

                                       125
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Total stock-based compensation expense, including stock option expense, was
$5 million in 2002, $3 million in 2001 and $2 million in 2000.

     The following table is a summary of the status of our stock option plans as
of December 31, 2002, 2001 and 2000 and changes during the years ending on those
dates:

<TABLE>
<CAPTION>
                                              2002                        2001                         2000
                                            Weighted                    Weighted                     Weighted
                                            Average                     Average                      Average
                             2002           Exercise         2001       Exercise         2000        Exercise
                            Shares           Price          Shares       Price          Shares        Price
                          ----------        --------      ----------    --------      ----------     --------
<S>                        <C>                <C>          <C>            <C>          <C>             <C>
Outstanding at
  beginning of
  year                     1,832,725         $39.52        1,569,171     $37.55        1,441,124      $33.45
Granted                      603,900 (a)      38.37          444,200      42.55          451,450       43.28
Exercised                   (163,381)         28.25         (162,229)     28.53         (283,819)      20.90
Forfeited                    (88,115)         41.54          (18,417)     41.67          (39,584)      39.86
                          ----------                      ----------                  ----------
Outstanding at end
  of year                  2,185,129          39.96        1,832,725      39.52        1,569,171       37.55
                          ==========                      ==========                  ==========
Options
  exercisable
  at year-end              1,155,357          39.66          926,315      37.41          831,537       34.37
                          ==========                      ==========                  ==========
Weighted average
  fair value of
  options granted
  during the year                              6.16                        8.84                        11.81
</TABLE>

(a)  Beginning 2002, we recorded compensation expense related to stock options
     under SFAS No. 123 (see above discussion).

     The following table summarizes information about our stock options at
December 31, 2002:

<TABLE>
<CAPTION>
                                                Weighted     Weighted Average                     Weighted
                                                Average         Remaining                         Average
   Exercise                 Options             Exercise         Contract           Options       Exercise
Prices Per Share          Outstanding            Price         Life (Years)       Exercisable      Price
----------------          -----------            -----         ------------       -----------      -----
<S>                        <C>                  <C>               <C>             <C>             <C>
 $18.71 - 23.39               50,584            $ 20.73            1.3                50,584      $ 20.73
  23.39 - 28.07               48,417              27.40            3.4                41,750        27.44
  28.07 - 32.75               46,000              31.44            3.9                46,000        31.44
  32.75 - 37.42              235,160              34.70            6.7               235,160        34.70
  37.42 - 42.10              779,700              38.85            8.3               181,900        40.01
  42.10 - 46.78            1,025,268              43.95            7.7               599,963        44.59
                          ----------                                              ----------
                           2,185,129                                               1,155,357
                          ==========                                              ==========
</TABLE>

                                       126
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     The following table is a summary of the amount and weighted-average grant
date fair value of stock compensation awards granted, other than options, during
the years ended December 31, 2002, 2001 and 2000:

<TABLE>
<CAPTION>
                                        2002                   2001                   2000
                                      Weighted               Weighted               Weighted
                                      Average                Average                Average
                            2002     Grant-Date    2001     Grant-Date    2000     Grant-Date
                           Shares    Fair Value   Shares    Fair Value   Shares    Fair Value
                           ------    ----------   ------    ----------   ------    ----------
<S>                          <C>       <C>         <C>        <C>         <C>        <C>
Restricted stock             6,000     $38.84      95,450     $42.84      86,426     $44.03
Performance share
  awards                   115,975      38.37          --         --          --         --
Stock ownership
  incentive awards (a)       9,650      38.37          --         --          --         --
</TABLE>

(a)  Shares are based on estimated ownership of Pinnacle West common stock.

17.  BUSINESS SEGMENTS

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

     *    our regulated electricity segment, which consists of regulated
          traditional retail and wholesale electricity businesses and related
          activities, and includes electricity transmission, distribution and
          generation;
     *    our marketing and trading segment, which consists of our competitive
          business activities, including wholesale marketing and trading and APS
          Energy Services' commodity-related energy services; and
     *    our real estate segment, which consists of SunCor's real estate
          development and investment activities.

     The amounts in our other segment include activity principally related to
NAC in 2002 (see Note 22), as well as the parent company and other subsidiaries.
Financial data for the years ended December 31, 2002, 2001 and 2000 by business
segments is provided as follows (dollars in millions):

                                       127
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                               Business Segments for the Year Ended December 31, 2002
                                           -------------------------------------------------------------
                                                         Marketing                   Other
                                            Regulated       and                  (principally
                                           Electricity    Trading    Real Estate      NAC)        Total
                                           -----------    -------    -----------    -------      -------
<S>                                          <C>          <C>          <C>          <C>          <C>
Operating revenues                           $ 2,013      $   326      $   236      $    62      $ 2,637
Purchased power and fuel costs                   500          194           --           --          694
Other operating expenses                         659           34          205          105        1,003
                                             -------      -------      -------      -------      -------
  Operating margin                               854           98           31          (43)         940
Depreciation and amortization                    416            2            5            2          425
Interest and other expense                       160           --           (5)           8          163
                                             -------      -------      -------      -------      -------
  Pretax margin                                  278           96           31          (53)         352
Income taxes                                     108           38           12          (21)         137
                                             -------      -------      -------      -------      -------
Income (loss) before accounting
  change                                         170           58           19          (32)         215
Cumulative effect of change in
  accounting for trading activities
  - net of income taxes of $43                    --          (66)          --           --          (66)
                                             -------      -------      -------      -------      -------
Net income(loss)                             $   170      $    (8)     $    19      $   (32)     $   149
                                             =======      =======      =======      =======      =======
Total assets                                 $ 7,589      $   301      $   504      $    32      $ 8,426
                                             =======      =======      =======      =======      =======
Capital expenditures                         $   893      $    19      $    72      $    --      $   984
                                             =======      =======      =======      =======      =======


                                               Business Segments for the Year Ended December 31, 2001
                                           -------------------------------------------------------------
                                                         Marketing
                                            Regulated       and
                                           Electricity    Trading    Real Estate     Other        Total
                                           -----------    -------    -----------    -------      -------
Operating revenues                           $ 2,562      $   651      $   169      $    12      $ 3,394
Purchased power and fuel costs                 1,161          334           --           --        1,495
Other operating expenses                         598           33          154           11          796
                                             -------      -------      -------      -------      -------
  Operating margin                               803          284           15            1        1,103
Depreciation and amortization                    423            1            4           --          428
Interest and other expense                       129           --            6           --          135
                                             -------      -------      -------      -------      -------
  Pretax margin                                  251          283            5            1          540
Income taxes                                      99          112            2           --          213
                                             -------      -------      -------      -------      -------
Income before accounting change                  152          171            3            1          327
Cumulative effect of change in
  accounting for derivatives - net
  of income taxes of $10                         (15)          --           --           --          (15)
                                             -------      -------      -------      -------      -------
Net income                                   $   137      $   171      $     3      $     1      $   312
                                             =======      =======      =======      =======      =======
Total assets                                 $ 6,862      $   589      $   477      $    11      $ 7,939
                                             =======      =======      =======      =======      =======
Capital expenditures                         $ 1,004      $    23      $    80      $    22      $ 1,129
                                             =======      =======      =======      =======      =======
</TABLE>

                                       128
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                               Business Segments for the Year Ended December 31, 2000
                                           -------------------------------------------------------------
                                                         Marketing
                                            Regulated       and
                                           Electricity    Trading    Real Estate     Other        Total
                                           -----------    -------    -----------    -------      -------
<S>                                          <C>          <C>          <C>          <C>          <C>
Operating revenues                           $ 2,539      $   418      $   158      $     4      $ 3,119
Purchased power and fuel costs                 1,066          292           --           --        1,358
Other operating expenses                         532           18          134            1          685
                                             -------      -------      -------      -------      -------
  Operating margin                               941          108           24            3        1,076
Depreciation and amortization                    426            1            5           --          432
Interest and other expense                       152           --           --           (4)         148
                                             -------      -------      -------      -------      -------
Pretax margin                                    363          107           19            7          496
Income taxes                                     142           42            8            2          194
                                             -------      -------      -------      -------      -------
   Net income                                $   221      $    65      $    11      $     5      $   302
                                             =======      =======      =======      =======      =======
Total assets                                 $ 6,213      $   459      $   429      $    22      $ 7,123
                                             =======      =======      =======      =======      =======
Capital expenditures                         $   665      $    --      $    50      $    --      $   715
                                             =======      =======      =======      =======      =======
</TABLE>

18.  DERIVATIVE AND TRADING ACCOUNTING

     We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We manage risks associated with these market fluctuations by utilizing various
commodity derivatives, including exchange-traded futures and options and
over-the-counter forwards, options and swaps. As part of our overall risk
management program, we enter into derivative transactions to hedge purchases and
sales of electricity, fuels, and emissions allowances and credits. The changes
in market value of such contracts have a high correlation to price changes in
the hedged 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). 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. See Note 1 for further discussion on our derivative
instrument accounting policy.

     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), 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.

                                       129
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     In December 2001, the FASB issued revised guidance on the accounting for
electricity contracts with option characteristics and the accounting for
contracts that combine a forward contract and a purchased option contract. The
effective date for the revised guidance was April 1, 2002. The impact of this
guidance was immaterial to our financial statements.

     During 2002, the EITF discussed EITF 02-3 and reached a consensus on
certain issues. EITF 02-3 rescinded EITF 98-10 and was effective October 25,
2002 for any new contracts, and on January 1, 2003 for existing contracts, with
early adoption permitted. We adopted the EITF 02-3 guidance for all contracts in
the fourth quarter of 2002. We recorded a $66 million after-tax charge in net
income as a cumulative effect adjustment for the previously recorded accumulated
unrealized mark-to-market on energy trading contracts that did not meet the
accounting definition of a derivative. As a result, our energy trading contracts
that are derivatives continue to be accounted for at fair value under SFAS No.
133. Contracts that were previously marked-to-market as trading activities under
EITF 98-10 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. Additionally, all gains
and losses (realized and unrealized) on energy trading contracts that qualify as
derivatives are included in marketing and trading segment revenues on the
Consolidated Statements of Income on a net basis. The rescission of EITF 98-10
has no effect on the accounting for derivative instruments used for non-trading
activities, which continue to be accounted for in accordance with SFAS No. 133.

     Both non-trading and trading derivatives are classified as assets and
liabilities from risk management and trading activities in the Consolidated
Balance Sheets. For non-trading derivative instruments that qualify for cash
flow hedge accounting treatment, changes in the fair value of the effective
portion are recognized in common stock equity (as a component of accumulated
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.

     Derivatives associated with trading activities are adjusted to fair value
through income. 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. Most 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.

     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. Conversely, all non-trading contracts and derivatives are to be reported
gross in the income statement. Previous guidance under EITF 98-10 permitted
non-financially settled energy trading contracts to be reported either gross or
net in the income statement. Beginning in the third quarter of 2002, we netted
all of our energy trading activities on the Consolidated Statements of Income
and restated prior year amounts for all periods presented. Reclassification of
such trading activity to a net basis of reporting resulted in reductions in both
revenues and purchased power and fuel costs, but did not have any impact on our
financial condition, results of operations or cash flows.

                                       130
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     Our assets and liabilities from risk management and trading activities are
presented in two categories consistent with our business segments:

     *    System - our regulated electricity business segment, which consists of
          non-trading derivative instruments that hedge our purchases and sales
          of electricity and fuel for our Native Load requirements; and

     *    Marketing and Trading - our non-regulated, competitive business
          segment, which includes both non-trading and trading derivative
          instruments.

     The changes in derivative fair value included in the Consolidated
Statements of Income for the years ended December 31, 2002 and 2001 are
comprised of the following (dollars in thousands):

                                                          2002           2001
                                                        --------       --------
Gains/(losses) on the ineffective portion of
  derivatives qualifying for hedge
   accounting (a)                                       $ 11,198       $ (6,056)
Losses from the discontinuance of
  cash flow hedges                                        (8,820)        (4,683)
Losses from non-hedge derivatives                         (4,324)        (7,157)
Prior period mark-to-market losses realized
  upon delivery of commodities                             8,005         25,948
                                                        --------       --------
Total pretax gain                                       $  6,059       $  8,052
                                                        ========       ========

(a)  Time value component of options excluded from assessment of hedge
     effectiveness.

     As of December 31, 2002, the maximum length of time over which we are
hedging our exposure to the variability in future cash flows for forecasted
transactions is approximately seven years. During the twelve months ending
December 31, 2003, we estimate that a net loss of $26 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.

     The following table summarizes our assets and liabilities from risk
management and trading activities related to system and marketing and trading at
December 31, 2002 and 2001 (dollars in thousands):

                                       131
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
December 31, 2002
                            Current                      Current         Other       Net Asset/
                            Assets      Investments    Liabilities    Liabilities    (Liability)
                           ---------     ---------      ---------      ---------      ---------
<S>                        <C>           <C>            <C>            <C>            <C>
Mark-to-
  market:
    Marketing
      and Trading          $  17,640     $  51,771      $  (9,848)     $  (2,583)     $  56,980
    System                    41,522         6,971        (60,819)       (36,678)       (49,004)
Emission
  allowances
  - at cost                       --        58,067             --        (14,328)        43,739
Collateral
  provided (held)                 --         5,527             --        (22,053)       (16,526)
                           ---------     ---------      ---------      ---------      ---------
Total                      $  59,162     $ 122,336      $ (70,667)     $ (75,642)     $  35,189
                           =========     =========      =========      =========      =========

December 31, 2001

                            Current                      Current         Other       Net Asset/
                            Assets      Investments    Liabilities    Liabilities    (Liability)
                           ---------     ---------      ---------      ---------      ---------
Mark-to-
  market:
    Marketing
      and Trading          $  56,876     $ 148,457      $ (14,154)     $ (53,253)     $ 137,926
    System                    10,097            --        (21,840)       (95,159)      (106,902)
Emission
  allowances
  - at cost                       --        (3,216)            --        (59,164)       (62,380)
Collateral
  provided                        --        55,110             --             --         55,110
                           ---------     ---------      ---------      ---------      ---------
Total                      $  66,973     $ 200,351      $ (35,994)     $(207,576)     $  23,754
                           =========     =========      =========      =========      =========
</TABLE>

     CREDIT RISK

     We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We have risk management and trading contracts with many
counterparties, including two counterparties for which a worst case exposure
represents approximately 33% of our $181 million of risk management and trading
assets as of December 31, 2002. We use a risk management process to assess and
monitor the financial exposure of those and all other counterparties. Despite
the fact that the great majority of trading counterparties are rated as
investment grade by the credit rating agencies, including the counterparties
noted above, there is still a possibility that one or more of these companies
could default, resulting in a material impact on consolidated earnings for a
given period. Counterparties in the portfolio consist principally of major
energy companies, municipalities and local distribution companies. We maintain
credit policies that we believe minimize overall credit risk to within
acceptable limits. Determination of the credit quality of our counterparties is
based upon a number of factors, including credit ratings and our evaluation of
their financial condition. In many contracts, we employ collateral requirements
and standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Credit valuation adjustments

                                       132
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

are established representing our estimated credit losses on our overall exposure
to counterparties. See "Mark-to-Market Accounting" in Note 1 for a discussion of
our credit valuation adjustment policy.

19.  OTHER INCOME AND OTHER EXPENSE

     The following table provides detail of other income and other expense for
the years ended December 31, 2002, 2001 and 2000 (dollars in thousands):

                                                 Year Ended December 31,
                                           ------------------------------------
                                             2002          2001          2000
                                           --------      --------      --------
Other income:
  Environmental insurance
    recovery                               $     --      $ 12,349      $     --
   Equity earnings - net                         --            --         6,882
  Interest income                             4,410         6,763         8,291
  SunCor joint venture earnings               7,471         3,687         3,208
  Miscellaneous                               3,223         3,617         3,451
                                           --------      --------      --------
Total other income                         $ 15,104      $ 26,416      $ 21,832
                                           ========      ========      ========
Other expense:
  Equity losses - net (a)                  $(10,439)     $ (5,126)     $     --
  Non-operating costs - SunCor                   --        (7,000)           --
  Non-operating costs (b)                   (19,430)      (16,807)      (16,044)
  Miscellaneous                              (3,786)       (4,644)       (9,285)
                                           --------      --------      --------
Total other expense                        $(33,655)     $(33,577)     $(25,329)
                                           ========      ========      ========

(a)  Primarily related to El Dorado's investment losses in NAC prior to
     consolidation in the third quarter of 2002 (see Note 22).

(b)  As defined by the FERC, includes below-the-line non-operating utility costs
     (primarily community relations and environmental compliance).

20.  VARIABLE INTEREST ENTITIES

     In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities." FIN No. 46 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.
FIN No. 46 is effective immediately for any VIE created after January 31, 2003
and is effective July 1, 2003 for VIEs created before February 1, 2003.

     In 1986, APS entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. See Note 9 for
further information about the sale-leaseback transactions. Based on our
preliminary assessment of FIN No. 46, we do not believe we will be required to

                                       133
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

consolidate the Palo Verde SPEs. However, we continue to evaluate the
requirements of the new guidance to determine what impact, if any, it will have
on our financial statements.

     APS is also exposed to losses under the Palo Verde sale-leaseback
agreements upon the occurrence of certain events that APS does not consider to
be reasonably likely to occur. Under certain circumstances (for example, the NRC
issuing specified violation orders with respect to Palo Verde or the occurrence
of specified nuclear events), APS would be required to assume the debt
associated with the transactions, make specified payments to the equity
participants, and take title to the leased Unit 2 interests, which, if
appropriate, may be required to be written down in value. If such an event had
occurred as of December 31, 2002, APS would have been required to assume
approximately $285 million of debt and pay the equity participants approximately
$200 million.

21.  INTANGIBLE ASSETS

     On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." We have no goodwill recorded and have separately disclosed
other intangible assets on our Consolidated Balance Sheets. The intangible
assets continue to be amortized over their finite useful lives. Thus, there was
no impact on our financial position as a result of the adoption of SFAS No. 142.
The Company's gross intangible assets (which are primarily software) were $214
million at December 31, 2002 and $175 million at December 31, 2001. The related
accumulated amortization was $104 million at December 31, 2002 and $88 million
at December 31, 2001. Amortization expense was $21 million in 2002, $22 million
in 2001 and $20 million in 2000. Estimated amortization expense on existing
intangible assets over the next five years is $25 million in 2003, $24 million
in 2004, $23 million in 2005, $21 million in 2006 and $15 million in 2007.

22.  EL DORADO'S INVESTMENT IN NAC

     Through our unregulated wholly-owned subsidiary, El Dorado, we own a
majority interest in NAC, a company that develops, markets and contracts for the
manufacture of cask designs for spent nuclear fuel storage and transportation.
Prior to the third quarter of 2002, our investment in NAC was accounted for
under the equity method and our share of NAC's earnings and losses was recorded
in other income or expense in our Consolidated Statements of Income. Beginning
in the third quarter of 2002, we fully consolidated NAC's financial statements
after acquiring a controlling interest in NAC as a result of increased voting
representation on NAC's Board of Directors. During the second and third quarters
of 2002, we recorded cumulative losses of approximately $21 million before tax
($13 million after tax, $0.15 per share) related to NAC, primarily as a result
of expected losses under contracts with two customers, including a contract
between NAC and Maine Yankee Atomic Power Company (Maine Yankee).

     On January 15, 2003, Maine Yankee notified NAC of its intention to
terminate its contract with NAC. We recorded additional NAC losses of
approximately $38 million before tax ($23 million after tax, or $0.27 per share)
in the fourth quarter of 2002, the substantial majority of which relate to the
termination of the Maine Yankee contract. As a result, in 2002, we recorded NAC
losses of approximately $59 million before tax ($35 million after tax, or $0.42
per share).

                                       134
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

     NAC LITIGATION On March 4, 2003, Maine Yankee Atomic Power Co. filed suit
against Pinnacle West, NAC and a surety company in federal court in Portland,
Maine. MAINE YANKEE ATOMIC POWER COMPANY V. UNITED STATES FIRE INSURANCE
COMPANY, Civil Action Docket No. 03-58-PC, United States District Court,
District of Maine. The lawsuit alleges that NAC failed to meet its contractual
obligations with respect to certain of NAC's activities relating to the
decommissioning of the Maine Yankee nuclear power plant. The lawsuit was filed a
few weeks after NAC initiated arbitration against Maine Yankee with respect to
matters relating to the same contract. The lawsuit seeks recovery under a
parental guarantee signed by Pinnacle West relating to certain of NAC's
contractual obligations and under performance and payment bonds issued by the
surety which are guaranteed (at least in part) by Pinnacle West. Maine Yankee
also alleges damages in excess of $1 million. We are currently evaluating the
allegations of the lawsuit and expect to vigorously defend our position.

23.  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 are effective for
the year ended December 31, 2002. The initial recognition and measurement
provisions of FIN No. 45 are effective on a prospective basis to guarantees
issued or modified after December 31, 2002.

     We have issued parental guarantees and letters of credit and obtained
surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees
related to Pinnacle West Energy consist of equipment and performance guarantees
related to our generation construction program, transmission service guarantees
for West Phoenix Units 4 and 5 and long-term service agreement guarantees for
new power plants. Our credit support instruments enable APS Energy Services to
provide commodity energy and energy-related products and enable El Dorado to
support the activities of NAC. SunCor has a debt guarantee on behalf of an
affiliated joint venture. Non-performance or payment under the original contract
by our unregulated subsidiaries would require us to perform under the guarantee
or surety bond. No liability is currently recorded on the Consolidated Balance
Sheets related to Pinnacle West's guarantees on behalf of its subsidiaries. Our
guarantees have no recourse (except NAC) or collateral provisions to allow us to
recover amounts paid under the guarantee. The amounts and approximate terms of
our guarantees and surety bonds for each subsidiary at December 31, 2002 are as
follows (dollars in millions):

                                       135
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                        Guarantees                Surety Bonds              Letters of Credit
                                    -------------------      ----------------------      -----------------------
                                                Term                        Term                         Term
                                    Amount   (in years)      Amount      (in years)      Amount       (in years)
                                    ------   ----------      ------      ----------      ------       ----------
<S>                                   <C>     <C>           <C>          <C>             <C>           <C>
Parental:
  Pinnacle West Energy                $126      1 to 2        $ --           --           $ 42          1 to 2
  APS Energy  Services                  82   less than 2        43       less than 1        --            --
  El Dorado (all NAC)                   43      1 to 3          --           --             --            --
SunCor guarantees                       33         1            --           --             --            --
                                      ----                    ----                        ----
Total                                 $284                    $ 43                        $ 42
                                      ====                    ====                        ====
</TABLE>

     At December 31, 2002, we had entered into approximately $42 million of
letters of credit which support various construction agreements. These letters
of credit expire in 2003 and 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.

     APS has entered into various agreements that require letters of credit for
financial assurance purposes. At December 31, 2002, approximately $258 million
of letters of credit were outstanding to support existing pollution control
bonds of approximately $253 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 2003. APS has also entered into approximately
$115 million of letters of credit to support certain equity lessors in the Palo
Verde sale-leaseback transactions (see Note 9 for further details on the Palo
Verde sale-leaseback transactions). These letters of credit expire in 2005.
Additionally, APS has approximately $5 million of letters of credit related to
counterparty collateral requirements and approximately $5 million of letters of
credit related to workers' compensation expiring in 2003. APS intends to provide
from either existing or new facilities for the extension, renewal or
substitution of the letters of credit to the extent required.

     In conjunction with our financing agreements, including our sale-leaseback
transactions, we generally provide indemnifications relating to liabilities
arising from or related to the agreements, except with certain limited
exceptions depending on the particular agreement. APS has also provided
indemnifications to the equity participants and other parties in the Palo Verde
sale-leaseback transactions with respect to certain tax matters. Generally, a
maximum obligation is not explicitly stated in the indemnification and
therefore, the overall maximum amount of the obligation under such
indemnifications cannot be reasonably estimated. Based on historical experience
and evaluation of the specific indemnities, we do not believe that any material
loss related to such indemnifications is likely and therefore no related
liability has been recorded.

                                       136
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

24.  SUBSEQUENT EVENTS

     See "ACC Applications" in Note 3 for information regarding the ACC's
approval on March 27, 2003 of a $500 million financing arrangement between APS
and Pinnacle West Energy and "Track B Order" in Note 3 for information regarding
the ACC order issued on March 14, 2003, mandating a process by which APS must
competitively procure energy.

     See "California Energy Issues and Refunds in the Pacific Northwest" in Note
11 for information regarding the FERC's adoption on March 26, 2003 of an ALJ's
proposed findings, and issuance on March 26, 2003 of a Final Report on Price
Manipulation in Western Markets.

     See Note 22 for information related to the March 4, 2003 NAC litigation.

                                       137
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                 SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS

<TABLE>
<CAPTION>
          Column A                     Column B             Column C            Column D      Column E
                                                           Additions
                                                     ---------------------
                                       Balance at    Charged to   Charged                      Balance
                                       beginning     cost and     to other                    at end of
        Description                    of period     expenses     accounts     Deductions      Period
        -----------                    ---------     --------     --------     ----------      ------
                                          (dollars in thousands)
                                       YEAR ENDED DECEMBER 31, 2002
<S>                                    <C>           <C>          <C>          <C>            <C>
Real Estate Valuation Reserves         $  2,000      $     --     $     --     $     339(a)   $  1,661

                                       YEAR ENDED DECEMBER 31, 2001
Real Estate Valuation Reserves         $  2,000      $     --     $     --     $      --(a)   $  2,000

                                       YEAR ENDED DECEMBER 31, 2000
Real Estate Valuation Reserves         $  8,000      $     --     $     --     $   6,000(a)   $  2,000

                                       YEAR ENDED DECEMBER 31, 2002
Reserve for uncollectibles             $ 14,334      $    (21)    $     --     $   4,705      $  9,608

                                       YEAR ENDED DECEMBER 31, 2001
Reserve for uncollectibles             $  7,580      $ 13,394     $    --      $   6,640      $ 14,334

                                       YEAR ENDED DECEMBER 31, 2000
Reserve for uncollectibles             $  1,538      $ 10,638     $    --      $   4,596      $  7,580

                                       YEAR ENDED DECEMBER 31, 2002
Reserve for contract losses            $     --      $ 13,000(b)  $    --      $      --      $ 13,000
</TABLE>

(a)  Represents pro-rata allocations for sale of land.
(b)  Contract losses related to NAC.

                                       138
<PAGE>
              ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
                     ON ACCOUNTING AND FINANCIAL DISCLOSURE

     None.

                                    PART III

                        ITEM 10. DIRECTORS AND EXECUTIVE
                           OFFICERS OF THE REGISTRANT

     Reference is hereby made to "Election of Directors" and to "Section 16(a)
Beneficial Ownership Reporting Compliance" in the Company's Proxy Statement
relating to the Annual Meeting of Shareholders to be held on May 21, 2003 (the
"2003 Proxy Statement") and to the Supplemental Item --- "Executive Officers of
the Registrant" in Part I of this report.

                         ITEM 11. EXECUTIVE COMPENSATION

     Reference is hereby made to "The Board and its Committees - How are
Directors Compensated?"; "Performance Graph"; and "Executive Compensation" in
the 2003 Proxy Statement.

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

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     Reference is hereby made to "Election of Directors - How many shares of
Pinnacle West stock are owned by management and large shareholders?" in the 2003
Proxy Statement.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

     The following table sets forth information as of December 31, 2002 with
respect to our compensation plans and individual compensation arrangements under
which our equity securities were authorized for issuance to directors, officers,
employees, consultants and certain other persons and entities in exchange for
the provision to us of goods or services.

                                       139
<PAGE>
<TABLE>
<CAPTION>
                                                                                      NUMBER OF SECURITIES
                                                                                    REMAINING AVAILABLE FOR
                              NUMBER OF SECURITIES TO      WEIGHTED-AVERAGE       FUTURE ISSUANCE UNDER EQUITY
                              BE ISSUED UPON EXERCISE      EXERCISE PRICE OF     COMPENSATION PLANS (EXCLUDING
                              OF OUTSTANDING OPTIONS,    OUTSTANDING OPTIONS,       SECURITIES REFLECTED IN
       PLAN CATEGORY            WARRANTS AND RIGHTS       WARRANTS AND RIGHTS             COLUMN (a))
                                        (a)                       (b)                         (c)
----------------------------  -----------------------    --------------------    -----------------------------
<S>                           <C>                        <C>                     <C>
Equity compensation plans
approved by security holders         2,185,129                  $ 39.96                     5,317,145
Equity compensation plans
not approved by security
holders                                     --                  $    --                       172,100
                                    ----------                                             ----------
         Total                       2,185,129                  $ 39.96                     5,489,245
                                    ==========                                             ==========
</TABLE>

EQUITY COMPENSATION PLANS APPROVED BY SECURITY HOLDERS

     The Company has four equity compensation plans that were approved by its
shareholders: the Pinnacle West Capital Corporation Stock Option and Incentive
Plan, under which no new options may be granted; the Pinnacle West Capital
Corporation Directors Stock Option Plan under which no new options may be
granted; the Pinnacle West Capital Corporation 1994 Long-Term Incentive Plan;
and the Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan. See
Note 16 for additional information regarding these plans.

EQUITY COMPENSATION PLANS NOT APPROVED BY SECURITY HOLDERS

     The Company has one equity compensation plan, the Pinnacle West Capital
Corporation 2000 Director Equity Plan (the "2000 Plan"), for which the approval
of shareholders was not required.

     NUMBER OF SHARES SUBJECT TO THE 2000 PLAN. The total number of shares of
the Company's common stock granted under the 2000 Plan may not exceed 200,000.
In the case of a significant corporate event, such as a reorganization, merger
or consolidation, the 2000 Plan provides for adjustment of the above limit, the
number of shares to be awarded automatically to eligible non-employee directors,
the number of shares of the Company's common stock non-employee directors are
required to own to receive an annual grant of common stock and options granted
under the 2000 Plan.

     ELIGIBILITY FOR PARTICIPATION. Only non-employee directors may participate
in the 2000 Plan. A non-employee director is an individual who is a director of
the Company but who is not also an employee of the Company or any of its
subsidiaries.

     TERMS OF AWARDS. The 2000 Plan provides for: (1) annual grants of common
stock to eligible non-employee directors, (2) discretionary grants of common
stock to eligible non-employee directors and (3) grants of nonqualified stock
options to eligible non-employee directors.

                                       140
<PAGE>
     ANNUAL GRANTS OF STOCK

     Each individual who is a non-employee director as of July 1 of a calendar
year, and who meets requirements of ownership of the Company's common stock set
forth below, will receive 900 shares of the Company's common stock for such
calendar year. In the first calendar year in which a non-employee director is
eligible to participate in the 2000 Plan, he or she must own at least 900 shares
of the Company's common stock as of December 31 of the same calendar year to
receive a grant of 900 shares of the Company's common stock. If the non-employee
director owns 900 shares of common stock as of June 30, he or she will receive a
grant of 900 shares of common stock as of July 1 of the same calendar year. If
the non-employee director does not own 900 shares of the Company's common stock
as of June 30, but acquires the necessary shares on or before December 31 of the
same year, he or she will receive a grant of 900 shares of common stock within a
reasonable time after the Company verifies that the requisite number of shares
has been acquired. In each subsequent year, the number of shares of the
Company's common stock the non-employee director must own to receive a grant of
900 shares of common stock will increase by 900 shares, until reaching a maximum
of 4,500 shares. In each of the subsequent years, the non-employee director must
own the requisite number of shares of the Company's common stock as of June 30
of the relevant calendar year.

     DISCRETIONARY GRANTS OF STOCK

     The Human Resources Committee of the Board of Directors, excluding those
members who are not "Non-Employee Directors" under SEC Rule 16b-3(b)(3) (the
Committee) administers the 2000 Plan and may grant shares of the Company's
common stock to non-employee directors in its discretion. No discretionary
grants of common stock have been made under the 2000 Plan.

     GRANTS OF NONQUALIFIED STOCK OPTIONS

     The Committee can grant nonqualified stock options under the 2000 Plan. The
terms and the conditions of the option grant, including the exercise price per
share, which may not be less than fair market value on the date of grant, will
be set by the Committee in a written award agreement. The Committee will
determine the time or times at which any such options may be exercised in whole
or in part. The Committee will also determine the performance or other
conditions, if any, that must be satisfied before all or part of an option may
be exercised. Any such options granted to a participant will expire on the tenth
anniversary date of the date of grant, unless the option is earlier terminated,
forfeited or surrendered pursuant to a provision of the 2000 Plan or the
applicable award agreement. Notwithstanding the foregoing, if a participant
ceases to be a Company director for any reason, including death or disability,
any such options held by that participant will expire on the second anniversary
of the date on which the participant ceased to be a Company director, unless
otherwise provided in the applicable award agreement. Unless the Committee
provides otherwise, no such options may be sold, transferred, pledged, assigned
or otherwise alienated, other than by will, the laws of descent and
distribution, or under any other circumstances allowed by the Committee. No
options have been granted under the 2000 Plan.

             ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Reference is hereby made to "Executive Compensation - Human Resources
Committee Interlocks and Insider Participation" and "- Employment and Severance
Arrangements" in the 2003 Proxy Statement.

                                       141
<PAGE>
                        ITEM 14. CONTROLS AND PROCEDURES

     As of a date within 90 days of the date of this report (the "Evaluation
Date"), we carried out an evaluation, under the supervision and with the
participation of our management, including our Chief Executive Officer and our
Chief Financial Officer, of the effectiveness of the design and operation of our
disclosure controls and procedures, as defined in Rules 13a-14 and 15d-14 under
the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Based upon
this evaluation, our Chief Executive Officer and our Chief Financial Officer,
concluded that, as of the Evaluation Date, our disclosure controls and
procedures were adequate to ensure that information required to be disclosed by
us in the reports filed or submitted by us under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in the
SEC's rules and forms.

     There were no significant changes in our internal controls or in other
factors that could significantly affect these controls subsequent to the date of
the evaluation, including any corrective actions with regard to significant
deficiencies and internal weaknesses.

                                     PART IV

                     ITEM 15. EXHIBITS, FINANCIAL STATEMENT
                       SCHEDULES, AND REPORTS ON FORM 8-K

FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES

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

EXHIBITS FILED

EXHIBIT NO.                            DESCRIPTION
-----------                            -----------

4.1      --    Fifty-sixth Supplemental Indenture to the Mortgage dated as of
               March 1, 2003

4.2      --    Fifty-seventh Supplemental Indenture to the Mortgage dated as of
               April 1, 2003

10.1(a)  --    2003 Officer Variable Incentive Plan

10.2(a)  --    2003 CEO Variable Incentive Plan

10.3(a)  --    Schedules of William J. Post and Jack E. Davis to Arizona Public
               Service Company Deferred Compensation Plan, as amended

10.4(a)  --    Letter Agreement dated June 28, 2001 between Pinnacle West
               Capital Corporation and Steve Wheeler

10.5(a)  --    Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan

12.1     --    Ratio of Earnings to Fixed Charges

21.1     --    Subsidiaries of the Company

23.1     --    Consent of Deloitte & Touche LLP

                                       142
<PAGE>
99.1     --    Certification of William J. Post, the Company's principal
               executive officer, pursuant to Section 906 of the Sarbanes-Oxley
               Act of 2002

99.2     --    Certification of Donald E. Brandt, the Company's principal
               financial officer, pursuant to Section 906 of the Sarbanes-Oxley
               Act of 2002

99.3     --    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
ss.229.10(d) by reference to the filings set forth below:

<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
3.1           Articles of Incorporation,       19.1 to the Company's September        1-8962         11-14-88
              restated as of July 29, 1988     1988 Form 10-Q Report

3.2           Bylaws, amended as of            3.2 to September 2002 Form 10-Q        1-8962         11-14-02
              September 18, 2002               Report

4.3           Mortgage and Deed of Trust       4.1 to APS' September 1992 Form        1-4473         11-9-92
              Relating to APS' First           10-Q Report
              Mortgage Bonds, together with
              forty-eight indentures
              supplemental thereto

4.4           Forty-ninth Supplemental         4.1 to APS' 1992 Form 10-K Report      1-4473         3-30-93
              Indenture

4.5           Fiftieth Supplemental            4.2 to APS' 1993 Form 10-K Report      1-4473         3-30-94
              Indenture

4.6           Fifty-first Supplemental         4.1 to APS' August 1, 1993 Form        1-4473         9-27-93
              Indenture                        8-K Report

4.7           Fifty-second Supplemental        4.1 to APS' September 30, 1993         1-4473         11-15-93
              Indenture                        Form 10-Q Report
</TABLE>

                                       143
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
4.8           Fifty-third Supplemental         4.5 to APS' Registration               1-4473         3-1-94
              Indenture                        Statement No. 33-61228 by means
                                               of February 23, 1994 Form 8-K
                                               Report

4.9           Fifty-fourth Supplemental        4.1 to APS' Registration               1-4473         11-22-96
              Indenture                        Statements Nos. 33-61228,
                                               33-55473, 33-64455 and 333-15379
                                               by means of November 19, 1996
                                               Form 8-K Report

4.10          Fifty-fifth Supplemental         4.8 to APS' Registration               1-4473         4-9-97
              Indenture                        Statement Nos. 33-55473, 33-64455
                                               and 333-15379 by means of April
                                               7, 1997 Form 8-K Report

4.11          Agreement, dated March 21,       4.1 to APS' 1993 Form 10-K Report      1-4473         3-30-94
              1994, relating to the filing
              of  instruments defining the
              rights of holders of APS
              long-term debt not in excess
              of 10% of APS' total assets

4.12          Indenture dated as of January    4.6 to APS' Registration               1-4473         1-11-95
              1, 1995 among APS and The        Statement Nos. 33-61228 and
              Bank of New York, as  Trustee    33-55473 by means of January 1,
                                               1995 Form 8-K Report

4.13          First Supplemental Indenture     4.4 to APS' Registration               1-4473         1-11-95
              dated as of January 1, 1995      Statement Nos. 33-61228 and
                                               33-55473 by means of January 1,
                                               1995 Form 8-K Report

4.14          Indenture dated as of            4.5 to APS' Registration               1-4473         11-22-96
              November 15, 1996 among APS      Statements Nos. 33-61228,
              and The Bank of New York, as     33-55473, 33-64455 and 333- 15379
              Trustee                          by means of November 19, 1996
                                               Form 8-K Report
</TABLE>

                                       144
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
4.15          First Supplemental Indenture     4.6 to APS' Registration               1-4473         11-22-96
                                               Statements Nos. 33-61228,
                                               33-55473, 33-64455 and 333-15379
                                               by means of November 19, 1996
                                               Form 8-K Report

4.16          Second Supplemental Indenture    4.10 to APS' Registration              1-4473         4-9-97
                                               Statement Nos. 33-55473, 33-64455
                                               and 333-15379 by means of April
                                               7, 1997 Form 8-K Report

4.17          Indenture dated as of            4.1 to the Company's Registration      1-8962         1-25-01
              December 1, 2000 between the     Statement No. 333-53150
              Company and The Bank of New
              York, as Trustee, relating to
              Senior Debt Securities

4.18          First Supplemental Indenture     4.2 to the Company's Registration      1-8962         3-26-01
              dated as of March 15, 2001       Statement No. 333-52476

4.19          Indenture dated as of            4.2 to the Company's Registration      1-8962         1-25-01
              December 1, 2000 between the     Statement No. 333-53150
              Company and The Bank of New
              York, as Trustee, relating to
              subordinated Debt Securities

4.20          Specimen Certificate of          4.2 to the Company's 1988 Form         1-8962         3-31-89
              Pinnacle West Capital            10-K Report
              Corporation Common Stock,  no
              par value

4.21          Agreement, dated March 29,       4.1 to the Company's 1987 Form         1-8962         3-30-88
              1988, relating to the filing     10-K Report
              of  instruments defining the
              rights of holders of
              long-term  debt not in excess
              of 10% of  the Company's
              total assets
</TABLE>

                                       145
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
4.22          Indenture dated as of January    4.10 to APS' Registration The          1-4473         1-16-98
              15, 1998 among APS and Chase     Statement Nos. 333-15379 and
              Manhattan Bank, as Trustee       333-27551 by means of January 13,
                                               1998 Form 8-K Report

4.23          First Supplemental Indenture     4.3 to APS' Registration               1-4473         1-16-98
              dated as of January 15, 1998     Statement Nos. 333-15379 and
                                               333-27551 by means of January 13,
                                               1998 Form 8-K Report

4.24          Second Supplemental Indenture    4.3 to APS' Registration               1-4473         2-22-99
              dated as of February 15, 1999    Statement Nos. 333-27551 and
                                               333-58445 by means of February
                                               18, 1999 Form 8-K Report

4.25          Third Supplemental Indenture     4.5 to APS' Registration               1-4473         11-5-99
              dated as of November 1, 1999     Statement Nos. 333-58445 by means
                                               of November 2, 1999 Form 8-K
                                               Report

4.26          Fourth Supplemental Indenture    4.1 to Registration Statement No.      1-4473         8-4-00
              dated as of August 1, 2000       333-58445 and 333-94277 by means
                                               of August 2, 2000 Form 8-K Report

4.27          Fifth Supplemental Indenture     4.1 to APS' September 2001 Form        1-4473         11-6-01
              dated as of October 1, 2001      10-Q

4.28          Sixth Supplemental Indenture     4.1 to APS' Registration               1-4473         2-28-01
              dated as of March 1, 2002        Statement Nos. 333-63994 and
                                               333-83398 by means of February
                                               26, 2002 Form 8-K Report
</TABLE>

                                       146
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
4.29          Amended and Restated Rights      4.1 to the Company's March 22,         1-8962         4-19-99
              Agreement, dated as of March     1999 Form 8-K Report
              26, 1999, between Pinnacle
              West Capital Corporation and
              BankBoston, N.A., as Rights
              Agent, including (i) as
              Exhibit A thereto the form of
              Amended Certificate of
              Designation of Series A
              Participating Preferred Stock
              of Pinnacle West Capital
              Corporation, (ii) as Exhibit
              B thereto the form of Rights
              Certificate and (iii) as
              Exhibit C thereto the Summary
              of Right to Purchase
              Preferred Shares

4.30          Amendment to Rights              4.1 to March 2002 Form 10-Q Report     1-8962         5-15-02
              Agreement, effective as of
              January 1, 2002

10.6          Two separate Decommissioning     10.2 to APS' September 1991 Form       1-4473         11-14-91
              Trust Agreements (relating       10-Q Report
              to  PVNGS Units 1 and 3,
              respectively), each dated
              July 1, 1991, between APS and
              Mellon Bank, N.A., as
              Decommissioning Trustee

10.7          Amendment No. 1 to               10.1 to APS' 1994 Form 10- K           1-4473         3-30-95
              Decommissioning Trust            Report
              Agreement (PVNGS Unit 1),
              dated as of December 1, 1994
</TABLE>

                                       147
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.8          Amendment No. 1 to               10.2 to APS' 1994 Form 10-K            1-4473         3-30-95
              Decommissioning Trust            Report
              Agreement (PVNGS Unit 3),
              dated as of December 1, 1994

10.9          Amendment No. 2 to APS           10.4 to APS' 1996 Form 10-K            1-4473         3-28-97
              Decommissioning Trust            Report
              Agreement (PVNGS Unit 1)
              dated as of July 1, 1991

10.10         Amendment No. 2 to APS           10.6 to APS' 1996 Form 10-K            1-4473         3-28-97
              Decommissioning Trust            Report
              Agreement (PVNGS Unit 3)
              dated as of July 1, 1991

10.11         Amended and Restated             10.1 to the Company's 1991 Form        1-8962         3-26-92
              Decommissioning Trust            10-K Report
              Agreement (PVNGS Unit 2)
              dated as of January 31,
              1992,  among APS, Mellon
              Bank, N.A., as
              Decommissioning  Trustee, and
              State Street Bank and Trust
              Company, as  successor to The
              First  National Bank of
              Boston, as Owner Trustee
              under two separate Trust
              Agreements, each with a
              separate Equity Participant,
              and as Lessor under two
              separate Facility Leases,
              each relating to an undivided
              interest in PVNGS Unit 2
</TABLE>

                                       148
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.12         First Amendment to Amended       10.2 to APS' 1992 Form 10-K            1-4473         3-30-93
              and Restated  Decommissioning    Report
              Trust  Agreement (PVNGS Unit
              2), dated as of November 1,
              1992

10.13         Amendment No. 2 to Amended       10.2 to APS' 1994 Form 10-K            1-4473         3-30-95
              and Restated Decommissioning     Report
              Trust Agreement (PVNGS Unit
              2), dated as of November 1,
              1994

10.14         Amendment No. 3 to Amended       10.1 to APS' June 1996 Form 10-Q       1-4473         8-9-96
              and Restated Decommissioning     Report
              Trust Agreement (PVNGS Unit
              2), dated as of November 1,
              1994

10.15         Amendment No. 4 to Amended       APS 10.5 to APS' 1996 Form 10-K        1-4473         3-28-97
              and Restated Decommissioning     Report
              Trust Agreement (PVNGS Unit
              2) dated as of January 31,
              1992

10.16         Amendment No. 5 to the           10.1 to Pinnacle West's March          1-8962         5-15-02
              Amended and Restated             2002 Form 10-Q Report
              Decommissioning Trust
              Agreement (PVNGS Unit 2),
              dated as of June 30, 2000

10.17         Amendment No. 3 to the           10.2 to Pinnacle West's March          1-8962         5-15-02
              Decommissioning Trust            2002 Form 10-Q Report
              Agreement (PVNGS Unit 1),
              dated as of March 18, 2002
</TABLE>

                                       149
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.18         Amendment No. 6 to the           10.3 to Pinnacle West's March          1-8962         5-15-02
              Amended and Restated             2002 Form 10-Q Report
              Decommissioning Trust
              Agreement (PVNGS Unit 2),
              dated as of March 18, 2002

10.19         Amendment No. 3 to the           10.4 to Pinnacle West's March          1-8962         5-15-02
              Decommissioning Trust            2002 Form 10-Q Report
              Agreement (PVNGS Unit 3),
              dated as of March 18, 2002

10.20         Asset Purchase and Power         10.1 to APS' June 1991 Form 10-Q       1-4473         8-8-91
              Exchange Agreement dated         Report
              September 21, 1990 between
              APS and PacifiCorp, as
              amended as of October 11,
              1990 and as of July 18, 1991

10.21         Long-Term Power Transaction      10.2 to APS' June 1991 Form 10-Q       1-4473         8-8-91
              Agreement dated September 21,    Report
              1990 between APS and
              PacifiCorp, as amended as of
              October 11, 1990, and as of
              July 8, 1991

10.22         Amendment No. 1 dated April      10.3 to APS' 1995 Form 10-K            1-4473         3-29-96
              5, 1995 to the Long-Term         Report
              Power Transaction Agreement
              and Asset Purchase and Power
              Exchange Agreement between
              PacifiCorp and APS

10.23         Restated Transmission            10.4 to APS' 1995 Form 10-K            1-4473         3-29-96
              Agreement between PacifiCorp     Report
              and APS dated April 5, 1995
</TABLE>

                                       150
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.24         Contract among PacifiCorp,       10.5 to APS' 1995 Form 10-K            1-4473         3-29-96
              APS and United States            Report
              Department of Energy Western
              Area Power Administration,
              Salt Lake Area Integrated
              Projects for Firm
              Transmission Service dated
              May 5, 1995

10.25         Reciprocal Transmission          10.6 to APS' 1995 Form 10-K            1-4473         3-29-96
              Service Agreement between APS    Report
              and PacifiCorp dated as of
              March 2, 1994

10.26         Contract, dated July 21,         10.31 to the Company's Form S-14       2-96386        3-13-85
              1984, with DOE providing for     Registration Statement
              the disposal of nuclear fuel
              and/or high-level
              radioactive waste, ANPP

10.27         Indenture of Lease with          5.01 to APS' Form S-7                  2-59644        9-1-77
              Navajo Tribe of Indians, Four    Registration Statement
              Corners Plant

10.28         Supplemental and Additional      5.02 to APS' Form S-7                  2-59644        9-1-77
              Indenture of Lease, including    Registration Statement
              amendments and supplements
              to original lease with
              Navajo Tribe of Indians,
              Four Corners Plant

10.29         Amendment and Supplement No.     10.36 to the Company's                 1-8962         7-25-85
              1 to Supplemental and            Registration Statement on Form
              Additional Indenture of Lease    8-B Report
              Four Corners, dated April
              25, 1985
</TABLE>

                                       151
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.30         Application and Grant of         5.04 to APS' Form S-7                  2-59644        9-1-77
              multi-party rights-of-way and    Registration Statement
              easements, Four Corners Plant
              Site

10.31         Application and Amendment No.    10.37 to the Company's                 1-8962         7-25-85
              1 to Grant of multi-party        Registration Statement on Form
              rights-of-way and easements,     8-B
              Four Corners Power Plant
              Site dated April 25, 1985

10.32         Application and Grant of         5.05 to APS' Form S-7                  2-59644        9-1-77
              Arizona Public Service           Registration Statement
              Company rights-of-way and
              easements, Four Corners Plant
              Site

10.33         Four Corners Project             10.7 to the Company's 2000 Form        1-8962         3-14-01
              Co-Tenancy Agreement             10-K Report
              Amendment No. 6

10.34         Application and Amendment No.    10.38 to the Company's                 1-8962         7-25-85
              1 to Grant of Arizona Public     Registration Statement on Form
              Service Company                  8-B
              rights-of-way and easements,
              Four Corners Power Plant
              Site dated April 25, 1985

10.35         Indenture of Lease, Navajo       5(g) to APS' Form S-7                  2-36505        3-23-70
              Units 1, 2, and 3                Registration Statement

10.36         Application of Grant of          5(h) to APS Form S-7 Registration      2-36505        3-23-70
              rights-of-way and easements,     Statement
              Navajo Plant

10.37         Water Service Contract           5(l) to APS' Form S-7                  2-394442       3-16-71
              Assignment with the United       Registration Statement
              States Department of
              Interior, Bureau of
              Reclamation, Navajo Plant
</TABLE>

                                       152
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.38         Arizona Nuclear Power Project    10.1 to APS' 1988 Form 10-K            1-4473         3-8-89
              Participation Agreement,
              dated August 23, 1973, among
              APS Salt River Project
              Agricultural Improvement and
              Power District, Southern
              California Edison Company,
              Public Service Company of
              New Mexico, El Paso
              Electric Company, Southern
              California Public Power
              Authority, and Department of
              Water and Power of the City
              of Los Angeles, and
              amendments 1-12 thereto

10.39         Amendment No. 13, dated as       10.1 to APS' March 1991 Form 10-Q      1-4473         5-15-91
              of April 22, 1991, to Arizona
              Nuclear Power Project
              Participation Agreement,
              dated August 23, 1973, among
              APS, Salt River Project
              Agricultural Improvement and
              Power District, Southern
              California Edison Company,
              Public Service Company of New
              Mexico, El Paso Electric
              Company, Southern California
              Public Power Authority, and
              Department of Water and Power
              of the City of Los Angeles
</TABLE>

                                       153
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.40         Amendment No. 14 to Arizona      99.1 to the Company's June 2000        1-8962         8-14-00
              Nuclear Power Project            Form 10-Q Report
              Participation Agreement,
              dated August 23, 1973, among
              APS, Salt River Project
              Agricultural Improvement and
              Power District, Southern
              California Edison Company,
              Public Service Company of New
              Mexico, El Paso Electric
              Company, Southern California
              Public Power Authority, and
              Department of Water and Power
              of the City of Los Angeles

10.41(c)      Facility Lease, dated as of      4.3 to APS' Form S-3 Registration      33-9480        10-24-86
              August 1, 1986, between State    Statement
              Street Bank and Trust
              Company, as successor to The
              First National Bank of
              Boston, in its capacity as
              Owner Trustee, as Lessor,
              and APS, as Lessee

10.42(c)      Amendment No. 1, dated as of     10.5 to APS' September 1986 Form       1-4473         12-4-86
              November 1, 1986, to Facility    10-Q Report by means of
              Lease, dated as of August 1,     Amendment No. on December  3,
              1986, between State Street       1986 Form 8
              Bank and Trust Company, as
              successor to The First
              National Bank of Boston, in
              its capacity as Owner
              Trustee, as Lessor, and APS,
              as Lessee
</TABLE>

                                       154
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.43(c)      Amendment No. 2 dated as of      10.3 to APS' 1988 Form 10-K            1-4473         3-8-89
              June 1, 1987 to Facility         Report
              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

10.44(c)      Amendment No. 3, dated as of     10.3 to APS' 1992 Form 10-K            1-4473         3-30-93
              March 17, 1993, to Facility      Report
              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

10.45         Facility Lease, dated as of      10.1 to APS' November 18 1986          1-4473         1-20-87
              December 15, 1986, between       Form 8-K Report
              State Street Bank and Trust
              Company, as successor to The
              First National Bank of
              Boston, in its capacity as
              Owner Trustee, as Lessor,
              and APS, as Lessee

10.46         Amendment No. 1, dated as of     4.13 to APS' Form S-3                  1-4473         8-24-87
              August 1, 1987, to Facility      Registration Statement No.
              Lease, dated as of December      33-9480 by means of August 1,
              15, 1986, between State          1987 Form 8-K Report
              Street Bank and Trust
              Company, as successor to The
              First National Bank of
              Boston, as Lessor, and APS,
              as Lessee
</TABLE>

                                       155
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.47         Amendment No. 2, dated as of     10.4 to APS' 1992 Form 10-K            1-4473         3-30-93
              March 17, 1993, to Facility      Report
              Lease, dated as of December
              15, 1986, between State
              Street Bank and Trust
              Company, as successor to The
              First National Bank of
              Boston, as Lessor, and APS,
              as Lessee

10.48(a)      Pinnacle West Capital            10.13 to the Company's 1999 Form       1-8962         3-30-00
              Corporation Supplemental         10-K Report
              Excess Benefit Retirement
              Plan, as amended and
              restated, dated December 7,
              1999

10.49(a)      First Amendment to the           10.4 to Pinnacle West's 2001 Form      1-8962         3-27-02
              Pinnacle West Capital            10-K Report
              Corporation Supplemental
              Excess Benefit Retirement Plan

10.50(a)      Second Amendment to the          10.5 to Pinnacle West's 2001 Form      1-8962         3-27-02
              Pinnacle West Capital            10-K Report
              Corporation Supplemental
              Excess Benefit Retirement Plan

10.51(a)      Trust for the Pinnacle West      10.14 to the Company's 1999 Form       1-8962         3-30-00
              Capital Corporation, Arizona     10-K Report
              Public Service Company and
              SunCor Development Company
              Deferred Compensation Plans
              dated August 1, 1996
</TABLE>

                                       156
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.52(a)      First Amendment dated            10.15 to the Company's 1999 Form       1-8962         3-30-00
              December 7, 1999 to the Trust    10-K Report
              for the Pinnacle West Capital
              Corporation, Arizona Public
              Service Company and SunCor
              Development Company Deferred
              Compensation Plans

10.53(a)      Directors' Deferred              10.1 to APS' June 1986 Form 10-Q       1-4473         8-13-86
              Compensation Plan, as            Report
              restated, effective January
              1, 1986

10.54(a)      Second Amendment to the          10.2 to APS' 1993 Form 10-K            1-4473         3-30-94
              Arizona Public Service           Report
              Company Deferred Compensation
              Plan, effective as of
              January 1, 1993

10.55(a)      Third Amendment to the           10.1 to APS' September 1994 Form       1-4473         11-10-94
              Arizona Public Service           10-Q
              Company Directors' Deferred
              Compensation Plan, effective
              as of May 1, 1993

10.56(a)      Fourth Amendment dated           10.8 to the Company's 1999 Form        1-8962         3-30-00
              December 28, 1999 to the         10-K Report
              Arizona Public Service
              Company Directors Deferred
              Compensation Plan

10.57(a)      Arizona Public Service           10.4 to APS' 1988 Form 10-K            1-4473         3-8-89
              Company Deferred Compensation    Report
              Plan, as restated, effective
              January 1, 1984, and the
              second and third amendments
              thereto, dated December 22,
              1986, and December 23, 1987
              respectively
</TABLE>

                                       157
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.58(a)      Third Amendment to the           10.3 to APS' 1993 Form 10-K            1-4473         3-30-94
              Arizona Public Service           Report
              Company Deferred
              Compensation Plan, effective
              as of January 1, 1993

10.59(a)      Fourth Amendment to the          10.2 to APS' September 1994 Form       1-4473         11-10-94
              Arizona Public Service           10-Q Report
              Company Deferred Compensation
              Plan effective as of May 1,
              1993

10.60(a)      Fifth Amendment to the           10.3 to APS' 1996 Form 10-K            1-4473         3-28-97
              Arizona Public Service           Report
              Company Deferred
              Compensation Plan

10.61(a)      Sixth Amendment to Arizona       10.8 to the Company's 2000 Form        1-8962         3-14-01
              Public Service Company           10-K Report
              Deferred Compensation Plan

10.62(a)      First Amendment effective as     10.7 to the Company's 1999 Form        1-8962         3-30-00
              of January 1, 1999, to the       10-K Report
              Pinnacle West Capital
              Corporation, Arizona Public
              Service Company, SunCor
              Development Company and El
              Dorado Investment Company
              Deferred Compensation Plan
</TABLE>

                                       158
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.63(a)      Second Amendment effective       10.10 to the Company's 1999 Form       1-8962         3-30-00
              January 1, 2000 to the           10-K Report
              Pinnacle West Capital
              Corporation, Arizona Public
              Service Company, SunCor
              Development Company and El
              Dorado Investment Company
              Deferred Compensation Plan

10.64(a)      Pinnacle West Capital            10.10 to APS' 1995 Form 10-K           1-4473         3-29-96
              Corporation, Arizona Public      Report
              Service Company, SunCor
              Development Company and  El
              Dorado Investment Company
              Deferred Compensation Plan as
              amended and restated
              effective January 1, 1996

10.65(a)      Pinnacle West Capital            10.7 to APS' 1994 Form 10-K            1-4473         3-30-95
              Corporation and Arizona          Report
              Public  Service Company
              Directors' Retirement Plan,
              effective as of January 1,
              1995

10.66(a)      Letter Agreement dated July      10.16 to the Company's 1999 Form       1-8962         3-30-00
              28, 1995 between Arizona         10-K Report
              Public Service Company and
              Armando B. Flores

10.67(a)      Letter Agreement dated as of     10.8 to APS' 1995 Form 10-K            1-4473         3-29-96
              January 1, 1996 between APS      Report
              and Robert G. Matlock &
              Associates, Inc. for
              consulting services
</TABLE>

                                       159
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.68(a)      Letter Agreement dated           10.7 to APS' 1994 Form 10-K Report     1-4473         3-30-96
              December 21, 1993, between
              APS and William L. Stewart

10.69(a)      Letter Agreement dated           10.8 to APS' 1996 Form 10-K            1-4473         3-28-97
              August 16, 1996 between APS      Report
              and William L. Stewart

10.70(a)      Letter Agreement between APS     10.2 to APS' September 1997 Form       1-4473         11-12-97
              and William L. Stewart           10-Q Report

10.71(a)      Letter Agreement dated           10.9 to 1999 Form 10-K Report          1-8962         3-30-00
              December 13, 1999 between APS
              and William L. Stewart

10.72(a)      Amendment to Letter              10.1 to June 2002 Form                 1-8962         8-13-02
              Agreement, effective as of       10-Q Report
              January 1, 2002, between APS
              and William L. Stewart

10.73(a)      Letter Agreement dated           10.17 to the Company's 1999 Form       1-8962         3-30-00
              October 3, 1997 between          10-K Report
              Arizona Public Service
              Company and James M. Levine

10.74(a)      Summary of James M.              10.2 to March 2002 Form 10-Q           1-8962         5-15-02
              Levine Retirement Benefits       Report

10.75(a)      Employment Agreement,            10.1 to November 2002 Form 10-Q        1-8962         11-14-02
              effective as of October 1,       Report
              2002, between APS and James
              M. Levine
</TABLE>

                                       160
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.76(ad)     Key Executive Employment and     10.1 to June 1999 Form                 1-8962         8-16-99
              Severance Agreement between      10-Q Report
              Pinnacle West and certain
              executive officers of
              Pinnacle West and its
              subsidiaries

10.77(a)      Pinnacle West Capital            10.1 to APS' 1992 Form 10-K            1-4473         3-30-93
              Corporation Stock Option and     Report
              Incentive Plan

10.78(a)      First Amendment dated            10.11 to the Company's 1999 Form       1-8962         3-30-00
              December 7, 1999 to the          10-K Report
              Pinnacle West Capital
              Corporation Stock Option and
              Incentive Plan

10.79(a)      Pinnacle West Capital            A to the Proxy Statement for the       1-8962         4-16-94
              Corporation 1994 Long- Term      Plan Report for the Company's
              Incentive Plan, effective as     1994 Annual Meeting of
              of March 23, 1994                Shareholders

10.80(a)      First Amendment dated            10.12 to the Company's 1999 Form       1-8962         3-30-00
              December 7, 1999 to the          10-K Report
              Pinnacle West Capital
              Corporation 1994 Long-Term
              Incentive Plan

10.81(a)      Pinnacle West Capital            B to the Proxy Statement for the       1-8962         4-16-94
              Corporation Director Equity      Plan Report for the Company's
              Participation Plan               1994 Annual Meeting of
                                               Shareholders

10.82(a)      Pinnacle West Capital            99.1 to the Company's                  1-8962         7-3-00
              Corporation 2000 Director        Registration Statement on Form
              Equity Plan                      S-8 (No. 333-40796)

10.83(a)      Pinnacle West Capital            99.2 to the Company's                  1-8962         7-3-00
              Corporation and Arizona          Registration Statement on Form
              Public Service Company           S-8 (No. 333-40796)
              Directors' Retirement Plan,
              as amended and restated on
              June 21, 2000
</TABLE>

                                       161
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.84         Agreement No. 13904 (Option      10.3 to APS' 1991 Form 10-K            1-4473         3-19-92
              and Purchase of Effluent)        Report
              with Cities of Phoenix,
              Glendale, Mesa, Scottsdale,
              Tempe, Town of Youngtown, and
              Salt River Project
              Agricultural Improvement and
              Power District, dated April
              23, 1973

10.85         Agreement for the Sale and       10.4 to APS' 1991 Form 10-K            1-4473         3-19-92
              purchase of Wastewater           Report
              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

10.86(a)      APS Director Equity Plan         10.1 to September 1997 Form 10-Q       1-4473         11-12-97
                                               Report

10.87         Territorial Agreement between    10.1 to APS' March 1998 Form 10-Q      1-4473         5-15-98
              the Company and Salt River       Report
              Project

10.88         Power Coordination Agreement     10.2 to APS' March 1998 Form 10-Q      1-4473         5-15-98
              between the Company and Salt     Report
              River Project

10.89         Memorandum of Agreement          10.3 to APS' March 1998 Form 10-Q      1-4473         5-15-98
              between the Company and Salt     Report
              River Project
</TABLE>

                                       162
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
10.90         Addendum to Memorandum of        10.2 to APS' May 19, 1998 Form         1-4473         6-26-98
              Agreement between APS and        8-K Report
              Salt River Project dated as
              of May 19, 1998

99.4          Collateral Trust Indenture       4.2 to APS' 1992 Form 10 K Report      1-4473         3-30-93
              among PVNGS II Funding
              Corp., Inc., APS and
              Chemical Bank, as Trustee

99.5          Supplemental Indenture to        4.3 to APS' 1992 Form 10 K Report      1-4473         3-30-93
              Collateral Trust Indenture
              among PVNGS II Funding
              Corp., Inc., APS and
              Chemical Bank, as Trustee
</TABLE>

                                       163
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
99.6(c)       Participation Agreement,         28.1 to APS' September 1992 Form       1-4473         11-9-92
              dated as of August 1, 1986,      10-Q Report
              among PVNGS Funding Corp.,
              Inc., Bank of America
              National Trust and Savings
              Association, State Street
              Bank and Trust Company, as
              successor to The First
              National Bank of Boston, in
              its individual capacity and
              as Owner Trustee, Chemical
              Bank, in its individual
              capacity and as Indenture
              Trustee, APS, and the Equity
              Participant named therein

99.7(c)       Amendment No. 1 dated as of      10.8 to APS' September 1986 Form       1-4473         12-4-86
              November 1, 1986, to             10-Q Report by means of
              Participation Agreement,         Amendment No. 1, on December 3,
              dated as of August 1, 1986,      1986 Form 8
              among PVNGS Funding  Corp.,
              Inc., Bank of America
              National Trust and Savings
              Association, State Street
              Bank and Trust Company, as
              successor to The First
              National Bank of Boston, in
              its individual capacity and
              as Owner Trustee, Chemical
              Bank, in its individual
              capacity and as Indenture
              Trustee, APS, and the Equity
              Participant named therein
</TABLE>

                                       164
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
99.8(c)       Amendment No. 2, dated as of     28.4 to APS' 1992 Form 10-K            1-4473         3-30-93
              March 17, 1993, to               Report
              Participation Agreement,
              dated as of August 1, 1986,
              among PVNGS Funding Corp.,
              Inc., PVNGS II Funding Corp.,
              Inc., State Street Bank and
              Trust Company, as successor
              to The First National Bank of
              Boston, in its individual
              capacity and as Owner
              Trustee, Chemical Bank, in
              its individual capacity and
              as Indenture Trustee, APS,
              and the Equity Participant
              named therein

99.9(c)       Trust Indenture, Mortgage,       4.5 to APS' Form S-3 Registration      33-9480        10-24-86
              Security Agreement and           Statement
              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
</TABLE>

                                       165
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
99.10(c)      Supplemental Indenture No. 1,    10.6 to APS' September 1986 Form       1-4473         12-4-86
              dated as of November 1, 1986     10-Q Report by means of
              to Trust Indenture, Mortgage,    Amendment No. 1 on December  3,
              Security Agreement and           1986 Form 8
              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

99.11(c)      Supplemental Indenture No. 2     28.14 to APS' 1992 Form 10-K           1-4473         3-30-93
              to Trust Indenture, Mortgage,    Report
              Security Agreement and
              Assignment of Facility
              Lease, dated as of August 1,
              1986, between State Street
              Bank and Trust Company, as
              successor to The First
              National Bank of Boston, as
              Owner Trustee, and Chemical
              Bank, as Lease Indenture
              Trustee

99.12(c)      Assignment, Assumption and       28.3 to APS' Form S-3                  33-9480        10-24-86
              Further Agreement, dated as      Registration Statement
              of August 1, 1986, between
              APS and State Street Bank
              and Trust Company, as
              successor to The First
              National Bank of Boston, as
              Owner Trustee
</TABLE>

                                       166
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
99.13(c)      Amendment No. 1, dated as of     10.10 to APS' September 1986 Form      1-4473         12-4-86
              November 1, 1986, to             10-Q Report by means of
              Assignment, Assumption and       Amendment No. l on December  3,
              Further Agreement, dated as      1986 Form 8
              of August 1, 1986, between
              APS and State Street Bank
              and Trust Company, as
              successor to The First
              National Bank of Boston, as
              Owner Trustee

99.14(c)      Amendment No. 2, dated as of     28.6 to APS' 1992 Form 10-K            1-4473         3-30-93
              March 17, 1993, to               Report
              Assignment, Assumption and
              Further Agreement, dated as
              of August 1, 1986, between
              APS and State Street Bank
              and Trust Company, as
              successor to The First
              National Bank of Boston, as
              Owner Trustee

99.15         Participation Agreement,         28.2 to APS' September 1992 Form       1-4473         11-9-92
              dated as of December 15,         10-Q Report
              1986, among PVNGS Funding
              Report Corp., Inc., State
              Street Bank and Trust
              Company, as successor to The
              First National Bank of
              Boston, in its individual
              capacity and as Owner
              Trustee, Chemical Bank, in
              its individual capacity and
              as Indenture Trustee under a
              Trust Indenture, APS, and the
              Owner Participant named
              therein
</TABLE>

                                       167
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
99.16         Amendment No. 1, dated as of     28.20 to APS' Form S-3                 1-4473         8-10-87
              August 1, 1987, to               Registration Statement No.
              Participation Agreement,         33-9480 by means of a November
              dated as of December 15,         6, 1986 Form 8-K  Report
              1986, among PVNGS Funding
              Corp., Inc. as  Funding
              Corporation, State Street
              Bank and Trust Company, as
              successor to The First
              National Bank of Boston, as
              Owner Trustee, Chemical
              Bank, as Indenture Trustee,
              APS, and the Owner
              Participant named therein

99.17         Amendment No. 2, dated as of     28.5 to APS' 1992 Form 10-K            1-4473         3-30-93
              March 17, 1993, to               Report
              Participation Agreement,
              dated as of December 15,
              1986, among PVNGS Funding
              Corp., Inc., PVNGS II Funding
              Corp., Inc., State Street
              Bank and Trust Company, as
              successor to The First
              National Bank of Boston, in
              its individual capacity and
              as Owner Trustee, Chemical
              Bank, in its individual
              capacity and as Indenture
              Trustee, APS, and the Owner
              Participant named therein
</TABLE>

                                       168
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
99.18         Trust Indenture, Mortgage        10.2 to APS' November 18, 1986         1-4473         1-20-87
              Security Agreement and           Form 10-K Report
              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

99.19         Supplemental Indenture No. 1,    4.13 to APS' Form S-3                  1-4473         8-24-87
              dated as of August 1, 1987,      Registration Statement No.
              to Trust Indenture, Mortgage,    33-9480 by means of August 1,
              Security Agreement and           1987 Form 8-K Report
              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
</TABLE>

                                       169
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
99.20         Supplemental Indenture No. 2     4.5 to APS' 1992 Form 10-K Report      1-4473         3-30-93
              to Trust Indenture Mortgage,
              Security Agreement and
              Assignment of Facility
              Lease, dated as of December
              15, 1986, between State
              Street Bank and Trust
              Company, as successor to The
              First National Bank of
              Boston, as Owner Trustee, and
              Chemical Bank, as Lease
              Indenture Trustee

99.21         Assignment, Assumption and       10.5 to APS' November 18, 1986         1-4473         1-20-87
              Further Agreement, dated as      Form 8-K Report
              of December 15, 1986, between
              APS and State Street Bank
              and Trust Company, as
              successor to The First
              National Bank of Boston, as
              Owner Trustee

99.22         Amendment No. 1, dated as of     28.7 to APS' 1992 Form 10-K            1-4473         3-30-93
              March 17, 1993, to               Report
              Assignment, Assumption and
              Further Agreement, dated as
              of December 15, 1986,
              between APS and State Street
              Bank and Trust Company, as
              successor to The First
              National Bank of Boston, as
              Owner Trustee

99.23(c)      Indemnity Agreement dated as     28.3 to APS' 1992 Form 10-K Report     1-4473         3-30-93
              of March 17, 1993 by APS
</TABLE>

                                       170
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
99.24         Extension Letter, dated as of    28.20 to APS' Form S-3                 1-4473         8-10-87
              August 13, 1987, from the        Registration Statement No.
              signatories of the               33-9480 by means of a November
              Participation Agreement to       6, 1986 Form 8-K Report
              Chemical Bank

99.25         Rate Reduction Agreement         10.1 to APS' December 4, 1995          1-4473         12-14-95
              dated December 4, 1995           8-K Report
              between APS and the ACC Staff

99.26         ACC Order dated April 24, 1996   10.1 to APS' March 1996 Form 10-Q      1-4473         5-14-96
                                               Report

99.27         Arizona Corporation              99.1 to APS' 1996 Form 10-K            1-4473         3-28-97
              Commission Order, Decision       Report
              No. 59943, dated December 26,
              1996, including the Rules
              regarding the introduction of
              retail competition in Arizona

99.28         Retail Electric Competition      10.1 to APS' June 1998 Form 10-Q       1-4473         8-14-98
              Rules                            Report

99.29         Arizona Corporation              10.1 to APS' September 1999 10-Q       1-4473         11-15-99
              Commission Order, Decision       Report
              No. 61973, dated October 6,
              1999, approving APS'
              Settlement Agreement

99.30         Addendum to Settlement           10.1 to the Company's September        1-8962         11-14-00
              Agreement                        2000 Form 10-Q Report

99.31         Arizona Corporation              10.2 to APS' September 1999 10-Q       1-4473         11-15-99
              Commission Order, Decision       Report
              No. 61969, dated September
              29, 1999, including the
              Retail Electric Competition
              Rules
</TABLE>

                                       171
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.   DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:         FILE NO.(b)   DATE EFFECTIVE
-----------   -----------                      ----------------------------         -----------   --------------
<S>           <C>                              <C>                                    <C>            <C>
99.32         Track 'A' Appeals Issues -       99.1 to the Company's November         1-8962         12-16-02
              Principles for Resolution        15, 2002 Form 8-K

99.33         ACC Opinion and Order dated      99.1 to the Company's September        1-8962         9-17-02
              September 10, 2002, Decision     10, 2002 Form 8-K Report
              No. 65154 (Track A Order)

99.34         Arizona Public Service           99.2 to the Company's September        1-8962         9-17-02
              Company Application filed        10, 2002 Form 8-K Report
              with the Arizona Corporation
              Commission on September 16,
              2002
</TABLE>

----------
(a)  Management contract or compensatory plan or arrangement to be filed as an
     exhibit pursuant to Item 14(c) of Form 10-K.

(b)  Reports filed under File No. 1-4473 and 1-8962 were filed in the office of
     the Securities and Exchange Commission located in Washington, D.C.

(c)  An additional document, substantially identical in all material respects to
     this Exhibit, has been entered into, relating to an additional Equity
     Participant. Although such additional document may differ in other respects
     (such as dollar amounts, percentages, tax indemnity matters, and dates of
     execution), there are no material details in which such document differs
     from this Exhibit.

(d)  Additional agreements, substantially identical in all material respects to
     this Exhibit have been entered into with additional persons. Although such
     additional documents may differ in other respects (such as dollar amounts
     and dates of execution), there are no material details in which such
     agreements differ from this Exhibit.

REPORTS ON FORM 8-K

     During the quarter ended December 31, 2002, and the period ended March 31,
2003, the Company filed the following Reports on Form 8-K:

     Report dated September 30, 2002 containing exhibits comprised of financial
information and earnings variance explanations.

     Report dated October 17, 2002 regarding the Company's earnings outlook and
a slide presentation for use at an analyst conference.

                                       172
<PAGE>
     Report dated November 14, 2002 regarding an ACC staff recommendation that
the Interim Financing Application be approved.

     Report dated November 15, 2002 regarding: (i) appeals of the Track A Order
and an agreement between APS and the ACC staff; (ii) ACC staff testimony on the
Financing Application; and (iii) EITF 02-3.

     Report dated November 21, 2002 regarding reclassifications of revenue from
electricity trading activities to a net basis of reporting.

     Report dated November 22, 2002 regarding ACC approval of the Interim
Financing Application and Pinnacle West Energy's decision to cancel Redhawk
Units 3 and 4.

     Report dated December 17, 2002 containing exhibits to Registration
Statement Nos. 333-52476 and 333-101457.

     Report dated December 31, 2002 regarding an ACC staff report on Track B and
containing exhibits comprised of financial information and earnings variance
explanations.

     Report dated January 15, 2003 regarding NAC losses and earnings outlook.

     Report dated February 27, 2003 regarding the ACC Track B decision.

     Report dated March 11, 2003 regarding an ACC ALJ recommendation on the
Financing Application.

     Report dated March 27, 2003 regarding ACC approval of a financing
arrangement.

                                       173
<PAGE>
                                   SIGNATURES

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

                                        PINNACLE WEST CAPITAL CORPORATION
                                                  (Registrant)

Date: March 31, 2003
                                        William J. Post
                                        ----------------------------------------
                                        (William J. Post, Chairman of the
                                        Board of Directors and Chief
                                        Executive Officer)

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

            SIGNATURE                         TITLE                    DATE
            ---------                         -----                    ----

       William J. Post             Principal Executive Officer    March 31, 2003
--------------------------------   and Director
  (William J. Post, Chairman
 of the Board of Directors and
   Chief Executive Officer)


         Jack E. Davis             Principal Accounting           March 31, 2003
--------------------------------   Officer and Director
  (Jack E. Davis, President)


       Donald E. Brandt            Principal Financial Officer    March 31, 2003
--------------------------------
      (Donald E. Brandt,
  Senior Vice President and)
   Chief Financial Officer)


     Edward N. Basha, Jr.          Director                       March 31, 2003
--------------------------------
    (Edward N. Basha, Jr.)


     Michael L. Gallagher          Director                       March 31, 2003
--------------------------------
    (Michael L. Gallagher)

                                       174
<PAGE>
         Pamela Grant              Director                       March 31, 2003
--------------------------------
        (Pamela Grant)


     Roy A. Herberger, Jr.         Director                       March 31, 2003
--------------------------------
    (Roy A. Herberger, Jr.)


        Martha O. Hesse            Director                       March 31, 2003
--------------------------------
       (Martha O. Hesse)


   William S. Jamieson, Jr.        Director                       March 31, 2003
--------------------------------
  (William S. Jamieson, Jr.)


       Humberto S. Lopez           Director                       March 31, 2003
--------------------------------
      (Humberto S. Lopez)


       Robert G. Matlock           Director                       March 31, 2003
--------------------------------
      (Robert G. Matlock)


       Kathryn L. Munro            Director                       March 31, 2003
--------------------------------
      (Kathryn L. Munro)


      Bruce J. Nordstrom           Director                       March 31, 2003
--------------------------------
     (Bruce J. Nordstrom)


      William L. Stewart           Director                       March 31, 2003
--------------------------------
     (William L. Stewart)

CERTIFICATIONS

I, William J. Post, certify that:

1.   I have reviewed this annual report on Form 10-K of Pinnacle West Capital
     Corporation;

2.   Based on my knowledge, this annual report does not contain any untrue
     statement of a material fact or omit to state a material fact necessary to
     make the statements made, in light of the circumstances under which such
     statements were made, not misleading with respect to the period covered by
     this annual report;

                                       175
<PAGE>
3.   Based on my knowledge, the financial statements, and other financial
     information included in this annual report, fairly present in all material
     respects the financial condition, results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     a)   designed such disclosure controls and procedures to ensure that
          material information relating to the registrant, including its
          consolidated subsidiaries, is made known to us by others within those
          entities, particularly during the period in which this annual report
          is being prepared;

     b)   evaluated the effectiveness of the registrant's disclosure controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and

     c)   presented in this annual report our conclusions about the
          effectiveness of the disclosure controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation, to the registrant's auditors and the audit
     committee of registrant's board of directors (or persons performing the
     equivalent function):

     a)   all significant deficiencies in the design or operation of internal
          controls which could adversely affect the registrant's ability to
          record, process, summarize and report financial data and have
          identified for the registrant's auditors any material weaknesses in
          internal controls; and

     b)   any fraud, whether or not material, that involves management or other
          employees who have a significant role in the registrant's internal
          controls; and

6.   The registrant's other certifying officer and I have indicated in this
     annual report whether or not there were significant changes in internal
     controls or in other factors that could significantly affect internal
     controls subsequent to the date of our most recent evaluation, including
     any corrective actions with regard to significant deficiencies and material
     weaknesses.

Date: March 31, 2003.

                                        William J. Post
                                        ----------------------------------------
                                        William J. Post
                                        Chairman and Chief Executive Officer

I, Donald E. Brandt, certify that:

1.   I have reviewed this annual report on Form 10-K of Pinnacle West Capital
     Corporation;

2.   Based on my knowledge, this annual report does not contain any untrue
     statement of a material fact or omit to state a material fact necessary to
     make the statements made, in light of the circumstances under which such
     statements were made, not misleading with respect to the period covered by
     this annual report;

                                       176
<PAGE>
3.   Based on my knowledge, the financial statements, and other financial
     information included in this annual report, fairly present in all material
     respects the financial condition, results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The registrant's other certifying officer and I are responsible for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     a)   designed such disclosure controls and procedures to ensure that
          material information relating to the registrant, including its
          consolidated subsidiaries, is made known to us by others within those
          entities, particularly during the period in which this annual report
          is being prepared;

     b)   evaluated the effectiveness of the registrant's disclosure controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and

     c)   presented in this annual report our conclusions about the
          effectiveness of the disclosure controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrant's other certifying officer and I have disclosed, based on
     our most recent evaluation, to the registrant's auditors and the audit
     committee of registrant's board of directors (or persons performing the
     equivalent function):

     a)   all significant deficiencies in the design or operation of internal
          controls which could adversely affect the registrant's ability to
          record, process, summarize and report financial data and have
          identified for the registrant's auditors any material weaknesses in
          internal controls; and

     b)   any fraud, whether or not material, that involves management or other
          employees who have a significant role in the registrant's internal
          controls; and

6.   The registrant's other certifying officer and I have indicated in this
     annual report whether or not there were significant changes in internal
     controls or in other factors that could significantly affect internal
     controls subsequent to the date of our most recent evaluation, including
     any corrective actions with regard to significant deficiencies and material
     weaknesses.

Date: March 31, 2003.

                                        Donald E. Brandt
                                        ----------------------------------------
                                        Donald E. Brandt
                                        Senior Vice President and Chief
                                        Financial Officer

                                       177

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.1
<SEQUENCE>4
<FILENAME>ex4-1.txt
<DESCRIPTION>56TH SUPPLEMENTAL INDENTURE
<TEXT>
                                                                     Exhibit 4.1

================================================================================

                         ARIZONA PUBLIC SERVICE COMPANY
               (formerly Central Arizona Light and Power Company)

                                       TO

                              THE BANK OF NEW YORK


                                      AS TRUSTEE UNDER CENTRAL ARIZONA LIGHT AND
                                               POWER COMPANY'S MORTGAGE AND DEED
                                             OF TRUST, DATED AS OF JULY 1, 1946.


                                 ---------------


                       Fifty-Sixth Supplemental Indenture


                                 ---------------


                          DATED AS OF NOVEMBER 1, 2002


                       This Mortgage covers real property,
                         personal property and chattels.


              This instrument and the above-mentioned Mortgage and
           Deed of Trust contain after-acquired property provisions.

================================================================================
<PAGE>
                       FIFTY-SIXTH SUPPLEMENTAL INDENTURE

                                 ---------------

     INDENTURE, dated as of the 1st day of November, 2002, made and entered into
by and between  ARIZONA  PUBLIC SERVICE  COMPANY,  a corporation of the State of
Arizona,  the  principal  place of business and mailing  address of which is 400
North Fifth Street,  Phoenix,  Arizona 85004  (hereinafter  sometimes called the
Company),  party of the first part, and THE BANK OF NEW YORK, a New York banking
corporation,  the  mailing  address of which is 385 Rifle Camp Road,  3rd Floor,
West  Paterson,  New Jersey 07424  (hereinafter  sometimes  called the Trustee),
party of the second part, as Trustee under the Mortgage and Deed of Trust, dated
as of July 1,  1946  (hereinafter  called  the  Mortgage),  which  Mortgage  was
executed and  delivered by the Company  under its former name,  Central  Arizona
Light and Power  Company,  to secure the payment of bonds issued or to be issued
under and in accordance with the provisions of the Mortgage,  reference to which
said Mortgage is hereby made, this Indenture (hereinafter called the Fifty-sixth
Supplemental Indenture) being supplemental thereto;

     WHEREAS,  said  Mortgage was recorded and filed in Counties in the State of
Arizona as follows:

<TABLE>
<CAPTION>
                                                                              FILED AND ABSTRACTED
                                                RECORDED AS REAL MORTGAGE     AS CHATTEL MORTGAGE
                                               ---------------------------    --------------------
                                                                                 CHATTEL
                                                 DATE      BOOK OR              MORTGAGE
                    COUNTY                     RECORDED     DOCKET    PAGE        BOOK      PAGE
                    ------                     --------     ------    ----        ----      ----
<S>                                            <C>         <C>        <C>         <C>       <C>
     Apache...........................          7-28-50        16        1          9        154
     Cochise..........................           2-3-53        80       28         19        292
     Coconino.........................          1-20-53        39        1         10        286
     Gila.............................          1-17-53        32       84         17         --
     Graham...........................          12-3-63        92       87         15        223
     Maricopa.........................           8-6-46       408      163         92        204
     Mohave...........................         11-13-57        28       68         12         13
     Navajo...........................         10-14-49        31      483         16        521
     Pima.............................          1-24-53       558      351         14         --
     Pinal............................         10-25-52        68       31         12        591
     Yavapai..........................           8-7-46        79        1         12        223
     Yuma.............................           8-1-47        58      173         21        265

and in Counties in the State of New Mexico as follows:

     McKinley.........................          5-31-61        36      153          4        295

     San Juan.........................          1-31-61       472      140          (No. 72441)
</TABLE>

the copy  recorded  in Yuma  County,  Arizona  also being  effective  for La Paz
County,  Arizona,  formed on December 31, 1982; and copies of said Mortgage were
filed with the office of the Bureau of Indian  Affairs at Window Rock,  Arizona,
and with the Navajo Tribe of Indians at Window Rock, Arizona, and in the offices
of the Secretary of State and the State Land  Department of the State of Arizona
(all the said  counties  and the said  offices  above  referred to being  herein
referred to as "jurisdictions"); and

                                       2
<PAGE>
     WHEREAS, by the Mortgage,  the Company covenanted that it would execute and
deliver such supplemental  indenture or indentures and such further  instruments
and do such  further  acts as might be  necessary  or  proper  to carry out more
effectually  the purposes of the Mortgage and to make subject to the Lien of the
Mortgage any property thereafter  acquired,  made or constructed and intended to
be subject to the Lien thereof; and

     WHEREAS,  the Company has executed and delivered to the Trustee  fifty-five
indentures  supplemental to the Mortgage  (hereinafter  respectively  called the
First through the Fifty-fifth  Supplemental  Indentures) dated as of December 1,
1947,  April 1, 1949,  February  1, 1950,  December  1, 1950,  February 1, 1953,
November 1, 1953,  March 1, 1954,  October 1, 1957,  March 1, 1959,  November 1,
1961,  June 1, 1962,  December 1, 1962,  September  1, 1963,  September 1, 1967,
April 1, 1970, March 15, 1972,  April 1, 1974,  February 15, 1975, June 1, 1975,
November 15, 1975, April 15, 1977,  January 15, 1978, March 1, 1979, October 15,
1979, May 15, 1980,  February 2, 1982, April 15, 1982, July 1, 1983, October 15,
1983, June 15, 1984,  January 15, 1985, May 1, 1985,  June 1, 1985,  November 1,
1985,  January 15, 1986,  March 1, 1986, May 1, 1986,  February 1, 1987, June 1,
1987,  November 15, 1987, April 1, 1989,  February 15, 1990, May 15, 1990, April
15, 1991,  December 15, 1991,  January 15, 1992,  March 1, 1992,  June 15, 1992,
February 1, 1993, August 1, 1993,  August 1, 1993,  September 15, 1993, March 1,
1994,  November 15, 1996,  and April 1, 1997,  each of which has been or will be
recorded  or filed in, or a  recording  or filing is or will be  effective  with
respect to, each jurisdiction referred to above; and

     WHEREAS,  in  addition  to  the  property  described  in the  Mortgage,  as
heretofore  supplemented  and amended,  the Company has acquired  certain  other
property, rights and interests in property; and

     WHEREAS,  the  Company  has  heretofore  issued,  in  accordance  with  the
provisions of the Mortgage, as heretofore  supplemented and amended,  bonds of a
series  entitled and  designated  First Mortgage  Bonds,  2-3/4% Series due 1976
(hereinafter  called the bonds of the First Series),  in the aggregate principal
amount of Eight Million Five Hundred Thousand Dollars  ($8,500,000);  bonds of a
series  entitled and  designated  First Mortgage  Bonds,  3-1/8% Series due 1977
(hereinafter  called the bonds of the Second Series), in the aggregate principal
amount of Two Million Five Hundred  Thousand  Dollars  ($2,500,000);  bonds of a
series  entitled  and  designated  First  Mortgage  Bonds,  3%  Series  due 1979
(hereinafter  called the bonds of the Third Series),  in the aggregate principal
amount of Four  Million  Dollars  ($4,000,000);  bonds of a series  entitled and
designated First Mortgage Bonds,  2-3/4% Series due 1980 (hereinafter called the
bonds of the Fourth Series),  in the aggregate  principal amount of Five Million
Dollars  ($5,000,000);  bonds of a series entitled and designated First Mortgage
Bonds,  2-7/8%  Series  due 1980  (hereinafter  called  the  bonds of the  Fifth
Series), in the aggregate principal amount of Six Million Dollars  ($6,000,000);
bonds of a series entitled and designated  First Mortgage  Bonds,  3-1/2% Series
due 1983  (hereinafter  called the bonds of the Sixth Series),  in the aggregate
principal   amount  of  Fourteen   Million   Five   Hundred   Thousand   Dollars
($14,500,000); bonds of a series entitled and designated First Mortgage Bonds, 3
1/2% Series due  November 1, 1983  (hereinafter  called the bonds of the Seventh
Series),  in the  aggregate  principal  amount  of Five  Million  Seven  Hundred
Twenty-three  Thousand  Dollars  ($5,723,000);  bonds of a series  entitled  and
designated First Mortgage Bonds,  3-1/4% Series due 1984 (hereinafter called the
bonds of the  Eighth  Series),  in the  aggregate  principal  amount of  Fifteen
Million Dollars  ($15,000,000);  bonds of a series entitled and designated First
Mortgage  Bonds,  5-1/8%  Series due 1987  (hereinafter  called the bonds of the
Ninth Series),  in the aggregate  principal  amount of Fifteen  Million  Dollars
($15,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
4.70% Series due 1989 (hereinafter called the bonds of the Tenth Series), in the
aggregate principal amount of Twenty Million Dollars  ($20,000,000);  bonds of a
series  entitled and  designated  First  Mortgage  Bonds,  4.80% Series due 1991
(hereinafter  called  the  bonds  of the  Eleventh  Series),  in  the  aggregate
principal amount of Thirty-five Million Dollars ($35,000,000); bonds of a series
entitled and designated First Mortgage Bonds, 4.45% Series due 1992 (hereinafter
called the bonds of the Twelfth  Series),  in the aggregate  principal amount of

                                       3
<PAGE>
Twenty-five  Million  Dollars  ($25,000,000);  bonds  of a series  entitled  and
designated First Mortgage Bonds,  4.40% Series due 1992 (hereinafter  called the
bonds  of  the  Thirteenth   Series),  in  the  aggregate  principal  amount  of
Twenty-five  Million  Dollars  ($25,000,000);  bonds  of a series  entitled  and
designated First Mortgage Bonds,  4.50% Series due 1993 (hereinafter  called the
bonds of the Fourteenth  Series),  in the aggregate  principal amount of Fifteen
Million Dollars  ($15,000,000);  bonds of a series entitled and designated First
Mortgage  Bonds,  6.25%  Series  due 1997  (hereinafter  called the bonds of the
Fifteenth  Series),  in the aggregate  principal  amount of Twenty-five  Million
Dollars ($25,000,000);  bonds of a series entitled and designated First Mortgage
Bonds,  8.50%  Series due 1975  (hereinafter  called the bonds of the  Sixteenth
Series),   in  the  aggregate   principal   amount  of  Thirty  Million  Dollars
($30,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
7.45% Series due 2002 (hereinafter called the bonds of the Seventeenth  Series),
in the aggregate principal amount of Sixty Million Dollars ($60,000,000);  bonds
of a series entitled and designated First Mortgage Bonds,  6.20% Series due 2004
(hereinafter  called  the  bonds of the  Eighteenth  Series),  in the  aggregate
principal  amount  of Fifty  Million  Dollars  ($50,000,000);  bonds of a series
entitled and designated First Mortgage Bonds, 9.50% Series due 1982 (hereinafter
called the bonds of the Nineteenth Series), in the aggregate principal amount of
One Hundred  Million  Dollars  ($100,000,000);  bonds of a series  entitled  and
designated First Mortgage Bonds,  9.80% Series due 1980 (hereinafter  called the
bonds  of  the  Twentieth  Series),   in  the  aggregate   principal  amount  of
Seventy-five  Million  Dollars  ($75,000,000);  bonds of a series  entitled  and
designated First Mortgage Bonds, 10.625% Series due 2000 (hereinafter called the
bonds  of  the  Twenty-first  Series),  in the  aggregate  principal  amount  of
Seventy-five  Million  Dollars  ($75,000,000);  bonds of a series  entitled  and
designated First Mortgage Bonds, 6.45% Series A due 2007 (hereinafter called the
bonds  of the  Twenty-second  Series),  in the  aggregate  principal  amount  of
Thirteen  Million  Dollars  ($13,000,000);   bonds  of  a  series  entitled  and
designated First Mortgage Bonds, 6.45% Series B due 2007 (hereinafter called the
bonds of the Twenty-third  Series),  in the aggregate principal amount of Thirty
Million Dollars  ($30,000,000);  bonds of a series entitled and designated First
Mortgage  Bonds,  6%  Series A due 2008  (hereinafter  called  the  bonds of the
Twenty-fourth  Series), in the aggregate principal amount of Thirty-four Million
Dollars ($34,000,000);  bonds of a series entitled and designated First Mortgage
Bonds,  9.95% Series due 2004 (hereinafter  called the bonds of the Twenty-fifth
Series),  in the aggregate  principal  amount of  Seventy-five  Million  Dollars
($75,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
12-1/8%  Series  due 2009  (hereinafter  called  the  bonds of the  Twenty-sixth
Series),  in the aggregate  principal  amount of  Seventy-five  Million  Dollars
($75,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
12-7/8%  Series due 2000  (hereinafter  called  the bonds of the  Twenty-seventh
Series),  in the aggregate  principal amount of One Hundred  Eighty-five Million
Dollars ($185,000,000); bonds of a series entitled and designated First Mortgage
Bonds,   10-3/8%  Series  due  1985   (hereinafter   called  the  bonds  of  the
Twenty-eighth  Series),  in the aggregate  principal amount of Sixty Million Two
Hundred Fifty Thousand  Dollars  ($60,250,000);  bonds of a series  entitled and
designated  First Mortgage Bonds,  16% Series due 1992  (hereinafter  called the
bonds of the  Twenty-ninth  Series),  in the aggregate  principal  amount of One
Hundred  Million  Dollars  ($100,000,000);   bonds  of  a  series  entitled  and
designated First Mortgage Bonds, 12-3/4% Series due 2013 (hereinafter called the
bonds of the Thirtieth Series), in the aggregate principal amount of One Hundred
Million Dollars ($100,000,000);  bonds of a series entitled and designated First
Mortgage  Bonds,  13-1/2% Series due 2013  (hereinafter  called the bonds of the
Thirty-first Series),  in the aggregate  principal amount of One Hundred Million
Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage
Bonds, 15% Series due 1994  (hereinafter  called the bonds of the  Thirty-second
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
12% Series due 1995 (hereinafter  called the bonds of the Thirty-third  Series),
in the aggregate  principal  amount of One Hundred  Twenty-five  Million Dollars
($125,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
13-1/4%  Series  due 2007  (hereinafter  called  the bonds of the  Thirty-fourth
Series),   in  the  aggregate   principal   amount  of  Fifty  Million   Dollars
($50,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
11-1/2%  Series  due 2015  (hereinafter  called  the  bonds of the  Thirty-fifth
Series),  in the aggregate principal amount of One Hundred Fifty Million Dollars

                                       4
<PAGE>
($150,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
11-1/2%  Series  due  November  1,  2015  (hereinafter  called  the bonds of the
Thirty-sixth  Series),  in the aggregate principal amount of One Hundred Million
Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage
Bonds, 11% Series due 2016 (hereinafter  called the bonds of the  Thirty-seventh
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
9-1/4%  Series  due 1996  (hereinafter  called  the  bonds of the  Thirty-eighth
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
9% Series due 1996 (hereinafter called the bonds of the Thirty-ninth Series), in
the  aggregate  principal  amount of One  Hundred  Twenty-five  Million  Dollars
($125,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
9% Series due 2017 (hereinafter called the bonds of the Fortieth Series), in the
aggregate principal amount of One Hundred Fifty Million Dollars  ($150,000,000);
bonds of a series entitled and designated  First Mortgage  Bonds,  9-7/8% Series
due 1997  (hereinafter  called  the  bonds of the  Forty-first  Series),  in the
aggregate   principal  amount  of  One  Hundred   Twenty-five   Million  Dollars
($125,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
10-3/4%  Series  due 2017  (hereinafter  called  the  bonds of the  Forty-second
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
10-3/4%  Series  due 2019  (hereinafter  called  the  bonds  of the  Forty-third
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
10-1/4%  Series  due 2000  (hereinafter  called  the  bonds of the  Forty-fourth
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
10 1/4%  Series  due 2020  (hereinafter  called  the  bonds  of the  Forty-fifth
Series),  in the aggregate  principal amount of One Hundred  Twenty-five Million
Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage
Bonds,  9-1/2% Series due 2021 (hereinafter  called the bonds of the Forty-sixth
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
9% Series due 2021 (hereinafter  called the bonds of the Forty-seventh  Series),
in  the  aggregate  principal  amount  of  One  Hundred  Fifty  Million  Dollars
($150,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
7-1/8% Series due 1997, in the aggregate  principal  amount of One Hundred Fifty
Million  Dollars  ($150,000,000),  and bonds of a series entitled and designated
First Mortgage Bonds,  8-3/4% Series due 2024, in the aggregate principal amount
of  One  Hundred  Seventy-five  Million  Dollars   ($175,000,000)   (hereinafter
collectively  called the bonds of the  Forty-eighth  Series);  bonds of a series
entitled and  designated  First Mortgage  Bonds,  7-5/8% Series due 1998, in the
aggregate  principal amount of One Hundred Million Dollars  ($100,000,000),  and
bonds of a series entitled and designated  First Mortgage  Bonds,  8-1/8% Series
due 2002, in the aggregate  principal amount of One Hundred  Twenty-five Million
Dollars  ($125,000,000)  (hereinafter  collectively  called  the  bonds  of  the
Forty-ninth  Series);  bonds of a series entitled and designated  First Mortgage
Bonds,  7-5/8%  Series due 1999  (hereinafter  called the bonds of the  Fiftieth
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
8% Series due 2025 (hereinafter called the bonds of the Fifty-first  Series), in
the  aggregate   principal   amount  of  One  Hundred   Fifty  Million   Dollars
($150,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
7-1/4%  Series  due 2023  (hereinafter  called  the  bonds  of the  Fifty-second
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
5-7/8% Series due 2028 (hereinafter called bonds of the Fifty-third  Series), in
the aggregate  principal  amount of Twelve  Million Eight Hundred Fifty Thousand
Dollars ($12,850,000);  bonds of a series entitled and designated First Mortgage
Bonds,  5-7/8%  Series due 2028  (hereinafter  called bonds of the  Fifty-fourth
Series),  in the aggregate principal amount of One Hundred Forty-one Million One
Hundred Fifty Thousand  Dollars  ($141,150,000);  bonds of a series entitled and
designated  First Mortgage  Bonds,  5-1/2% Series due 2028  (hereinafter  called
bonds  of  the  Fifty-fifth  Series),  in  the  aggregate  principal  amount  of
Twenty-five  Million  Dollars  ($25,000,000);  bonds  of a series  entitled  and
designated  First Mortgage  Bonds,  5-3/4% Series due 2000  (hereinafter  called

                                       5
<PAGE>
bonds of the  Fifty-sixth  Series)  in the  aggregate  principal  amount  of One
Hundred  Million  Dollars  ($100,000,000);   bonds  of  a  series  entitled  and
designated  First Mortgage  Bonds,  6-5/8% Series due 2004  (hereinafter  called
bonds of the  Fifty-seventh  Series) in the  aggregate  principal  amount of One
Hundred  Million  Dollars  ($100,000,000);   bonds  of  a  series  entitled  and
designated First Mortgage Bonds,  Senior Note Series A (hereinafter called bonds
of the  Fifty-eighth  Series) in the aggregate  principal  amount of One Hundred
Million  Dollars  ($100,000,000);  and bonds of a series entitled and designated
First  Mortgage  Bonds,  Senior Note Series B  (hereinafter  called bonds of the
Fifth-ninth  Series) in the aggregate  principal amount of Fifty Million Dollars
($50,000,000); and

     WHEREAS, said The Bank of New York, by an instrument in writing,  effective
on the opening of business on September  29, 1995,  succeeded to Bank of America
National  Trust and Savings  Association  as Trustee  under the  Mortgage;  and,
pursuant to Section 104 of the  Mortgage,  The Bank of New York is the successor
Trustee under the Mortgage; and

     WHEREAS, Section 8 of the Mortgage provides that the form of each series of
bonds  (other  than  bonds  of the  First  Series)  issued  thereunder  shall be
established  by Resolution of the Board of Directors of the Company and that the
form of each series,  as established  by said Board of Directors,  shall specify
the descriptive title of the bonds and various other terms thereof, and may also
contain such provisions not inconsistent  with the provisions of the Mortgage as
the Board of  Directors  may, in its  discretion,  cause to be inserted  therein
expressing or referring to the terms and conditions upon which such bonds are to
be issued and/or secured under the Mortgage; and

     WHEREAS, Section 120 of the Mortgage provides, among other things, that any
power,  privilege  or right  expressly  or  impliedly  reserved to or in any way
conferred upon the Company by any provision of the Mortgage, whether such power,
privilege or right is in any way restricted or is unrestricted,  may be in whole
or in part waived or surrendered or subjected to any  restriction if at the time
unrestricted or to additional restriction if already restricted, and the Company
may enter  into any  further  covenants,  limitations  or  restrictions  for the
benefit of any one or more series of bonds issued thereunder, or the Company may
cure any ambiguity contained therein, or in any supplemental  indenture,  or may
establish the terms and  provisions of any series of bonds other than said First
Series,  by an instrument in writing executed and acknowledged by the Company in
such  manner as would be  necessary  to entitle a  conveyance  of real estate to
record in all of the  states in which any  property  at the time  subject to the
Lien of the Mortgage shall be situated; and

     WHEREAS,  the  Company  now  desires  to create a new series of bonds to be
issued under and pursuant to the Mortgage in accordance  with the  provisions of
Article VI thereof,  and to add to its covenants and agreements contained in the
Mortgage,  as heretofore  supplemented and amended,  certain other covenants and
agreements  to be observed by it and to alter and amend in certain  respects the
covenants and provisions contained in the Mortgage,  as heretofore  supplemented
and amended; and

     WHEREAS,  the  Company  has  entered  into a Loan  Agreement,  dated  as of
November 1, 2002 (as amended from time to time,  the "Loan  Agreement")  between
the Company and Maricopa  County,  Arizona  Pollution  Control  Corporation (the
"Issuer"),  and the Issuer has issued the  Maricopa  County,  Arizona  Pollution
Control  Corporation  Pollution  Control Revenue Refunding Bonds (Arizona Public
Service  Company Palo Verde  Project) 2002 Series A in the  aggregate  principal
amount of  $90,000,000  (the  "Series A  Pollution  Control  Bonds")  under that
certain  Indenture of Trust,  dated as of November 1, 2002 (as amended from time
to time, the "Maricopa  Indenture") between the Issuer and The Bank of New York,
as  Trustee  (together  with its  successors  in such  capacity,  the  "Maricopa
Trustee");

     WHEREAS,  the Company has agreed to issue Ninety Million  ($90,000,000)  in
aggregate  principal  amount of its 5.05% Senior Notes  (Maricopa 2002 Series A)
due 2029 (the  "Series A Senior  Notes") in  support  of the Series A  Pollution

                                       6
<PAGE>
Control Bonds,  pursuant to the provisions of the Indenture dated as of November
15, 1996 (the "Senior Note Indenture"),  between the Company and The Bank of New
York, as trustee  (said  trustee or any successor  trustee under the Senior Note
Indenture  being  hereinafter  referred to as the  "Senior  Note  Trustee"),  as
supplemented by the First Supplemental Indenture, dated as of November 15, 1996,
the  Second  Supplemental  Indenture  dated as of April 1,  1997,  and the Third
Supplemental Indenture dated as of November 1, 2002, between the Company and the
Senior Note Trustee; and

     WHEREAS,  in order to secure the Company's  obligation to pay principal and
interest on the Series A Senior Notes prior to the Release Date (as  hereinafter
defined),  the Company desires to provide for the issuance under the Mortgage to
the Senior  Note  Trustee of a new series of bonds  designated  "First  Mortgage
Bonds, Senior Note Series C," having the same rate of interest, interest payment
dates,  maturity  date  and  redemption  provisions  and in the  same  aggregate
principal amount as the Series A Senior Notes; and

     WHEREAS,  the  execution  and  delivery by the Company of this  Fifty-sixth
Supplemental  Indenture,  and the  terms  of the  bonds of the  Sixtieth  Series
hereinafter  referred to, have been duly authorized by the Board of Directors of
the Company by appropriate Resolutions of said Board of Directors;

     NOW  THEREFORE,  THIS  INDENTURE  WITNESSETH:  That Arizona  Public Service
Company,  in  consideration of the premises and of One Dollar to it duly paid by
the  Trustee at or before the  ensealing  and  delivery of these  presents,  the
receipt whereof is hereby acknowledged,  and in further evidence of assurance of
the estate,  title and rights of the Trustee and in order  further to secure the
payment of both the principal of and interest and premium,  if any, on the bonds
from time to time  heretofore,  herewith or hereafter issued under the Mortgage,
according to their tenor and effect,  and the  performance of all the provisions
of  the  Mortgage  (including  any  instruments  supplemental  thereto  and  any
modifications  made  as in the  Mortgage  provided)  and of said  bonds,  hereby
grants,  bargains,  sells, releases,  conveys,  assigns,  transfers,  mortgages,
pledges,  sets over and confirms (subject,  however, to Excepted Encumbrances as
defined in Section 6 of the Mortgage and to the liens permitted by Section 36 of
the Mortgage)  unto The Bank of New York, as Trustee under the Mortgage,  and to
its  successor  or  successors  in  said  trust,  and to  said  Trustee  and its
successors and assigns forever,  all the properties of the Company  described in
the Mortgage,  as heretofore  supplemented  and amended  (except any  properties
which have been released from the Lien of the Mortgage),  and all the properties
specifically described in Article V hereof.

     Also all other  property,  real,  personal and mixed, of the kind or nature
specifically  mentioned  in  Article  V hereof  or of any  other  kind or nature
(except any herein or in the Mortgage,  as heretofore  supplemented and amended,
expressly excepted and except any which may not lawfully be mortgaged or pledged
hereunder), now owned or, subject to the provisions of subsection (I) of Section
87  of  the   Mortgage,   hereafter   acquired  by  the  Company  (by  purchase,
consolidation, merger, donation, construction, erection or in any other way) and
wheresoever situated, including (without in anywise limiting or impairing by the
enumeration  of the same the scope and intent of the foregoing or of any general
description  contained in this  Fifty-sixth  Supplemental  Indenture) all lands,
power  sites,   flowage   rights,   water   rights,   water   locations,   water
appropriations,  ditches, flumes, reservoirs, reservoir sites, canals, raceways,
dams,  dam sites,  aqueducts,  and all other rights or means for  appropriating,
conveying,  storing and supplying water; all rights of way and roads; all plants
for the generation of electricity by steam,  water and/or other power; all power
houses,  gas plants,  street  lighting  systems,  standards and other  equipment
incidental thereto,  telephone,  radio and television systems,  air-conditioning
systems and equipment incidental thereto, water works, water systems, steam heat
and hot water plants,  substations,  lines, service and supply systems, bridges,
culverts, tracks, ice or refrigeration plants and equipment,  offices, buildings
and other structures and equipment  thereof;  all machinery,  engines,  boilers,
dynamos,  electric, gas and other machines,  regulators,  meters,  transformers,

                                       7
<PAGE>
generators, motors, electrical, gas and mechanical appliances, conduits, cables,
water,  steam heat,  gas or other  pipes,  gas mains and pipes,  service  pipes,
fittings,  valves and connections,  pole and transmission lines, wires,  cables,
tools, implements,  apparatus, furniture and chattels; all franchises,  consents
or permits; all lines for the transmission and distribution of electric current,
gas, steam heat or water for any purpose including towers, poles, wires, cables,
pipes,  conduits,  ducts and all apparatus for use in connection therewith;  all
real  estate,  lands,  easements,  servitudes,  licenses,  permits,  franchises,
privileges,  rights of way and other  rights in or relating to public or private
property,  real or personal,  or the  occupancy of such  property and (except as
herein or in the Mortgage,  as heretofore  supplemented  and amended,  expressly
excepted)  all the  right,  title  and  interest  the  Company  may now  have or
hereafter  acquire  in and to any  and  all  property  of  any  kind  or  nature
appertaining  to and/or used and/or  occupied  and/or enjoyed in connection with
any property  hereinbefore or in the Mortgage,  as heretofore  supplemented  and
amended, described.

     TOGETHER WITH all and singular the tenements, hereditaments, prescriptions,
servitudes  and  appurtenances  belonging  or in  anywise  appertaining  to  the
aforementioned  property or any part thereof, with the reversion and reversions,
remainder  and  remainders  and (subject to the  provisions of Section 57 of the
Mortgage) the tolls, rents,  revenues,  issues,  earnings,  income,  product and
profits  thereof,  and  all  the  estate,   right,  title,  interest  and  claim
whatsoever,  at law as well  as in  equity,  which  the  Company  now has or may
hereafter acquire in and to the aforementioned property and franchises and every
part and parcel thereof.

     IT IS HEREBY  AGREED by the  Company  that,  subject to the  provisions  of
subsection (I) of Section 87 of the Mortgage and to the extent permitted by law,
all the property,  rights and  franchises  acquired by the Company (by purchase,
consolidation,  merger,  donation,  construction,  erection or in any other way)
after the date  hereof,  except any  herein or in the  Mortgage,  as  heretofore
supplemented and amended,  expressly excepted, shall be and are as fully granted
and conveyed hereby and as fully embraced within the lien hereof and the Lien of
the Mortgage as if such property,  rights and  franchises  were now owned by the
Company and were specifically described herein and conveyed hereby.

     PROVIDED  that  the  following  are not and are not  intended  to be now or
hereafter granted, bargained, sold, released, conveyed,  assigned,  transferred,
mortgaged,  pledged,  set over or confirmed  hereunder and are hereby  expressly
excepted from the lien and operation of this Fifty-sixth  Supplemental Indenture
and from the Lien and  operation  of the  Mortgage,  viz.:  (1) cash,  shares of
stock,  bonds,  notes and other  obligations and other  securities not hereafter
specifically pledged,  paid, deposited,  delivered or held under the Mortgage or
covenanted  so to  be;  (2)  merchandise,  equipment,  apparatus,  materials  or
supplies held for the purpose of sale or other  disposition  in the usual course
of business;  fuel,  oil and similar  materials  and supplies  consumable in the
operation  of any of the  properties  of  the  Company;  construction  equipment
acquired for  temporary  use; all aircraft,  tractors,  rolling  stock,  trolley
coaches, buses, motor coaches, automobiles,  motor trucks and other vehicles and
materials  and supplies held for the purpose of repairing or replacing (in whole
or part) any of the same; all timber, minerals, mineral rights and royalties and
all  Natural  Gas and Oil  Production  Property,  as defined in Section 4 of the
Mortgage;  (3) bills,  notes and  accounts  receivable,  judgments,  demands and
chooses in  action,  and all  contracts,  leases and  operating  agreements  not
specifically pledged under the Mortgage or covenanted so to be; (4) the last day
of the term of any lease or leasehold which may be or become subject to the Lien
of the Mortgage;  (5) electric  energy,  gas, steam,  ice and other materials or
products generated, manufactured, produced, purchased or acquired by the Company
for sale,  distribution or use in the ordinary  course of its business;  and (6)
the  Company's  franchise  to be a  corporation;  PROVIDED,  HOWEVER,  that  the
property  and  rights  expressly  excepted  from the Lien and  operation  of the
Mortgage in the above subdivisions (2) and (3) shall (to the extent permitted by
law) cease to be so excepted in the event and as of the date that the Trustee or
a receiver or trustee shall enter upon and take  possession of the Mortgaged and

                                       8
<PAGE>
Pledged  Property  in the manner  provided  in Article  XIII of the  Mortgage by
reason of the occurrence of a Default as defined in Section 65 thereof.

     TO HAVE AND TO HOLD all such properties, real, personal and mixed, granted,
bargained, sold, released, conveyed, assigned, transferred,  mortgaged, pledged,
set over or  confirmed by the Company as  aforesaid,  or intended so to be, unto
The Bank of New York, the Trustee, and its successors and assigns forever.

     IN TRUST  NEVERTHELESS,  for the  same  purposes  and upon the same  terms,
trusts and conditions and subject to and with the same provisos and covenants as
are set forth in the Mortgage, as supplemented and amended.

     AND IT IS HEREBY COVENANTED by the Company that all the terms,  conditions,
provisos,  covenants and provisions  contained in the Mortgage,  as supplemented
and amended,  shall affect and apply to the property hereinbefore  described and
conveyed and to the estate,  rights,  obligations  and duties of the Company and
the Trustee and the  beneficiaries  of the trust with respect to said  property,
and to the Trustee and its  successors  as Trustee of said  property in the same
manner and with the same  effect as if the said  property  had been owned by the
Company at the time of the  execution of the Mortgage and had been  specifically
and at length  described  in and  conveyed to said  Trustee by the Mortgage as a
part of the property therein stated to be conveyed.

     The Company  further  covenants  and agrees to and with the Trustee and its
successors in said trust under the Mortgage, as follows:

                                   ARTICLE I.
                            SIXTIETH SERIES OF BONDS.

     SECTION  1. There  shall be a series of bonds  designated  "First  Mortgage
Bonds, Senior Note Series C" (hereinafter sometimes referred to as the "Sixtieth
Series" or the "Senior Note Series C Bonds"), limited to the aggregate principal
amount of $90,000,000, each of which shall also bear the descriptive title First
Mortgage Bond, and the form thereof, which shall be established by Resolution of
the Board of Directors of the Company,  shall contain  suitable  provisions with
respect to the matters  hereinafter  specified in this  Supplemental  Indenture.
Bonds of the  Sixtieth  Series  shall be dated as  provided in Section 10 of the
Mortgage;   shall  mature,  subject  to  the  provisions  for  prior  redemption
hereinafter  set  forth,  on May 1,  2029;  shall be  issued  as a single  fully
registered bond, and shall be registered in the name of the Senior Note Trustee;
and shall bear interest  from November 1, 2002 or from the most recent  Interest
Payment Date (as defined  below) to which  interest has been paid at the rate of
5.05% per annum  (calculated  on the  basis of a 360-day  year of twelve  30-day
months), payable on May 1 and November 1 of each year (each an "Interest Payment
Date"), commencing May 1, 2003, to the holders thereof of record on the April 15
or October 15, as the case may be, next  preceding  such  Interest  Payment Date
(subject  to the  provisions  of Section  12 of the  Mortgage  concerning  legal
holidays  and bank  closings),  and the  principal  of and interest on, or other
amounts, if any, payable upon redemption of, each said bond to be payable at the
office or agency of the  Company in the  Borough of  Manhattan,  The City of New
York,  New York, in such coin or currency of the United States of America as, at
the time of payment, is legal tender for public and private debts.

     Notwithstanding  the above,  to the extent  required  in Section 4.2 of the
Loan Agreement at any time, all payments of interest on an Interest Payment Date
and of principal on the maturity  date of the Senior Note Series C Bonds will be
due and payable not less than two (2) Business  Days (as defined in the Maricopa
Indenture) prior to each such Interest Payment Date and such maturity date.

                                       9
<PAGE>
     The Company  shall have no  obligation to make payments with respect to the
principal  and/or  interest on the Senior Note Series C Bonds  unless and until,
and only to the extent that,  payments shall be due and payable  pursuant to the
Series A Senior  Notes,  and the  Company's  obligation  to make  payments  with
respect to the principal and/or interest on the Senior Note Series C Bonds shall
be fully or  partially,  as the case may be,  satisfied  and  discharged  to the
extent that, at the time that any such payment  shall be due, the  corresponding
amount of  principal  of and/or  interest  then due on the Series A Senior Notes
shall have been fully or partially paid, as the case may be, or there shall have
been  deposited  with the Senior Note Trustee  pursuant to Section 501,  Section
1103, or Section 1205 of the Senior Note Indenture trust funds  sufficient under
the  provisions of said Sections to fully or partially  pay, as the case may be,
the  corresponding  amount of principal and/or interest then due on the Series A
Senior Notes.

     SECTION 2. Upon payment of the  principal of and interest due on the Series
A Senior  Notes,  whether at  maturity or prior to  maturity  by  redemption  or
otherwise,  or upon  provision  for the  payment  thereof  having  been  made in
accordance with Section 501 or Section 1402 of the Senior Note Indenture, Senior
Note  Series C Bonds in a  principal  amount  equal to the  principal  amount of
Series A Senior Notes so paid or for which such  provision  for payment has been
made shall be deemed fully paid, satisfied and discharged and the obligations of
the Company  thereunder  shall be terminated and such Senior Note Series C Bonds
shall be surrendered  to and cancelled by the Trustee.  From and after such date
as all bonds issued under the  Mortgage  (other than Senior Note First  Mortgage
Bonds,  as such term is defined in the Senior Note  Indenture) have been retired
through payment,  redemption,  or otherwise at, before or after maturity thereof
(the "Release Date"), the Senior Note Series C Bonds shall be deemed fully paid,
satisfied and discharged and the obligation of the Company  thereunder  shall be
terminated. On the Release Date, subject to the conditions of Section 407 of the
Senior Note  Indenture,  the Senior Note Series C Bonds shall be  surrendered to
and cancelled by the Trustee.

     SECTION 3. Bonds of the  Sixtieth  Series  shall be held by the Senior Note
Trustee and shall not be  transferable  except to its permitted  successors  and
assigns.  The Senior  Note  Trustee,  as the holder of the Senior  Note Series C
Bonds,  shall attend  meetings of bondholders  under the Mortgage or deliver its
proxy in connection  therewith.  Either at such meeting,  or otherwise  when the
consent of the  holders of the Senior  Note  Series C Bonds is sought  without a
meeting,  the Senior  Note  Trustee  shall vote as the holder of the Senior Note
Series C Bonds, or shall consent with respect thereto;  provided,  however, that
the  Senior  Note  Trustee  shall  not vote in favor  of,  or  consent  to,  any
modification  of the Mortgage  which is  correlative  to a  modification  of the
Maricopa  Indenture or the Loan  Agreement  which would  require the approval of
owners of Series A Pollution Control Bonds without the approval of the owners of
Series A Pollution  Control  Bonds which would be required for such  correlative
modification of such Maricopa Indenture or Loan Agreement.

                                   ARTICLE II.
          REDEMPTION OF SENIOR NOTE SERIES C BONDS AND OTHER PROVISIONS

     The Senior Note Series C Bonds shall be redeemed, in whole or in part, from
time to time, on the date on which a corresponding  principal amount of Series A
Senior  Notes is redeemed as  provided  in the Senior  Note  Indenture  upon the
Senior  Note  Trustee's  notification  of the Trustee of such  redemption,  at a
redemption  price equal to the  redemption  price of such Series A Senior  Notes
being so  redeemed.  Any such  notice  shall be received by the Trustee no later
than 5 days prior to any  redemption  date fixed for the  Senior  Note  Series C
Bonds to be redeemed and shall specify the principal  amount of such Senior Note
Series C Bonds to be redeemed,  the  redemption  date, and the amount of accrued
interest to be paid thereon. The Company shall deposit in trust with the Trustee
on the redemption date an amount of money sufficient to pay the principal amount
plus accrued interest, if any, on the Senior Note Series C Bonds to be redeemed.
Upon presentation to the Trustee of any Senior Note Series C Bonds by the Senior
Note Trustee for payment  under this Article II, such Senior Note Series C Bonds
so presented shall be redeemed and paid in full to the extent so redeemed.

                                       10
<PAGE>
     In the event the principal of all Series A Senior Notes is declared due and
payable or becomes  automatically due and payable pursuant to Section 602 of the
Senior Note Indenture,  upon the filing with the Trustee of a written demand for
the  acceleration of the payment of principal of all Senior Note Series C Bonds,
the  payment  of  principal  on all  Senior  Note  Series C Bonds  shall  become
immediately  due and payable and the  Trustee  shall  provide to the Senior Note
Trustee an irrevocable,  valid and  unconditional  notice of acceleration of all
Senior Note Series C Bonds.

     Redemption  of the Senior Note Series C Bonds  shall be  effected,  without
further  notice by the Company to the Trustee,  by the payment by the Company of
the  applicable  redemption  price  specified  in this  Article  II at the place
specified for payment of principal of and interest on such bonds.

     The  Senior  Note  Series C Bonds  will not be  subject  to  prepayment  or
redemption  prior to maturity  except as provided  herein,  notwithstanding  the
provisions  of Section 39 or Section 64 of the  Mortgage,  or with  "Proceeds of
Released Property," as defined in the Mortgage.

     The Senior Note Series C Bonds will not be subject to any sinking fund.

     The Company  covenants and agrees that,  prior to Release Date, it will not
take any action  (except as required by this Article II hereof) that would cause
the  outstanding  principal  amount of the Senior Note Series C Bonds to be less
than the then outstanding principal amount of the Series A Senior Notes.


                                  ARTICLE III.
             REPLACEMENT FUND PROVISIONS -- OTHER RELATED PROVISIONS
             OF THE MORTGAGE -- DIVIDEND COVENANT -- RECORD DATES --
                              AUTHENTICATING AGENT.

     SECTION 4. The Company  covenants  that the provisions of Section 39 of the
Mortgage,  which  were to  remain  in  effect  so long as any bonds of the First
Series  remained  Outstanding,  shall remain in full force and effect so long as
any bonds of the Sixtieth Series are Outstanding.

     Clause (d) of subsection  (II) of Section 4 of the Mortgage,  as heretofore
amended,  clause (6) and clause (e) of Section 5 of the Mortgage,  as heretofore
amended,  and Section 29 of the  Mortgage,  as  heretofore  amended,  are hereby
further amended by inserting  therein the words "and Sixtieth  Series" after the
words "bonds of the First  Series and Second  Series and Third Series and Fourth
Series and Fifth  Series and Sixth Series and Seventh  Series and Eighth  Series
and Ninth  Series and Tenth Series and  Eleventh  Series and Twelfth  Series and
Thirteenth  Series and  Fourteenth  Series and  Fifteenth  Series and  Sixteenth
Series and Seventeenth  Series and Eighteenth  Series and Nineteenth  Series and
Twentieth  Series  and  Twenty-first   Series  and   Twenty-second   Series  and
Twenty-third  Series  and  Twenty-fourth  Series  and  Twenty-fifth  Series  and
Twenty-sixth  Series  and  Twenty-seventh  Series and  Twenty-eighth  Series and
Twenty-ninth   Series  and  Thirtieth   Series  and   Thirty-first   Series  and
Thirty-second  Series  and  Thirty-third  Series  and  Thirty-fourth  Series and
Thirty-fifth  Series  and  Thirty-sixth  Series  and  Thirty-seventh  Series and
Thirty-eighth Series and Thirty-ninth Series and Fortieth Series and Forty-first
Series and Forty-second  Series and Forty-third  Series and Forty-fourth  Series
and  Forty-fifth  Series and  Forty-sixth  Series and  Forty-seventh  Series and
Forty-eighth  Series and Forty-ninth  Series and Fiftieth Series and Fifty-first
Series and Fifty-second  Series and Fifty-third  Series and Fifty-fourth  Series
and Fifty-fifth  Series and Fifty-sixth  Series,  and  Fifty-seventh  Series and
Fifty-eighth Series and Fifty-ninth" each time such words occur therein.

                                       11
<PAGE>
     Clause (e) of subsection  (II) of Section 4 of the Mortgage,  as heretofore
amended, is hereby further amended by the insertion therein after the words "and
Fifty-ninth" the words "and Sixtieth."

     The last  paragraph of Section 12 of the Mortgage,  as heretofore  amended,
the last paragraph of Section 17 of the Mortgage, as heretofore amended, and the
last paragraph of Section 110 of the Mortgage, as heretofore amended, are hereby
amended by inserting  therein the words "or the Sixtieth Series" after the words
"Fifty-ninth Series" each time such words occur therein.

                                   ARTICLE IV.
                            MISCELLANEOUS PROVISIONS.

     SECTION 5. The terms defined in the Mortgage,  as supplemented and amended,
shall, for all purposes of this  Fifty-sixth  Supplemental  Indenture,  have the
meanings specified therein,  except that the term "Mortgage" shall mean only the
original  Mortgage  and  Deed of  Trust,  dated  as of July 1,  1946;  the  term
"Mortgage,  as heretofore  supplemented and amended" shall mean the Mortgage, as
supplemented  and  amended  by  the  First  through   Fifty-fifth   Supplemental
Indentures hereinabove referred to; and the term "Mortgage,  as supplemented and
amended,"  shall mean the  Mortgage,  as  supplemented  and amended by the First
through  Fifty-fifth  Supplemental  Indentures  hereinabove  referred  to and as
supplemented  and amended by this  Fifty-sixth  Supplemental  Indenture  and any
future supplemental indentures.

     SECTION 6. The Trustee hereby accepts the trusts herein declared, provided,
created,  supplemented  or amended and agrees to perform the same upon the terms
and  conditions  herein and in the  Mortgage,  as  heretofore  supplemented  and
amended, set forth and upon the following terms and conditions:

     The Trustee shall not be  responsible  in any manner  whatsoever  for or in
respect  of  the  validity  or  sufficiency  of  this  Fifty-sixth  Supplemental
Indenture or for or in respect of the recitals  contained  herein,  all of which
recitals  are made by the Company  solely.  In general,  each and every term and
condition contained in Article XVII of the Mortgage shall apply to and form part
of this Fifty-sixth  Supplemental Indenture with the same force and effect as if
the same were  herein  set forth in full with  such  omissions,  variations  and
insertions,  if any,  as may be  appropriate  to make  the same  conform  to the
provisions of this Fifty-sixth Supplemental Indenture.

     SECTION 7. Whenever in this  Fifty-sixth  Supplemental  Indenture either of
the  parties  hereto  is  named or  referred  to,  this  shall,  subject  to the
provisions  of Articles XVI and XVII of the  Mortgage,  be deemed to include the
successors  and assigns of such party,  and all the covenants and  agreements in
this Fifty-sixth Supplemental Indenture contained by or on behalf of the Company
or by or on behalf of the Trustee shall, subject as aforesaid, bind and inure to
the  respective  benefits  of the  respective  successors  and  assigns  of such
parties, whether so expressed or not.

     SECTION 8. Nothing in this Fifty-sixth Supplemental Indenture, expressed or
implied,  is intended or shall be construed  to confer upon,  or to give to, any
person,  firm or  corporation,  other than the parties hereto and the holders of
the bonds Outstanding under the Mortgage, any right, remedy or claim under or by
reason of this Fifty-sixth  Supplemental  Indenture or any covenant,  condition,
stipulation,  promise or agreement  hereof,  and all the covenants,  conditions,
stipulations, promises and agreements in this Fifty-sixth Supplemental Indenture
contained  by or on behalf of the  Company  shall be for the sole and  exclusive
benefit of the parties hereto and of the holders of the bonds  Outstanding under
the Mortgage.

                                       12
<PAGE>
     SECTION  9.  This  Fifty-sixth   Supplemental  Indenture  may  be  executed
simultaneously in several  counterparts,  each of which shall be an original and
all of which shall constitute but one and the same instrument.

                                   ARTICLE V.
                        SPECIFIC DESCRIPTION OF PROPERTY.

     SECTION 10. CERTAIN REAL PROPERTY LOCATED IN:

                                  APACHE COUNTY

                            EAST HOLBROOK SUBSTATION

PARCEL NO. 1:

That certain  parcel of land  situated in the  Southwest  quarter of Section 20,
Township 19 North,  Range 24 East of the Gila and Salt River Base and  Meridian,
Apache County, Arizona, being more particularly described as follows:

COMMENCING  at the axle that  marks the  Southwest  corner of Section  20,  from
whence the axle that marks the West quarter  corner of Section 20 bears North 00
degrees 18 minutes 08 seconds West, a distance of 2639.33 feet;

thence  North 00 degrees 08 minutes 18 seconds  West along the West line of said
Section 20, a distance of 2087.82 feet;

thence  departing  the West  Section  line on a bearing  of South 89  degrees 34
minutes  38  seconds  East,  a  distance  of  328.67  feet to the TRUE  POINT OF
BEGINNING;

thence continuing on a bearing of South 89 degrees 34 minutes 38 seconds East, a
distance of 250.00 feet;

thence South 00 degrees 25 minutes 22 seconds West, a distance of 250.00 feet;

thence North 89 degrees 34 minutes 38 seconds West, a distance of 250.00 feet;

thence North 00 degrees 25 minutes 22 seconds East, a distance of 250.00 feet to
the TRUE POINT OF BEGINNING.

                                 COCONINO COUNTY

                               RED LAKE SUBSTATION

The  following  described  land  situate in Coconino  County,  Arizona,  being a
portion of the Southwest Quarter of Section 15, Township 23 North,  Range 2 East
of the Gila and Salt River Base and  Meridian,  more  particularly  described as
follows:

COMMENCING  at the  "P-K"  nail in a  concrete  fence  corner  footing,  locally
accepted as the Southwest  corner of said Section 15, from whence the 1" pipe in
a stone circle that marks the South  Quarter  corner of said Section bears South
87(degree)59'34" East, 2574.88 feet distant;

                                       13
<PAGE>
THENCE North  36(degree)17'16" East, a distance of 602.19 feet to the TRUE POINT
OF BEGINNING;

THENCE North 01(degree)09'03" East, a distance of 291.53 feet;

THENCE South 88(degree)50'58" East, a distance of 300.00 feet;

THENCE South 01(degree)09'03" West, a distance of 300.00 feet;

THENCE North 88(degree)50'58" West, a distance of 249.94 feet;

THENCE North  79(degree)14'50"  West, a distance of 50.77 feet to the TRUE POINT
OF BEGINNING.

TOGETHER WITH a release,  transfer and quit-claim of all right, title, privilege
and claim of Grantor in and to all minerals  (surface and subsurface)  which may
be owned by him and which are appurtenant to the aforedescribed lands.

TOGETHER with all improvements thereon located.

                                 MARICOPA COUNTY

                              ALEXANDER SUBSTATION

A portion of the South half of Section 25, Township 3 North,  Range 2 East, Gila
and Salt River Meridian,  Maricopa County,  Arizona,  lying south of the Arizona
Canal more particularly described as follows:

Commencing  at the South  Quarter  corner of said Section 25, said point being a
brass cap in  handhole,  thence  coincident  with the  mid-section  line,  North
00(degree)  29' 36" East  1666.94  feet to the True  Point of  Beginning  of the
parcel herein described.

Thence leaving said mid-section  line South  55(degree)  53'23" West 8.36' to an
iron bar with SRP cap stamped LS15925,

Thence North  38(degree)  36' 25" West 231.40 feet to the North line of a parcel
of land described in Docket 265, Page 90 Maricopa County records and an iron bar
with SRP cap stamped LS 15925,

Thence  coincident  with the North line of said Docket 265,  Page 90,  North 510
15'14"  East  125.27  feet to an iron bar with SRP cap  stamped LS 15925 and the
beginning  of an non  tangent  curve,  concave  to the South  having a radius of
380.00 feet and to which beginning a radial line bears North  27(degree) 42' 18"
West;

Thence  easterly  81.70  feet  along  said  curve  through  a  central  angle of
12(degree) 19' 08" to an iron bar with SRP cap stamped LS 15925

Thence  South.10(degree)44'  49"  East  37.36  feet to an iron  bar with SRP cap
stamped LS15925,

Thence  North  81(degree)46'  03"  East  70.88  feet to an iron bar with SRP cap
stamped LS 15925,

Thence  North  13(degree)  21' 24" West  39.83  feet to an iron bar with SRP cap
stamped LS 15925 and the beginning of a non tangent curve,  concave to the south
having a radius of 380 feet and to which  beginning  a radial  line bears  North
04(degree) 58' 04" West;

                                       14
<PAGE>
Thence  easterly  149.84  feet  along  said  curve  through a  central  angle of
22(degree) 35' 34" to an iron bar with SRP cap stamped LS15925,

Thence  South  72(degree)22'  30" East  274.22  feet to an iron bar with SRP cap
stamped LS 15925,

Thence South 53(degree)04'37" East 8.00 feet to an iron bar with SRP cap stamped
LS15925,

Thence  South  72(degree)35'  22" East  119.70  feet to an iron bar with SRP cap
stamped LS 15925,

Thence  South  61(degree)24'  41"  West  52.21  feet to an iron bar with SRP cap
stamped LS15925,

Thence  North  78(degree)18'  39"  West  75.52  feet to an iron bar with SRP cap
stamped LS15925,

Thence  South  61(degree)24'  41" West  542.37  feet to an iron bar with SRP cap
stamped LS15925,

Thence  North  00(degree)29'  36" East  129.40  feet to an iron bar with SRP cap
stamped LS15925,

Thence South 56(degree) 15' 21" West 30.24 feet to the true point of beginning.

                              ARROWHEAD SUBSTATION

PARCEL NO. 1:

That part of the Southeast quarter of Section 23, Township 4 North, Range 1 East
of the Gila and Salt River Meridian, Maricopa County, Arizona, more particularly
described as follows:

COMMENCING at the South quarter corner of said Section 23;

THENCE South 89 degrees 53 minutes 33 seconds East,  along the South line of the
Southeast quarter of said Section 23, a distance of 740.00 feet;

THENCE North 00 degrees 05 minutes 41 seconds East, departing said South line, a
distance  of 70.00 feet to the  Southwest  corner of a 20.00 foot wide  Electric
Utility Easement, recorded in Document No. 94-0809353, Maricopa County Records;

THENCE  North 89 degrees 53 minutes 33 seconds  West,  a distance of 120.00 feet
the True Point of Beginning;

THENCE  continuing  North 89 degrees 53 minutes 33 seconds  West,  a distance of
250.00 feet;

THENCE North 00 degrees 05 minutes 41 seconds East, a distance of 250.00 feet;

THENCE South 89 degrees 53 minutes 33 seconds East, a distance of 250.00 feet;

THENCE South 00 degrees 05 minutes 41 seconds West, a distance of 250.00 feet to
the True Point of Beginning.

PARCEL NO. 2:

A 20.00 foot Electric Utility Easement  (Extension) over the following described
property:

                                       15
<PAGE>
That part of the Southeast quarter of Section 23, Township 4 North, Range 1 East
of the Gila and Salt River Meridian, Maricopa County, Arizona, more particularly
described as follows:

COMMENCING at the South quarter corner of said Section 23;

THENCE south 89 degrees 53 minutes 33 seconds East,  along the South line of the
Southeast quarter of said Section 23, a distance of 740.00 feet;

THENCE North 00 degrees 05 minutes 41 seconds East, departing said South line, a
distance  of 70.00 feet to the  Southwest  corner of a 20.00 foot wide  Electric
Utility Easement, recorded in Document No. 94-0809353,  Maricopa County Records,
said point being the True Point of Beginning;

THENCE North 89 degrees 53 minutes 33 seconds West, a distance of 120.00 feet to
the  Southeast  corner of the  proposed  boundary of an Arizona  Public  Service
Sub-station site;

THENCE North 00 degrees 05 minutes 41 seconds  East,  along the East boundary of
said Sub-station site, a distance of 20.00 feet;

THENCE  South 89 degrees 53 minutes 33 seconds  East,  departing  said  proposed
boundary,  a distance of 120.00 feet to the  Northwest  corner of said  Electric
Utility Easement;

THENCE South 00 degrees 05 minutes 41 seconds  West,  along the West boundary of
said Electric  Utility  Easement,  a distance of 20.00 feet to the True Point of
Beginning.

PARCEL NO. 3:

A 20.00 foot Ingress and Egress Easement over the following described property;

That part of the Southeast quarter of Section 23, Township 4 North, Range 1 East
of the Gila and Salt River Meridian, Maricopa County, Arizona, more particularly
described as follows:

A 20.00 foot  easement  being  10.00 feet each side of the  following  described
centerline;

COMMENCING at the Southeast corner of said Section 23;

THENCE North 00 degrees 18 minutes 23 seconds  East,  along the East line of the
Southeast quarter of said Section 23, a distance of 1,571.94 feet;

THENCE North 89 degrees 41 minutes 37 seconds  West, a distance of 55.00 feet to
a point on the Westerly right of way of "75th Avenue," said point being the True
Point of Beginning;

THENCE  continuing  North 89 degrees 41 minutes 37 seconds West,  departing said
Westerly  right-of-way,  a distance of 168.09 feet to the beginning of a tangent
curve of 50.00 foot radius, concave Southeasterly;

THENCE  Southwesterly,  along said curve, through a central angle of 103 degrees
43 minutes 28 seconds,  a distance of 90.52 feet to the  beginning  of a tangent
compound curve of 1,682.00 foot radius, concave Northeasterly;

THENCE Southeasterly, along said curve, through a central angle of 05 degrees 51
minutes 26  seconds,  a distance of 171.94  feet to the  beginning  of a tangent
reverse curve of 604.00 foot radius, concave Northwesterly;

                                       16
<PAGE>
THENCE  Southwesterly,  along said curve, through a central angle of 125 degrees
23 minutes 38 seconds, a distance of 1,321.88 feet to the beginning of a tangent
reverse curve of 1,650.00 foot radius, concave Southwesterly;

THENCE Northwesterly, along said curve, through a central angle of 31 degrees 26
minutes 46  seconds,  a distance of 905.58  feet to the  beginning  of a tangent
reverse curve of 285.00 foot radius, concave Northeasterly;

THENCE Northwesterly, along said curve, through a central angle of 44 degrees 14
minutes 21  seconds,  a distance of 220.05  feet to the  beginning  of a tangent
reverse curve of 95.00 foot radius, concave Southeasterly;

THENCE Southwesterly, along said curve, through a central angle of 76 degrees 39
minutes 20 seconds, a distance of 127.10 feet;

THENCE South 43 degrees 15 minutes 22 seconds  West, a distance of 74.02 feet to
the beginning of a tangent curve of 62.50 foot radius, concave Southeasterly;

THENCE Southwesterly, along said curve, through a central angle of 42 degrees 15
minutes 22 seconds, a distance of 46.09 feet;

THENCE South 00 degrees 00 minutes 00 seconds East, a distance of 158.20 feet to
a point on the proposed North boundary of an Arizona Public Service  Sub-station
site, said point being the terminus of said easement.

                            BISCUIT FLATS SUBSTATION

That portion of the South half of Section 26, Township 5 North,  Range 2 East of
the Gila and Salt River Base and Meridian,  Maricopa County, Arizona,  described
as follows:

Commencing  at a point on the  North-South  mid-section  line of said Section 26
that lies North 00 degrees 01 minutes 41 seconds  East record  (North 00 degrees
01 minutes 31 seconds  East  measured),  a distance of 1671.16  record  (1671.14
measured) feet from the South quarter corner of said Section 26;

thence  departing said  mid-section  line South 89 degrees 39 minutes 32 seconds
West and parallel to the South line of the Southwest quarter of said Section 26,
a distance of 869.84 record  (868.38  measured)  feet to the  Southerly  line of
Tract No. GR-10-6 in the Central Arizona Project Canal Right-of-Way as described
in Docket 11522, page 436, records of said county;

thence North 44 degrees 27 minutes 45 seconds  East record  (North 44 degrees 27
minutes 48 seconds East  measured)  along said Southerly line 203.94 feet to the
True Point of Beginning;

thence  continuing  North 44 degrees 27 minutes 45 seconds East record (North 44
degrees 27 minutes 48 seconds East  measured)  along said  Southerly  line 89.91
feet to the  beginning of a curve  concave to the  Southeast  having a radius of
1282.14 feet;

thence  Northeasterly along said curve and said Southerly line through a central
angle of 14  degrees 48  minutes  56  seconds  record (14  degrees 49 minutes 17
seconds measured), an arc distance of 331.54 record (331.67 measured) feet;

                                       17
<PAGE>
thence  departing  said  Southerly  line  North 80 degrees 04 minutes 45 seconds
record  (North 80  degrees 04 minutes  28  seconds  East  measured),  along said
Southerly  boundary of Tract No.  GR-10-6A of the Central  Arizona Project Canal
Right-of-Way  as described in Docket  11827,  page 1263,  records of said county
670.13 record (668.89  measured)  feet, more or less, to a point on the Westerly
right-of-way of Interstate 17 according to Book 542 of Deeds,  page 471, records
of said county;

thence South 09 degrees 55 minutes 45 seconds  East record  (South 09 degrees 55
minutes 32 seconds East measured),  along said right-of-way a distance of 278.16
feet;

thence departing said right-of-way  South 83 degrees 55 minutes 20 seconds West,
a distance of 1035.80 feet to the True Point of Beginning.

                               BUCKEYE SUBSTATION

That portion of the  Southeast  quarter of the  Southeast  quarter of Section 7,
Township 1 North,  Range 3 West of the Gila and Salt  River  Base and  Meridian,
Maricopa County, Arizona, lying South of the following described line:

BEGINNING at a point on the East line of said Section 7, which point bears North
0 degrees  31  minutes  52  seconds  East,  690 feet from the  Southeast  corner
thereof;

thence  North 82 degrees 35 minutes 18 seconds West 2317.38 feet to the Point of
Ending;

EXCEPT the following described part of said Section 7:

BEGINNING at a point on the South line of the Southeast  quarter 430.8 feet West
of the Southeast corner;

thence Northerly, parallel to the East line of the Southeast quarter 315.5 feet;

thence Easterly, parallel to the South line of the Southeast quarter, 160 feet;

thence Northerly, parallel to the East line, 400 feet;

thence Westerly, parallel to the South line, 400 feet;

thence Southerly parallel to the East line, 400 feet;

thence Easterly, parallel to the South line, 140 feet;

thence Southerly, parallel to the East line, 315.5 feet;

thence Easterly, along the South line, 100 feet to the Point of Beginning.

                                COLTER SUBSTATION

PARCEL NO. 1:

That part of the  Southwest  quarter of the  Southwest  quarter  of Section  24,
Township 2 North,  Range 1 West of the Gila and Salt  River  Base and  Meridian,
Maricopa County, Arizona, described as follows:

COMMENCING at the Southwest corner of said Section 24;

                                       18
<PAGE>
Thence  North 00 degrees 12 minutes 23 seconds  West along the West line of said
Section 24, a distance of 950.24 feet to the North line of the South 950.00 feet
of said Southwest quarter of the Southwest quarter of Section 24;

Thence  South 88 degrees 55 minutes  39 seconds  East along said North  line,  a
distance  of 55.01  feet to a point on a line which is  parallel  with and 55.00
feet East of the said West line of Section  24,  said point being the TRUE POINT
OF BEGINNING;

Thence  North 00 degrees 12 minutes 23 seconds  West along said  parallel  line,
273.78 feet;

Thence South 89 degrees 03 minutes 57 seconds East, 26.19 feet;

Thence North 00 degrees 12 minutes 23 seconds  West,  18.13 feet to a point on a
line that is  parallel  with and  60.00  feet  South of the  North  line of said
Southwest quarter of the Southwest quarter of Section 24;

Thence  South 89 degrees 03 minutes 57 seconds  East along said  parallel  line,
343.88 feet to the East line of the West 425.00 feet of said  Southwest  quarter
of the Southwest quarter of Section 24;

Thence South 00 degrees 12 minutes 23 seconds East along said East line,  292.80
feet to the said North line of the South 950.00 feet of the Southwest quarter of
the Southwest quarter of Section 24;

Thence North 88 degrees 55 minutes 39 seconds West along said line,  370.09 feet
to the TRUE POINT OF BEGINNING.

PARCEL NO. 2:

An  easement  for  ingress  and egress as set forth in  instruments  recorded in
Document No. 89222578 and in Document No. 92545550  records of Maricopa  County,
Arizona, over the following described property:

That part of the  Southwest  quarter of the  Southwest  quarter  of Section  24,
Township 2 North,  Range 1 West of the Gila and Salt  River  Base and  Meridian,
Maricopa County, Arizona, more particularly described as follows:

COMMENCING at the Southwest corner of said Section 24;

Thence North 00 degrees 12 minutes 23 seconds West,  along the West line of said
Section,  1302.02 feet to a point on the North line of said Southwest quarter of
the Southwest quarter of Section 24;

Thence South 89 degrees 03 minutes 57 seconds East along said North line,  55.01
feet to a point on a line which is parallel with and 55.00 feet East of the said
West line of said Section 24, said point being the TRUE POINT OF BEGINNING;

Thence  South 89 degrees 03 minutes  57  seconds  East,  along said North  line,
370.08 feet;

Thence South 00 degrees 12 minutes 23 seconds East, 60.01 feet, said point being
on a line that is  parallel  with and 60.00 feet South of the North line of said
Southwest quarter of the Southwest quarter of Section 24;

Thence North 89 degrees 03 minutes 57 seconds  West,  along said  parallel  line
370.08  feet,  to a point being on a line that is  parallel  with and 55.00 feet
East of the West line of said Section 24;

                                       19
<PAGE>
Thence  North 00 degrees 12 minutes 23 seconds West along said  parallel  line a
distance of 60.01 feet to the TRUE POINT OF BEGINNING.

                               DOWNING SUBSTATION

A portion of Tract 21 of State Plat No. 16,  core  South,  recorded in Book 324,
Page 50 of Maps,  Maricopa  County  Recorders  Office in Section 36,  Township 4
North, Range 4 East, Gila and Salt River Meridian, Maricopa County, Arizona, and
being more  particularly  described as follows:  Commencing  at the East quarter
corner of said Section 36, from whence the  Northeast  corner of said Section 36
bears N00(degree)01'37"W,  (basis of bearings), a distance of 2640.50 ft; thence
N00(degree)01'37"W, along the east line of said Section 36, a distance of 847.91
ft;  thence  N36(degree)08'59"W,  a  distance  of 728.73 ft to the true point of
beginning;  thence  continuing  N36  '08'59"W,  a distance of 400.00 ft;  thence
S53(degree)51'01  "W, a distance  of 300.00  ft;  thence  S36(degree)08'59"E,  a
distance of 400.00 ft;  thence  N53(degree)51'01  "E, a distance of 300.00 ft to
the true point of beginning.

Total 2.75 acres more or less.

                               FLYING E SUBSTATION

A portion of the Southwest quarter of Section 9, Township 7 North,  Range 5 West
of the Gila and Salt River Meridian, Maricopa County, Arizona, more particularly
described as follows:

Commencing at the Center of Section 9-(2 inch aluminum cap RLS 24514);

THENCE  North 89 degrees 54 minutes 33 seconds  West along the North line of the
Southwest  quarter of said Section 9 a distance of 880.72 feet to the True Point
of Beginning of said Parcel;

THENCE  continuing  North 89 degrees  54 minutes 33 second  West along the North
line of the Southwest quarter of said Section 9 a distance of 400.00 feet;

THENCE  South 00 degrees 03 minutes 56 seconds West a distance of 278.70 feet to
a point on the Northerly Right of Way of U.S. Highway 60;

THENCE South 89 degrees 15 minutes 50 seconds East along the Northerly  Right of
Way. of U.S. Highway 60 a distance of 400.00 feet;

THENCE  North 00 degrees 04 minutes 16 seconds East a distance of 283.21 feet to
the True Point Beginning.

                               HATFIELD SUBSTATION

The South 330 feet of the West half of the  Southwest  quarter of the  Northwest
quarter of the Northeast quarter of Section 8, Township 4 North, Range 1 East of
the Gila and Salt River Base and Meridian, Maricopa County, AZ.

                           HEDGEPATH HILLS SUBSTATION

The North half of Lot 2, Section 7,  Township 4 North,  Range 2 East of the Gila
and Salt River Base and Meridian,  Maricopa  County,  Arizona;

EXCEPT that part lying North of the following described line:

                                       20
<PAGE>
BEGINNING at a point on the West line of said Lot 2 which bears South 00 degrees
10 minutes  East a distance of 446.24 feet from the  Northwest  corner  thereof;
thence North 86 degrees 04 minutes East a distance of 1026.53 feet to a point on
the East line of said Lot 2 which  bears  South 00 degrees 11  minutes  East,  a
distance of 383.93 feet from the Northeast corner thereof.

                             MISTY WILLOW SUBSTATION

The South 290 feet of the East 290 feet of the  Northwest  quarter of Section 8,
Township 4 North,  Range 3 East of the Gila and Salt  River  Base and  Meridian,
Maricopa County, Arizona;

Except the East 40 feet; and

Except the South 40 feet; and

Except an undivided 1/16 of all oil, gases,  and other  hydrocarbon  substances,
coal,  stone,  metals,  minerals,  fossils  and  fertilizer  of  every  name and
description and except all uranium,  thorium,  or any other material which is or
may be  determined  by the laws of the State of  Arizona,  the United  States of
America, or decisions of courts to be peculiarly  essential to the production of
fissionable  materials,  whether or not of  commercial  value,  as  reserved  in
Section 37-231 Arizona Revised Statutes

                              NEW RIVER SUBSTATION

The South 120 feet of the North half of Lot 4, of Section 26,  Township 7 North,
Range 2 East,  of the Gila and Salt River Base and  Meridian,  Maricopa  County,
Arizona;

EXCEPT all coal,  oil,  gas,  and other  mineral  deposits as reserved  unto the
United States of America in the Patent of said land.

                                STOUT SUBSTATION

Being a portion of the South three quarters of the West half of the West half of
the Southwest  quarter of the Northeast quarter of Section 12, Township 4 North,
Range 2 East of the Gila and Salt  River  Base and  Meridian,  Maricopa  County,
Arizona, being more particularly described as follows:

COMMENCING at the Northwest corner of said Southwest quarter;

Thence  South 00 degrees 07 minutes 32 seconds  East along the West line of said
West half 331.46 feet to a point on the North line of said South three quarters;

Thence  South 89 degrees 42 minutes 22 seconds  East along said North line 30.00
feet to the POINT OF BEGINNING;

Thence  continuing  South 89 degrees 42 minutes 22 seconds East along said North
line 304.59 feet to a point on the East line of said West half;  Thence South 00
degrees 08 minutes 09 seconds East along said East line 286.01 feet;

Thence  North 89 degrees 42 minutes 22 seconds West along a line  parallel  with
the North line of said South  three  quarters  304.64  feet to a point on a line
30.00 feet East of and parallel with the West line of said West half;

                                       21
<PAGE>
Thence  North 00 degrees 07 minutes  32 seconds  West along said  parallel  line
286.01 feet to the POINT OF BEGINNING.

                                WATSON SUBSTATION

A parcel of land  situate in a portion of the  Southeast  quarter of Section 10,
Township 1 North,  Range 3 West of the Gila and Salt  River  Base and  Meridian,
Maricopa County, Arizona more particularly described as follows:

Commencing  at the  Southeast  corner of said  Section  10 from  which the South
quarter  corner of said  Section 10 bears South 89 degrees 27 minutes 57 seconds
West, a distance of 2626.67 feet;

Thence South 89 degrees 27 minutes 57 seconds West,  along the Southerly line of
the Southeast quarter of said Section 10, a distance of 912.51 feet;

Thence North 00 degrees 33 minutes 32 seconds  West, a distance of 65.00 feet to
the true point of beginning;

Thence  South 89 degrees 27  minutes  57 seconds  West,  along a line 65.00 feet
northerly of and parallel with said southerly line, a distance of 209.34 feet;

Thence North 00 degrees 33 minutes 32 seconds West, a distance of 220.00 feet;

Thence  North 89 degrees 27 minutes 57 seconds  East,  along a line  285.00 feet
northerly of and parallel with said southerly line, a distance of 209.34 feet;

Thence South 00 degrees 33 minutes 32 seconds East, a distance of 220.00 feet to
the true point of beginning.

                              WILDFLOWER SUBSTATION

The South 704.51 feet of the South half of the West 330 feet of the East half of
the East half of the Southwest  quarter of Section 6, Township 1 North,  Range 1
West of the Gila and Salt River Base and Meridian, Maricopa County, Arizona;

EXCEPT that portion,  if any, lying within the West 660 feet of the East half of
the Southwest quarter of Section 6; and

EXCEPT that portion,  if any, lying within the East half of the East half of the
East half of the Southwest quarter of Section 6.

                            WEST PHOENIX POWER PLANT

     All real and  personal  property  that are part of the West  Phoenix  Power
Plant,  including all such property repurchased by the Company at the end of the
term of that certain Lease and other  documents  relating to the "Combined Cycle
Transactions"  described in the Twenty-first  Supplemental Indenture dated as of
April 15, 1997 to the Mortgage,  and as further  described in that certain Deed,
Bill of Sale and  Assignment  as recorded on December 15, 2000 in the records of
Maricopa County,  Arizona as Instrument No. 2002-0957462,  and further including
the following described real property:

                                       22
<PAGE>
PARCEL NO. 1:

The Southeast  quarter of Section 9, Township 1 North,  Range 2 East of the Gila
and Salt River Base and Meridian, Maricopa County, Arizona;

EXCEPT the East 20 feet; and

EXCEPT the West 10 feet; and

EXCEPT the South 33 feet for roadway; and

EXCEPT the North 20 feet for railroad; and

EXCEPT BEGINNING at a point 811 feet South and 695 feet West of the East quarter
corner of Section 9,  Township 1 North,  Range 2 East of the Gila and Salt River
Base and Meridian;

Thence South 453 feet;

Thence West 95 feet;

Thence North 453 feet;

Thence East 95 feet, to the POINT OF BEGINNING; and

EXCEPT all that portion of the Southeast quarter of Section 9, Township 1 North,
Range 2 East of the Gila and Salt  River  Base and  Meridian,  Maricopa  County,
Arizona, more particularly bounded and described as follows:

BEGINNING at a point from which the East quarter corner of said Section 9, bears
North 29 degrees 57 minutes 45 seconds East a distance of 686.8 feet;

Thence South 669.0 feet;

Thence West 352.0 feet;

Thence North 453.0 feet;

Thence West 95.0 feet;

Thence North 102.0 feet;

Thence East 30.0 feet;

Thence North 114.0 feet;

Thence East 417.0 feet to the Place of Beginning; and

EXCEPT  that  portion of land  situated in the  Southeast  quarter of Section 9,
Township 1 North,  Range 2 East of the Gila and Salt  River  Base and  Meridian,
more particularly described as follows:

BEGINNING at the South quarter corner of Section 9;

                                       23
<PAGE>
Thence on a bearing  North 00  degrees  18  minutes  40  seconds  West along the
midsection line of Section 9, a distance of 1161.30 feet to a point;

Thence  North 89 degrees 22 minutes 30 seconds East a distance of 505.41 feet to
a point being corner number Sixteen,  of the Combined Cycle Plant Site, and TRUE
POINT OF BEGINNING of the parcel herein described;

Thence  continue  North 89 degrees 22  minutes  30  seconds  East a distance  of
1094.88 feet to a point being corner number One;

Thence  North 00 degrees 38 minutes 30 seconds West a distance of 207.88 feet to
a point being corner number Two;

Thence  South 89 degrees 22 minutes 30 seconds West a distance of 340.00 feet to
a point being corner number Three;

Thence South 0 degrees 38 minutes 30 seconds East a distance of 187.88 feet to a
point being corner number Four;

Thence South 89 degrees 22 minutes 30 seconds West a distance of 45.00 feet to a
point being corner number Five;

Thence North 0 degrees 38 minutes 30 seconds West a distance of 823.72 feet to a
point being corner number Six;

Thence  South 89 degrees 21 minutes 30 seconds West a distance of 279.44 feet to
a point being corner number Seven;

Thence  North 0 degrees 38 minutes 30 seconds  West a distance of 40.0 feet to a
point being corner number Eight;

Thence  South 89 degrees 21 minutes 30 seconds West a distance of 93.0 feet to a
point being corner number Nine;

Thence  South 0 degrees 38 minutes 30 seconds  East a distance of 40.0 feet to a
point being corner number Ten;

Thence South 89 degrees 21 minutes 30 seconds West a distance of 255.0 feet to a
point being corner number Eleven;

Thence North 0 degrees 38 minutes 30 seconds West a distance of 131.96 feet to a
point being corner number Twelve;

Thence  South 89 degrees 21 minutes 30 seconds West a distance of 502.62 feet to
a point being corner number Thirteen;

Thence South 0 degrees 38 minutes 30 seconds East a distance of 528.30 feet to a
point being corner number Fourteen;

Thence  North 89 degrees 21 minutes 30 seconds East a distance of 420.18 feet to
a point being corner number Fifteen;

                                       24
<PAGE>
Thence South 0 degrees 38 minutes 30 seconds East a distance of 447.17 feet to a
point being corner number Sixteen and the TRUE POINT OF BEGINNING; and

EXCEPT a portion of the Southeast quarter of Section 9, Township 1 North,  Range
2 East of the Gila and Salt River Base and Meridian,  Maricopa County,  Arizona,
being more particularly described as follows:

COMMENCING  at the South  quarter  corner of Section  9, from  whence the center
quarter  corner of Section 9, bears  North 0 degrees 18 minutes 18 seconds  West
2634.59 feet distant;

Thence North 0 degrees 18 minutes 18 seconds West a distance of 125.00 feet;

Thence  North 89 degrees 02 minutes 00 seconds  East a distance of 60.00 feet to
the TRUE POINT OF BEGINNING;

Thence North 0 degrees 18 minutes 16 seconds West a distance of 825.06 feet;

Thence North 89 degrees 02 minutes 00 seconds East a distance of 565.00 feet;

Thence South 0 degrees 18 minutes 18 seconds East a distance of 900.06 feet;

Thence South 89 degrees 02 minutes 00 seconds West a distance of 515.00 feet;

Thence North 0 degrees 18 minutes 18 seconds West, a distance of 75.00 feet;

Thence  South 89 degrees 02 minutes 00 seconds  West a distance of 50.00 feet to
the TRUE POINT OF BEGINNING; and

EXCEPT the North 17.00 feet of the South 50.00 feet of the Southeast  quarter of
Section 9,  Township  1 North,  Range 2 East of the Gila and Salt River Base and
Meridian, Maricopa County, Arizona;

EXCEPT the West 10.00 feet thereof; and

EXCEPT the East 574.18 feet thereof; and

EXCEPT a portion of the Southeast quarter of Section 9, Township 1 North,  Range
2 East of the Gila and Salt  River  and  Base  and  Meridian,  Maricopa  County,
Arizona, more particularly described as follows:

BEGINNING at the Southeast corner of Section 9;

Thence  South 89 degrees  02  minutes  00  seconds  West along the South line of
Section 9, a distance of 1399.80 feet;

Thence North 00 degrees 58 minutes 00 seconds West to a point on the North right
of way line of  Buckeye  Road,  a  distance  of 50.00  feet to the TRUE POINT OF
BEGINNING;

Thence  South 89 degrees 02 minutes 00 seconds  West,  a distance of 580.80 feet
along said right of way;

Thence North 00 degrees 17 minutes 52 seconds West, a distance of 900.06 feet to
a point on the South right of way of Hadley Street;

Thence  North 89 degrees 02 minutes 00 seconds  East,  a distance of 580.80 feet
along said right of way;

                                       25
<PAGE>
Thence South 00 degrees 17 minutes 52 seconds East, a distance of 900.06 feet to
the TRUE POINT OF BEGINNING; and

EXCEPT that  portion of the  Southeast  quarter of Section 9,  Township 1 North,
Range 2 East of the Gila and Salt  River  Base and  Meridian,  Maricopa  County,
Arizona, described as follows:

COMMENCING at the Southeast corner of said Section 9;

Thence  South 89 degrees 02 minutes 00 seconds West along the South line of said
Section 9, a distance of 83.10 feet;

Thence North 00 degrees 58 minutes 00 seconds  West, a distance of 50.00 feet to
a point on the North right of way line of Buckeye Road,  being the TRUE POINT OF
BEGINNING;

Thence South 89 degrees 02 minutes 00 seconds West along said right of way line,
a distance of 1316.70 feet;

Thence North 00 degrees 17 minutes 52 seconds West, a distance of 900.06 feet to
a point on the South right of way line of Hadley Street;

Thence North 89 degrees 02 minutes 00 seconds East along said right of way line,
a distance of 1345.10 feet to a point on a tangent curve  concave  Southwesterly
with a radius of 20.00  feet,  and a central  angle of 90  degrees 58 minutes 17
seconds,  a distance  of 31.76 feet to a point  tangent to the West right of way
line of 43rd Avenue;

Thence South 00 degrees 00 minutes 27 seconds West along said right of way line,
a distance of 504.79 feet;

Thence South 01 degrees 09 minutes 12 seconds West along said right of way line,
a distance of 100.01 feet;

Thence South 00 degrees 00 minutes 27 seconds West along said right of way line,
a distance of 242.11 feet;

Thence South 51 degrees 16 minutes 25 seconds  West, a distance of 53.77 feet to
the TRUE POINT OF  BEGINNING,  as conveyed in that  certain  Warranty  Deed from
Arizona Public Service Company to Suncor Development Company dated March 6, 1998
and recorded  July 24,  1998,  as Document  No.  980636446,  records of Maricopa
County, Arizona; and

EXCEPT  those  roadways for 43rd  Avenue,  47th Avenue,  Buckeye Road and Hadley
Street as delineated on Map of  Dedication  for APS Property  dated May 18, 1989
and recorded  November 9, 1989 in Book 335 of Maps, page 21, records of Maricopa
County, Arizona; and

EXCEPT a parcel of land  being  located in the  Southeast  quarter of Section 9,
Township 1 North,  Range 2 East of the Gila and Salt  River  Base and  Meridian,
Maricopa  County,  Arizona;  said parcel  being more  particularly  described as
follows:

COMMENCING at the South quarter corner of said Section;

Thence  North 00 degrees  18 minutes 01 seconds  West along the West line of the
Southeast  quarter of Section 9,  Township 1 North,  Range 2 East, a distance of
1,486.38 feet;

                                       26
<PAGE>
Thence North 89 degrees 17 minutes 24 seconds East, a distance of 40 feet to the
TRUE POINT OF BEGINNING of the parcel herein described;

Thence  continuing  Northeast along the same bearing,  a distance of 317.26 feet
along the North line of said parcel;

Thence South 01 degrees 11 minutes 27 seconds East, a distance of 95.08 feet;

Thence North 89 degrees 17 minutes 24 seconds East, a distance of 49.43 feet;

Thence South 00 degrees 42 minutes 36 seconds East, a distance of 100.14 feet;

Thence North 89 degrees 17 minutes 24 seconds East, a distance of 43.34 feet;

Thence South 00 degrees 42 minutes 36 seconds East, a distance of 105.96 feet;

Thence  South 89 degrees 20 minutes 44 seconds  West along the South line of the
parcel herein described, a distance of 412.99 feet;

Thence  North 00 degrees 18 minutes 01 seconds  West along the West line of said
parcel,  a distance of 300.78 feet to the TRUE POINT OF  BEGINNING of the parcel
herein described; and

EXCEPT a parcel of land located in the Southeast  quarter of Section 9, Township
1 North,  Range 2 East of the Gila and Salt  River Base and  Meridian,  Maricopa
County, Arizona; said parcel being more particularly described as follows:

COMMENCING at the East quarter corner of said Section;

Thence  South 89 degrees 21 minutes 48 seconds  West along the North line of the
Southeast  quarter of Section 9,  Township 1 North,  Range 2 East, a distance of
2,622.28 feet;

Thence  South 00 degrees  18 minutes 01 seconds  East along the West line of the
Southeast quarter of said Section, a distance of 94.82 feet;

Thence North 89 degrees 17 minutes 24 seconds East, a distance of 30 feet to the
TRUE POINT OF BEGINNING of the parcel herein described;

Thence continuing  Northeast along the same bearing, a distance of 1,040.41 feet
along the North line of said parcel;

Thence South 45 degrees 00 minutes 00 seconds East, a distance of 85.85 feet;

Thence South 00 degrees 42 minutes 36 seconds East, a distance of 88.39 feet;

Thence South 89 degrees 17 minutes 24 seconds West, a distance of 481.33 feet;

Thence South, a distance of 293.07 feet;

Thence South 89 degrees 17 minutes 24 seconds West, a distance of 618.57 feet;

Thence North 00 degrees 18 minutes 01 seconds West, a distance of 442.90 feet to
the TRUE POINT OF BEGINNING of the parcel herein described; and

                                       27
<PAGE>
EXCEPT a parcel of land located in the Southeast  quarter of Section 9, Township
1 North,  Range 2 East of the Gila and Salt  River Base and  Meridian,  Maricopa
County, Arizona; said parcel being more particularly described as follows:

COMMENCING at the Southeast corner of said Section;

Thence  North 00  degrees  03  minutes  22  seconds  East along the East line of
Section 9, Township 1 North, Range 2 East, a distance of 1,359.93 feet;

Thence South 89 degrees 21 minutes 48 seconds West, a distance of 40 feet to the
TRUE POINT OF BEGINNING of the parcel herein described;

Thence  continuing  Southwest along the same bearing,  a distance of 302.93 feet
along the South line of the parcel herein described;

Thence  North 00 degrees 03 minutes 22 seconds  East along the West line of said
parcel, a distance of 669.00 feet;

Thence  North 89 degrees 21 minutes 48 seconds East along the North line of said
parcel, a distance of 302.93 feet;

Thence  South 00 degrees 03 minutes 22 seconds  West along the East line of said
parcel,  a distance of 669.00 feet to the TRUE POINT OF  BEGINNING of the parcel
herein described.

PARCEL NO. 2:

The East half of the North  half of the East half of the  Southwest  quarter  of
Section 9,  Township  1 North,  Range 2 East of the Gila and Salt River Base and
Meridian, Maricopa County, Arizona;

EXCEPT beginning at the Northeast corner of said Southwest  quarter of Section 9
in the  Southerly  line of the parcel of land  described in deed dated March 19,
1910 to Phoenix & Buckeye Railway Company recorded in Book 89 of Deeds, Page 97,
records of Maricopa County, Arizona;

Thence  Westerly along said Southerly line also the North line of said Southwest
quarter of Section 9, a distance of 1334.29 feet to the Northwest  corner of the
Northeast  quarter of said  Southwest  quarter of Section 9, also the  Northeast
corner of the parcel of land  described in Deed dated August 22, 1949 to Arizona
Eastern  Railroad  Company recorded in Docket 491, Page 216, records of Maricopa
County, Arizona;

Thence Southerly along the West line of said Northeast quarter of said Southwest
quarter of Section 9, a distance of 20.0 feet;

Thence  Easterly  parallel  with said  North line of said  Southwest  quarter of
Section 9, a distance of 1334.38 feet to the East line of said Southwest quarter
of Section 9;

Thence  Northerly  along said East line a distance  of 20.0 feet to the point of
beginning;

ALSO  EXCEPT a strip of land 20 feet in width in  Section  9,  Township 1 North,
Range 2 East of the Gila and Salt River Base and Meridian, Maricopa County, said
strip of land lying 10 feet on each side of the following described center line;

                                       28
<PAGE>
Beginning  at the  Northeast  corner of said  Section 9, and using as a base the
North  boundary line of said Section,  said North boundary line having a bearing
of South 89  degrees 22  minutes  West  based on a magnetic  bearing of South 75
degrees 00 minutes West;

Thence  South 88 degrees 22 minutes  West a distance  of 2661.5 feet to the True
Point of Beginning;

Thence South 0 degrees 07 minutes West a distance of 1325 feet;

Thence South 0 degrees 01 minutes West a distance of 1243.4 feet;

Thence South 0 degrees 14 minutes East a distance of 1331.6 feet;

Thence  South 0 degrees 27 minutes  East a distance of 1318.9 feet to a point in
the South boundary line of said Section 9, from which point the Southeast corner
of said  Section 9 bears  North 89 degrees 36 minutes  East a distance of 2606.5
feet,  as conveyed to the United States of America,  by  instrument  recorded in
Deed Book 115, Page 276, records of Maricopa County, Arizona;

EXCEPT  that  portion of the East half of the North half of the East half of the
Southwest  quarter of Section 9, Township 1 North,  Range 2 East of the Gila and
Salt  River Base and  Meridian,  Maricopa  County,  Arizona,  more  particularly
described as follows:

COMMENCING at the Northeast  corner of said Southwest  quarter of Section 9 from
whence the Southeast corner of said Southwest quarter of Section 9 lies South 00
degrees 18 minutes 01 seconds East, a distance of 2634.48 feet;

Thence  South 00 degrees 18 minutes 01 seconds  East along the East line of said
Southwest quarter of Section 9, a distance of 497.53 feet;

Thence South 89 degrees 24 minutes 46 seconds  West, a distance of 53.01 feet to
the TRUE POINT OF BEGINNING;

Thence South 00 degrees 37 minutes 11 seconds East, a distance of 467.02 feet;

Thence South 89 degrees 26 minutes 58 seconds West, a distance of 392.04 feet;

Thence North 00 degrees 36 minutes 52 seconds West, a distance of 466.77 feet;

Thence North 89 degrees 24 minutes 46 seconds East, a distance of 392.00 feet to
the TRUE POINT OF BEGINNING; and

EXCEPT a parcel of land located in the Southwest  quarter of Section 9, Township
1 North,  Range 2 East of the Gila and Salt  River Base and  Meridian,  Maricopa
County, Arizona; said parcel being more particularly described as follows:

COMMENCING at the South quarter corner of said Section;

Thence  North 00 degrees  18 minutes 01 seconds  West along the East line of the
Southwest  quarter of Section 9,  Township 1 North,  Range 2 East, a distance of
1,281.67 feet;

Thence South 89 degrees 17 minutes 36 seconds West, a distance of 40 feet to the
TRUE POINT OF BEGINNING of the parcel herein described;

                                       29
<PAGE>
Thence  continuing  Southwest along the same bearing,  a distance of 629.09 feet
along the South line of the parcel herein described;

Thence  North 00 degrees  13 minutes 26 seconds  West along the West line of the
parcel herein described, a distance of 1,123.64 feet;

Thence North 89 degrees 21 minutes 48 seconds East, a distance of 221.11 feet;

Thence South 00 degrees 36 minutes 52 seconds East, a distance of 781.97 feet;

Thence North 89 degrees 17 minutes 24 seconds East, a distance of 402.19 feet;

Thence South 00 degrees 18 minutes 01 seconds East, a distance of 341.39 feet to
the TRUE POINT OF BEGINNING of the parcel herein described.

PARCEL NO. 3:

The South  one-half of the East one-half of the Southwest  quarter of Section 9,
Township 1 North,  Range 2 East of the Gila and Salt  River  Base and  Meridian,
Maricopa County, Arizona;

EXCEPT the West 30.00 feet and

EXCEPT a strip of land  20.00  feet in width in  Section  9, said  strip of land
lying 10.00 feet on each side of the following described centerline;

COMMENCING  at the  Northeast  corner of said Section 9, and using as a base the
North  boundary of said  Section,  said North  boundary line having a bearing of
South 89 degrees 22 minutes West based on a magnetic bearing of South 75 degrees
00 minutes  West;  Thence  South 88 degrees 22 minutes  West 2,661.5 feet to the
POINT OF BEGINNING;

Thence South 00 degrees 07 minutes West 1,325 feet;

Thence South 00 degrees 01 minutes West 1,243.4 feet;

Thence South 00 degrees 14 minutes East 1,331.6 feet;

Thence  South 00 degrees 27 minutes  East  1,318.9  feet to a point in the South
boundary line of said Section 9 from which the Southeast  corner of said Section
9 bears North 89 degrees 36 minutes East 2,606.5 feet, as conveyed to the United
States of America by instrument recorded in Book 115 of Deeds, Page 276, records
of Maricopa County, Arizona; and

EXCEPT the South 450.00 feet.

                                  NAVAJO COUNTY

                            CHOLLA GENERATING STATION

POWER PLANT SITE

That part of Sections 15, 22, 23, 24, 25, 26, 27, 35 and 36,  Township 18 North,
Range 19 East, Gila and Salt River Meridian, Navajo County, Arizona described as
follows:

                                       30
<PAGE>
BEGINNING at a capped pipe marking the common  corner of Sections 14, 15, 22 and
23;

Thence  North 0 degrees 22  minutes 36 seconds  West along the East line of said
Section 15, a distance of 2669.78 feet to a capped pipe marking the East quarter
corner thereof;

Thence  North 89  degrees  55  minutes  54  seconds  West  along  the  East-West
mid-section line of said Section 15, a distance of 299.82 feet to a point in the
West line of the East 300 feet of the  Southeast  quarter  of said  Section  15,
being a found 5/8 inch rebar;

Thence  South 0 degrees  22 minutes  36  seconds  East  along said West line,  a
distance of 2668.57 feet to a found 5/8 inch rebar  located in the South line of
said Section 15;

Thence South 0 degrees 3 minutes 13 seconds West along the West line of the East
300 feet of the Northeast quarter of said Section 22, a distance of 1234.75 feet
to a point in the Southerly right of way line of old U.S.
Highway 66;

Thence  North 56 degrees 28  minutes  30 seconds  West,  along said right of way
line,  a  distance  of 156.72  feet to a point in the East line of the parcel of
land described in Docket 265, page 174;

Thence South 34 degrees 45 minutes 39 seconds West, along last said East line, a
distance of 3654.13  feet to a point in the  Northerly  right of way line of the
Atchison, Topeka and Santa Fe Railroad;

Thence South 44 degrees 6 minutes 47 seconds  West, a distance of 210.22 feet to
the intersection of the Southerly right of way line of the Atchison,  Topeka and
Santa Fe Railroad and the North-South mid-section line of said Section 22;

Thence  South 0 degrees 2 minutes  33 seconds  East along last said  mid-section
line, a distance of 1005.76 feet to the common  quarter  corner of said Sections
22 and 27;

Thence  North 89 degrees 44 minutes 21 seconds West along the North line of said
Section 27, a distance of 120.00 feet to its Intersection with the thread of the
Little Colorado River;

Thence  Southerly and Easterly  along said thread to its  intersection  with the
East line of said  Section  27,  said point  lying South 0 degrees 30 minutes 30
seconds  East,  a  distance  of 600.00  feet from the  Northeast  corner of said
Section 27;

Thence South 0 degrees 30 minutes 30 seconds East,  along last said East line, a
distance of 4714.56 feet to the common corner of said Section 26, 27, 34 and 35;

Thence North 89 degrees 37 minutes 3 seconds East,  along the North line of said
Section 35, a distance of 422.00 feet to its intersection with the thread of the
Little Colorado  River,  from which point the common corner of said Sections 25,
26, 35 and 36 bears  North 89 degrees 37 minutes 3 seconds  East,  a distance of
4894.86 feet;

Thence Southerly and  Southeasterly  along said thread to its intersection  with
the East line of said  Section 35,  from which  point the common  corner of said
Sections  25, 26, 35 and 36 bears North 0 degrees 14 minutes 4 seconds  West,  a
distance of 3171.07 feet;

Thence  South 0 degrees 14 minutes 4 seconds  East along last said East line,  a
distance of 2166.50 feet to the common  corner of said Sections 35 and 36 and of
Sections  1 and 2 of  Township  17  North,  Range 19 East,  Gila and Salt  River
Meridian;

                                       31
<PAGE>
Thence  North 88 degrees 27 minutes 31 seconds East along the South line of said
Section 36, a distance of 1337.23  feet to the West 1/16th  corner  between said
Sections 36 and 1;

Thence  North 0 degrees 16 minutes 29 seconds West along the West 1/16th line of
said  Section 36, a distance of 5324.98 feet to the West 1/16th  corner  between
said Sections 25 and 36;

Thence  North 89  degrees 0 minutes 0 seconds  East along the South line of said
Section  25,  a  distance  of  1112.92  feet  to  its   intersection   with  the
Southwesterly right of way line of the Atchison, Topeka and Santa Fe Railroad;

Thence  North 56 degrees 26  minutes  18 seconds  West along said  Southwesterly
right of way line, a distance of 611.23 feet;

Thence North 33 degrees 18 minutes 42 seconds East, a distance of 200.00 feet to
the  Northeasterly  right  of way  line of the  Atchison,  Topeka  and  Santa Fe
Railroad,  said  point  being in the East  line of the  West  2050  feet of said
Section 25;

Thence  North 0 degrees  24 minutes 1 second  West along last said East line,  a
distance of 4808.67 feet to its intersection with the North line of said Section
25, from which the common  corner of said Sections 23, 24, 25 and 26 bears South
89  degrees 31 minutes  41  seconds  West  (South 89 degrees 20 minutes  West of
record) a distance of 2050.00 feet;

Thence  North 0 degrees 24 minutes 31 seconds  West  (North 0 degrees 36 minutes
West of record), a distance of 637.66 feet (637.67 feet of record);

Thence  North 71 degrees 35 minutes 24 seconds West (North 71 degrees 46 minutes
West of record),  a distance of 2149.74 feet (2150.04 feet of record) to a point
in the West line of said  Section 24 (said point being North 0 degrees 2 minutes
East along the West line of said Section 24, a distance of 1334.13 feet from the
Southwest corner of said Section 24, of record);

Thence  North 0 degrees 14  minutes 48 seconds  East along the East line of said
Section  23, a distance of 164.99 feet to its  intersection  with the  Southerly
right of way line of Old U.S. Highway 66;

Thence  North 74 degrees 55  minutes 37 seconds  West along last said  Southerly
right of way line,  a  distance  of  1708.33  feet to the  beginning  of a curve
concave Northerly having a radius of 5779.58 feet;

Thence continue along last said Southerly right of way line, Northwesterly along
the arc of said  curve  through  a  central  angle of 5 degrees  28  minutes  11
seconds, a distance of 551.73 feet to a point of tangency;

Thence continue along last said Southerly right of way line, North 69 degrees 27
minutes  38 seconds  West,  a distance  of 1040.53 to the  beginning  of a curve
concave Northerly having a radius of 2914.79 feet;

Thence  continue along last said Southerly  right of way line,  along the arc of
last  said  curve  through a central  angle of 4 degrees 1 minute 0  seconds,  a
distance  of 83.66  feet to a point  from  which a radial  line  bears  North 22
degrees 11 minutes 3 seconds East said point being the Northeast  corner of that
part of the West half of the said  Section  23  described  in Parcel 1 of Docket
766, page 155;

Thence South 26 degrees 20 minutes 42 seconds West, a distance of 359.44 feet to
the Southeast corner of said parcel of land;

                                       32
<PAGE>
Thence North 68 degrees 47 minutes 52 seconds West, a distance of 484.70 feet to
the Southwest corner of said parcel of land;

Thence North 33 degrees 42 minutes 40 seconds East, a distance of 396.09 feet to
the  Northwest  corner of said parcel of land,  said point being in the arc of a
curve in said  Southerly  right of way line of Old U.S.  Highway  66, said curve
being  concave  to the North  having a radius of  1482.39  feet and from which a
radial line thereof bears North 29 degrees 40 minutes 36 seconds East;

Thence  Northwesterly  along last said Southerly right of way line along the arc
of said  curve  through a central  angle of 9  degrees  7 minutes 0  seconds,  a
distance of 103.40 feet;

Thence continue along last said Southerly right of way line, North 56 degrees 19
minutes 38 seconds West, a distance of 1950.09 feet to its intersection with the
West line of said Section 23;

Thence  North 0 degrees 3 minutes 13 seconds  East along last said West line,  a
distance of 1431.70 feet to the POINT OF BEGINNING;

EXCEPT that part of said Section 22 lying whiting the right of way of Interstate
40 and being described as follows:

BEGINNING at a capped pipe marking the common corner of said Sections 14, 15, 22
and 23;

Thence  South 0 degrees 3 minutes  13  seconds  West along the East line of said
Section 22, a distance of 384.09 feet to a point in the  Northeasterly  right of
way line of said Interstate 40 and the TRUE POINT OF BEGINNING;

Thence  continue  South 0 degrees 3 minutes 13 seconds West along last said East
line,  a distance  of 396.43 feet to a point in the  Southwesterly  right of way
line of said Interstate 40;

Thence  North 63 degrees 11  minutes  44 seconds  West along said  Southwesterly
right of way line,  a distance of 335.95 feet to a point in the West line of the
East 300 feet of the Northeast quarter of said Section 22;

Thence North 0 degrees 3 minutes 13 seconds  East,  along last said West line, a
distance of 413.51 feet to a point in said Northeasterly right of way line;

Thence  South 59 degrees 11 minutes 46 seconds  East,  along said  Northeasterly
right of way line, a distance of 218.60 feet;

Thence continue along last said Northeasterly right of way line South 63 degrees
11 minutes  44 seconds  East,  a  distance  of 125.38  feet to the TRUE POINT OF
BEGINNING; and

EXCEPT  that part of said  Section 22 lying  within the right of way of Old U.S.
Highway 66 and being described as follows:

BEGINNING at a capped pipe marking the common corner of said Sections 14, 15, 22
and 23;

Thence  South 0 degrees 3 minutes  13  seconds  West along the East line of said
Section 22, a distance of 1311.58 feet to a point in the Northeasterly  right of
way line of said Old U.S. Highway 66 and the TRUE POINT OF BEGINNING;

                                       33
<PAGE>
Thence continue along last said East line,  South 0 degrees 3 minutes 13 seconds
West,  a distance  of 120.12 feet to a point in the  Southwesterly  right of way
line of said Old U.S. Highway 66;

Thence  North 56 degrees 28 minutes 30 seconds West along last said right of way
line, a distance of 359.47 feet;

Thence North 0 degrees 3 minutes 13 seconds East, a distance of 120.12 feet to a
point in last said Northeasterly right of way line;

Thence South 56 degrees 28 minutes 30 seconds East, along last said right of way
line, a distance of 359.47 feet to the TRUE POINT OF BEGINNING; and

EXCEPT that certain tract of land  situated in the Southwest  quarter of Section
23, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo
County, Arizona, being more particularly described as follows:

COMMENCING at the brass cap that marks the Southwest  corner of Section 23, from
whence the brass cap that marks the Northwest corner of said Section bears North
0 degrees 2 minutes 5 seconds West;

Thence North 61 degrees 33 minutes 56 seconds East a distance of 1368.08 feet to
a 5/8 inch rebar that marks the Southeasterly  corner of said tract and the TRUE
POINT OF BEGINNING;

Thence  North 57 degrees 23 minutes 27 seconds West a distance of 357.99 feet to
a 5/8 inch rebar;

Thence  North 32 degrees 36 minutes 33 seconds East a distance of 117.67 feet to
a 5/8 inch rebar;

Thence  North 72 degrees 58 minutes 14 seconds East a distance of 114.71 feet to
a 5/8 inch rebar;

Thence  North 32 degrees 36 minutes 33 seconds East a distance of 555.92 feet to
a brass cap set in concrete;

Thence  South 77 degrees 44 minutes 13 seconds East a distance of 273.73 feet to
a 5/8 inch rebar;

Thence  South 32 degrees 36 minutes 33 seconds West a distance of 256.05 feet to
a 5/8 inch rebar;

Thence South 57 degrees 23 minutes 27 seconds East a distance of 27.06 feet to a
5/8 inch rebar;

Thence  South 32 degrees 36 minutes 33 seconds West a distance of 600.12 feet to
the TRUE POINT OF BEGINNING; and

EXCEPT that certain tract of land  situated in the Southwest  quarter of Section
23, Township 18 North, Range 19 East of the Gila and Salt River Meridian, Navajo
County, Arizona, being more particularly described as follow:

COMMENCING at the brass cap that marks the Southwest  corner of Section 23, from
whence the brass cap that marks the Northwest corner of said Section bears North
0 degrees 2 minutes 5 seconds West;

Thence  North 9 degrees 43 minutes 57 seconds East a distance of 1364.55 feet to
the 5/8 inch rebar that  marks the most  Southerly  corner of said tract and the
TRUE POINT OF BEGINNING;

Thence  North 34 degrees 53 minutes 35 seconds West a distance of 144.40 feet to
a 5/8 inch rebar;

                                       34
<PAGE>
Thence North 55 degrees 6 minutes 25 seconds East a distance of 439.58 feet to a
5/8 inch rebar;

Thence South 34 degrees 53 minutes 35 seconds East a distance of 85.73 feet to a
5/8 inch rebar;

Thence South 55 degrees 6 minutes 25 seconds West a distance of 276.35 feet to a
5/8 inch rebar;

Thence South 34 degrees 53 minutes 35 seconds East a distance of 58.67 feet to a
5/8 inch rebar;

Thence  South 55 degrees 6 minutes 25 seconds  West a distance of 163.23 feet to
the TRUE POINT OF BEGINNING; and

EXCEPT all those parts thereof  lying within the  Atchison,  Topeka and Santa Fe
Railroad Companys' 200 foot wide fee owned right of way; and

EXCEPT all oil,  gas and  minerals as  reserved in Deed  recorded in Docket 129,
page 481, records of Navajo County, Arizona, affects Section 25; and

EXCEPT 1/16th of all oil, gases and other hydrocarbon  substances,  coal, stone,
metals,  minerals,  fossils and  fertilizers of every name and  description  and
except  all  materials  which may be  essential  to  production  of  fissionable
materials as reserved in Arizona Revised Statutes, affects Section 36; and

EXCEPT all oil,  gas and sodium as reserved  to the United  States of America in
Patent to the West half of the Northwest quarter of Section 26.

WELL FIELD

PARCEL 1:

The North Half;
The Southeast quarter;
The North  half of the  Southwest  quarter;  and The  Southeast  quarter  of the
Southwest quarter of Section 4,
Township  17 North,  Range 19 East of the Gila and Salt River  Meridian,  Navajo
County, Arizona;

EXCEPT the following two parcels:

(1) In the Northeast  quarter of Section 4, Township 17 North,  Range 19 East of
the Gila and Salt River and Meridian,  Navajo County, Arizona, more particularly
described as follows:

FROM the Northeast corner of said Section 4;

thence South (assumed  bearing) along the East line of the Northeast  quarter of
said Section 4, a distance of 900.00 feet;

Thence  West 25.00 feet to the point of  beginning  of the parcel of land herein
described and the Northeast corner thereof;
         Thence West 460.00 feet;
         Thence South 460.00 feet;
         Thence East 460.00 feet;
Thence North 460.00 feet to the POINT OF BEGINNING.

                                       35
<PAGE>
(2) A rectangular  shaped parcel of land in the Northeast  quarter of Section 4,
Township 17 North, Range 19 East of the Gila and Salt River and Meridian, Navajo
County, Arizona, more particularly described as follows:

COMMENCING  at the  Northeast  corner of said Section 4; thence  South  (assumed
bearing) along the East line of said Section 4, a distance of 1360.00 feet;

Thence West 25.00 feet to the  Southeast  corner of that certain  parcel of land
described in Deed to Mountain States Telephone and Telegraph Company recorded in
Docket 151,  page 497,  and the TRUE POINT OF  BEGINNING  for the parcel  herein
described;

Thence South 400.00 feet;

Thence West 460.00 feet;

Thence North  400.00 feet to the  Southwest  corner of said parcel  described in
Docket 151, page 497;

Thence East along the South line of last said parcel,  a distance of 460.00 feet
to the POINT OF BEGINNING.

PARCEL 2:

The Southwest  quarter of the Southwest quarter of Section 4, Township 17 North,
Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona.

PARCEL 3:

The Southeast quarter of Section 2, Township 17 North, range 19 East of the Gila
and Salt River Meridian, Navajo County, Arizona;

EXCEPT all oil, gas and other hydrocarbon substances, Helium or other substances
of a gaseous nature, coal, metals, minerals,  fossils,  fertilizer or every name
and description, together with all uranium, thorium, or any other material which
is or may be  determined  by the laws of the United  State,  or of this state or
decisions of court to be peculiarly  essential to the  production of fissionable
materials as reserved in Deed recorded in Book 509, page 438,  records of Navajo
County, Arizona. County, Arizona.

PARCEL 4:

The  East  half of the  Northwest  quarter  and the West  half of the  Northeast
quarter of Section  34,  Township  18 North,  Range 19 East of the Gila and Salt
River Meridian, Navajo County, Arizona;

EXCEPT all oil and/or minerals as reserved in Deed recorded in Book 31 of deeds,
page 310,  and  recorded  in Docket  688,  page 17,  records  of Navajo  County,
Arizona.

PARCEL 5:

The Southwest quarter of the Northwest quarter,  the North half of the Southwest
quarter,  and the  Northwest  quarter of the  Southeast  quarter of Section  34,
Township  18 North,  Range 19 East of the Gila and Salt River  Meridian,  Navajo
County, Arizona;

EXCEPT the  following  described  property  conveyed  by Special  Warranty  Deed
recorded in Document No. 2002-6843, records of Navajo County, Arizona:

                                       36
<PAGE>
COMMENCING at the Southwest  corner of Section 34, a 3" brass cap stamped A.P.S.
1977;

Thence  North 00 degrees 03 minutes 35 seconds  West 1338.47 feet along the West
section line;

Thence  North 89 degrees 56 minutes 02 seconds East 2390.60 feet to a 1/2" rebar
and tag LS 22290, the POINT OF BEGINNING;

Thence  North 00 degrees 08 minutes 50 seconds West 1082.24 feet to a 1/2" rebar
and tag LS 22290;

Thence  North 89 degrees 56 minutes 02 seconds East 1609.99 feet to a 1/2" rebar
and tag LS 22290;

Thence  South 00 degrees 08 minutes 50 seconds East 1082.24 feet to a 1/2" rebar
and tag LS 22290;

Thence  South 89 degrees 56 minutes 02 seconds West 1609.99 feet to the POINT OF
BEGINNING.

PARCEL 6:

Section  28,  Township  18  North,  Range 19 East of the  Gila  and  Salt  River
Meridian, Navajo County, Arizona;

EXCEPT all oil,  gas and  minerals  reserved in Docket 168,  page 155,  from the
Southeast  quarter and the South half of the Northeast quarter and the Northwest
quarter of the Northeast quarter.

PARCEL 7:

The  Southwest  quarter of Section 21,  Township 18 North,  Range 19 East of the
Gila and Salt River Meridian, Navajo County, Arizona;

EXCEPT any part of the  Southwest  quarter  lying  North of the Little  Colorado
River.

PARCEL 8:

The South half of Section 6,  Township  17 North,  Range 20 East of the Gila and
Salt River Meridian, Navajo County, Arizona;

EXCEPT all coal and other  minerals as reserved in Patent from United  States of
America; and

EXCEPT the East 219 acres thereof.

PARCEL 9:

The East 219 acres of the South half of Section 6,  Township 17 North,  Range 20
East of the Gila Salt River and Meridian, Navajo County, Arizona;

EXCEPT all coal and other  minerals as reserved in Patent from United  States of
America.

PARCEL 10:

Section  10 ,  Township  17  North,  Range 19 East of the  Gila  and Salt  River
Meridian, Navajo County, Arizona;

EXCEPT all minerals in Patent from United States of America.

                                       37
<PAGE>
FLY ASH

PARCEL 1:

The West half of the West half of the Northwest quarter of the Northwest quarter
and the West half of the  Northwest  quarter  of the  Southwest  quarter  of the
Northwest  quarter of Section 29,  Township 18 North,  Range 20 East of the Gila
and Salt River Meridian, Navajo County, Arizona.

PARCEL 2:

The West half of the East half of the West half of the Northwest  quarter of the
Northwest quarter and the West half of the East half of the Northwest quarter of
the Southwest quarter of the Northwest quarter of Section 29, Township 18 North,
Range 20 East of the Gila and Salt River Meridian, Navajo County, Arizona.

EXCEPT all oil and gas as  conveyed  in Book 11 of Deeds,  page 355,  records of
Navajo County, Arizona.

PARCEL 3:

COMMENCING at the Northeast  corner of Section 25,  Township 18 North,  Range 19
East of Gila and Salt River Meridian;

Thence  along said  Section line South 88 degrees 35 minutes West for a distance
of 2460 feet to a point;

Thence South 43 degrees 30 minutes East for a distance of 380 feet to a point;

Thence South 36 degrees 35 minutes East for a distance of 2180 feet to a point;

Thence  South 63 degrees 50 minutes  East for a distance of 1000 feet to a point
on the East section line of said Section 25;

Thence North 2530 feet to the POINT OF BEGINNING,  being in Section 25, Township
18 North, Range 19 East of the Gila and Salt River and Meridian;

And  including  all land in said  Section  25  located on the North side of U.S.
Highway 66 (now Interstate Highway 40), Navajo County, Arizona;

EXCEPT  beginning  at a point of  Section  tine 1300 feet West of the  Northeast
corner of Section 25, Township 18 North, Range 19 East;

Thence West on Section line 1095 feet;

Thence South 37 degrees 49 minutes East 1100 feet;

Thence North 32 degrees 25 minutes East 210.6 feet;

Thence North 61 degrees 51 minutes East 600 feet;

Thence North 26 degrees 17 minutes West 460 feet to the PLACE OF BEGINNING; and

EXCEPT that portion of which lies  Southwesterly of the  Northeasterly  right of
way line of existing U.S. Highway 66 (now Interstate Highway 40).

                                       38
<PAGE>
PARCEL 4:

The East half of the Southeast  quarter of the Southeast  quarter of Section 24,
Township  18 North,  Range 19 East of the Gila and Salt River  Meridian,  Navaho
County, Arizona.

EXCEPT all the oil, gas,  sodium and potassium as reserved in Patent from United
States of America.

PARCEL 5:

The South half of the Southwest quarter of Section 19, Township 18 North,  Range
20 East of the Gila and Salt River Meridian, Navajo County, Arizona.

PARCEL 6:

All of Section 30 North of the Northerly  boundary of  Interstate  Highway 40 in
Township  18 North,  Range 20 East of the Gila and Salt River  Meridian,  Navajo
County, Arizona;

EXCEPT the Southeast  quarter of the Southeast  quarter and the East half of the
Southwest  quarter of the  Southeast  quarter of Section 30,  Township 18 North,
Range 20 East of the Gila and Salt River Meridian, Navajo County, Arizona; and

EXCEPT all oil, gas and mineral  rights as reserved in Patent from United States
of America.

BOTTOM ASH

PARCEL 1:

The West half of the Southwest  quarter of Section 13, Township 18 North,  Range
19 East of the Gila and Salt River Meridian, Navajo County, Arizona;

EXCEPT all oil,  gas rights as  reserved  in Deed  recorded in Book 13 of Deeds,
page 164, records of Navajo County, Arizona.

PARCEL 2:

The West half of the Northwest quarter of the Northwest quarter of the Northwest
quarter;

The  North  half  of the  Northeast  quarter  of the  Northwest  quarter  of the
Northwest quarter of the Northwest quarter;

The Southwest  quarter of the Northeast  quarter of the Northwest quarter of the
Northwest quarter of the Northwest quarter;

The Northwest  quarter of the Southeast  quarter of the Northeast quarter of the
Northwest quarter of the Northwest quarter of the Northwest quarter;

The West half of the West half of the Southeast quarter of the Northwest quarter
of the Northwest quarter of the Northwest quarter;

The  North  half  of the  Northeast  quarter  of the  Northwest  quarter  of the
Southeast  quarter  of the  Northwest  quarter of the  Northwest  quarter of the
Northwest  quarter of Section 24,  Township 18 North,  Range 19 East of the Gila
and Salt River Meridian, Navajo County, Arizona.

                                       39
<PAGE>
PARCEL 3:

The North half of the Northeast quarter of the Northeast quarter,  the Northeast
quarter of the

Northwest  quarter of the  Northeast  quarter of Section 23,  Township 18 North,
Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona.

PARCEL 4:

The East half of the Northeast quarter of the Southeast quarter;

The Southwest quarter of the Northeast quarter of the Southeast quarter;

The East half of the Southwest quarter of the Southeast quarter; and

The Southeast quarter of the Southeast quarter of Section 14, Township 18 North,
Range 19 East of the Gila and Salt River Meridian, Navajo County, Arizona;

Except all oil,  gas,  sodium and  potassium  as  reserved in Patent from United
States of America.

                                 YAVAPAI COUNTY

                             MCGUIREVILLE SUBSTATION

The West 250.00 feet of the following described parcel:

A parcel of land  located in the  Southeast  quarter of Section 33,  Township 15
North Range 5 East of the Gila and Salt River Base and Meridian, Yavapai County,
Arizona, described as follows:

Commencing   at  the   Southeast   corner  of  said  Section  33;  thence  North
89(degree)41'00"  West 2694.12 feet to the  Southwest  corner of said  Southeast
quarter;  thence  North  01(degree)01'25"  East,  along  the  West  line of said
Southeast  quarter,  1051.66  feet  to  the  true  point  of  beginning;  thence
continuing  North  01(degree)01'25"  East,  along said West line,  280.00  feet;
thence South 88(degree)25'00" East, 660.13 feet;
thence South  11053'50"  East,  along the West line of an easement  created by a
combination of the deeds  recorded in Book 187 of Deeds,  Page 174 and Book 1396
of Official Records, Page 937 a distance of 287.92 feet; thence 88(degree)25'00"
West 724.51 feet to the true point of beginning.

Together  with an easement for ingress,  egress and  utilities set forth in deed
recorded in Book 3214 of Official Records, Page 318.

     SECTION  11.  THE  ELECTRIC  SUBSTATIONS  OF  THE  COMPANY,  including  all
buildings,  structures, towers, poles, all equipment, appliances and devices for
transforming, converting and distributing electric energy, and all land owned by
the  Company  upon  which  the  same  are  situated,  and  all of the  Company's
easements,  rights of way, rights, machinery,  equipment,  appliances,  devices,
licenses  and  supplies  forming  a part of said  substations,  or any of  them,
including additions and improvements to any of the foregoing, or used or enjoyed
or capable of being use or enjoyed in conjunction with any thereof.

     SECTION  12.  Additions,   extensions  and  improvements  to  THE  ELECTRIC
TRANSMISSION SYSTEMS of the Company.

                                       40
<PAGE>
     SECTION  13.  Additions,   extensions  and  improvements  to  THE  ELECTRIC
DISTRIBUTION SYSTEMS of the Company,  including,  the construction of additional
facilities  throughout  the  Company's  service  area,  as well as  extension of
residential  and  downtown  underground   distribution   facilities,   including
associated  distribution equipment such as voltage regulators,  capacitor banks,
sectionalizing  equipment,  transformers,  street lighting  systems,  meters and
services, including reconstruction and improvements to provide efficient Company
operation.

                                       41
<PAGE>
     IN WITNESS  WHEREOF,  ARIZONA PUBLIC SERVICE  COMPANY,  party hereto of the
first  part,  has caused its  corporate  name to be hereunto  affixed,  and this
instrument to be signed and sealed by its President, one of its Vice Presidents,
or its Treasurer,  and its corporate seal to be attested by its Secretary or one
of its Assistant  Secretaries or Associate Secretaries for and in its behalf, in
the City of  Phoenix,  Arizona,  and THE BANK OF NEW YORK,  party  hereto of the
second part,  has caused its  corporate  name to be hereunto  affixed,  and this
instrument  to be signed and sealed by one of its Vice  Presidents  or Assistant
Vice  Presidents  and its corporate  seal to be attested by one of its Assistant
Vice  Presidents or Assistant  Treasurers for and in its behalf,  in the City of
New York, New York, all as of the 1st day of November, 2002.


                                        ARIZONA PUBLIC SERVICE COMPANY


                                          Barbara M. Gomez
                                          --------------------------------------
                                                         TREASURER


Attest:

Betsy A. Pregulman
--------------------------------------
      ASSOCIATE SECRETARY

Executed, sealed and delivered by
  ARIZONA PUBLIC SERVICE COMPANY
  in the presence of:


--------------------------------------

                                                          [SEAL]
--------------------------------------


                                          THE BANK OF NEW YORK, As Trustee


                                          Debra A. Schwalb
                                          --------------------------------------
                                                       VICE PRESIDENT
Attest:

Thomas J. Provenzano
--------------------------------------
Executed, sealed and delivered by
  THE BANK OF NEW YORK in the
  presence of:

Thomas J. Provenzano
--------------------------------------
Thomas J. Provenzano
Vice President


                                                          [SEAL]

                                       42
<PAGE>
STATE OF ARIZONA..         )
                                    ) ss.:
COUNTY OF MARICOPA                  )

     On this  1st day of  November,  2002,  before  me,  Debra L.  Blondin,  the
undersigned  officer,  personally  appeared  Barbara M. Gomez,  who acknowledged
herself  to be the  Treasurer  of ARIZONA  PUBLIC  SERVICE  COMPANY,  an Arizona
corporation, and that she, as such Treasurer being authorized so to do, executed
the foregoing instrument for the purposes therein contained, by signing the name
of the corporation by herself as Treasurer.

     IN WITNESS WHEREOF, I have hereunto set my hand and seal.


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

                                          My Commission Expires June 7, 2004
                                                                ----------------
[SEAL]


STATE OF ARIZONA                    )
                                    ) ss.:
COUNTY OF MARICOPA                  )

     On this  1st day of  November,  2002,  before  me,  Debra L.  Blondin,  the
undersigned officer, personally came Barbara M. Gomez, to me known, who being by
me duly sworn, did depose and say that she resides in Phoenix, Arizona, that she
is the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, the corporation described in
and  which  executed  the  above  instrument;  that she  knows  the seal of said
corporation;  that the seal affixed to said  instrument is such corporate  seal;
that it was so affixed by order of the Board of Directors  of said  corporation,
and that she signed her name thereto by like order.

     IN WITNESS WHEREOF, I have hereunto set my hand and seal.


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

                                          My Commission Expires June 7, 2004
                                                                ----------------
[SEAL]


STATE OF ARIZONA                    )
                                    ) ss.:
COUNTY OF MARICOPA                  )

     This instrument was  acknowledged  before me on November 1, 2002 by Barbara
M.  Gomez  and  Betsy  A.  Pregulman,  as  Treasurer  and  Associate  Secretary,
respectively, of ARIZONA PUBLIC SERVICE COMPANY.


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

                                          My Commission Expires June 7, 2004
                                                                ----------------
[SEAL]

                                       43
<PAGE>
STATE OF NEW JERSEY                 )
                                    ) ss.:
COUNTY OF PASSAIC                   )

     On this 1st day of  November,  2002,  before me,  Ronald M.  Mania,  Notary
Public  in and for the  County  and  State  aforesaid,  residing  therein,  duly
commissioned and sworn,  personally appeared Debra A. Schwalb, known to me to be
a Vice President of THE BANK OF NEW YORK, a New York banking corporation,  which
executed the within  instrument,  and Thomas J. Provenzano,  known to me to be a
Vice President of The Bank of New York, who being by me duly sworn, acknowledged
before me that the seal affixed to said  instrument is the corporate seal of The
Bank of New York,  that they,  being  authorized  so to do,  executed the within
instrument  on  behalf  of The Bank of New  York by  authority  of its  board of
directors,  and that said instrument is the free act and deed of The Bank of New
York for the purposes therein contained.

     IN WITNESS  WHEREOF,  I have  hereunto  set my hand and affixed my official
seal the day and year in this certificate first above written.

                                          Ronald M. Mania
                                          --------------------------------------
                                                       Notary Public


                                          My Commission Expires     10/4/2006
                                                                ----------------
[SEAL]


STATE OF NEW JERSEY                 )
                                    ) ss.:
COUNTY OF PASSAIC                   )

     This instrument was acknowledged  before me on November 1, 2002 by Debra A.
Schwalb and Thomas J.  Provenzano,  each as a Vice  President of THE BANK OF NEW
YORK.

                                          Ronald M. Mania
                                          --------------------------------------
                                                       Notary Public


                                          My Commission Expires     10/4/2006
                                                                ----------------
[SEAL]

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.2
<SEQUENCE>5
<FILENAME>ex4-2.txt
<DESCRIPTION>57TH SUPPLEMENTAL INDENTURE
<TEXT>
                                                                     Exhibit 4.2

================================================================================

                         ARIZONA PUBLIC SERVICE COMPANY
               (formerly Central Arizona Light and Power Company)

                                       TO

                              THE BANK OF NEW YORK


                                      AS TRUSTEE UNDER CENTRAL ARIZONA LIGHT AND
                                               POWER COMPANY'S MORTGAGE AND DEED
                                             OF TRUST, DATED AS OF JULY 1, 1946.


                                 ---------------


                      Fifty-Seventh Supplemental Indenture


                                 ---------------


                            DATED AS OF MARCH 1, 2003


                       This Mortgage covers real property,
                         personal property and chattels.


              This instrument and the above-mentioned Mortgage and
           Deed of Trust contain after-acquired property provisions.

================================================================================
<PAGE>
                      FIFTY-SEVENTH SUPPLEMENTAL INDENTURE

                                 ---------------

     INDENTURE, dated as of the 1st day of March, 2003, made and entered into by
and between  ARIZONA  PUBLIC  SERVICE  COMPANY,  a  corporation  of the State of
Arizona,  the  principal  place of business and mailing  address of which is 400
North Fifth Street,  Phoenix,  Arizona 85004  (hereinafter  sometimes called the
Company),  party of the first part, and THE BANK OF NEW YORK, a New York banking
corporation,  the  mailing  address of which is 385 Rifle Camp Road,  3rd Floor,
West  Paterson,  New Jersey 07424  (hereinafter  sometimes  called the Trustee),
party of the second part, as Trustee under the Mortgage and Deed of Trust, dated
as of July 1,  1946  (hereinafter  called  the  Mortgage),  which  Mortgage  was
executed and  delivered by the Company  under its former name,  Central  Arizona
Light and Power  Company,  to secure the payment of bonds issued or to be issued
under and in accordance with the provisions of the Mortgage,  reference to which
said  Mortgage  is  hereby  made,   this  Indenture   (hereinafter   called  the
Fifty-seventh Supplemental Indenture) being supplemental thereto;

     WHEREAS,  said  Mortgage was recorded and filed in Counties in the State of
Arizona as follows:

<TABLE>
<CAPTION>
                                                                              FILED AND ABSTRACTED
                                                RECORDED AS REAL MORTGAGE     AS CHATTEL MORTGAGE
                                               ---------------------------    --------------------
                                                                                 CHATTEL
                                                 DATE      BOOK OR              MORTGAGE
                    COUNTY                     RECORDED     DOCKET    PAGE        BOOK      PAGE
                    ------                     --------     ------    ----        ----      ----
<S>                                            <C>         <C>        <C>         <C>       <C>
     Apache...........................          7-28-50      16          1          9        154
     Cochise..........................           2-3-53      80         28         19        292
     Coconino.........................          1-20-53      39          1         10        286
     Gila.............................          1-17-53      32         84         17         --
     Graham...........................          12-3-63      92         87         15        223
     Maricopa.........................           8-6-46     408        163         92        204
     Mohave...........................         11-13-57      28         68         12        13
     Navajo...........................         10-14-49      31        483         16        521
     Pima.............................          1-24-53     558        351         14         --
     Pinal............................         10-25-52      68         31         12        591
     Yavapai..........................           8-7-46      79          1         12        223
     Yuma.............................           8-1-47      58        173         21        265

and in Counties in the State of New Mexico as follows:

     McKinley.........................          5-31-61      36        153          4        295
     San Juan.........................          1-31-61     472        140          (No. 72441)
</TABLE>

the copy  recorded  in Yuma  County,  Arizona  also being  effective  for La Paz
County,  Arizona,  formed on December 31, 1982; and copies of said Mortgage were
filed with the office of the Bureau of Indian  Affairs at Window Rock,  Arizona,
and with the Navajo Tribe of Indians at Window Rock, Arizona, and in the offices
of the Secretary of State and the State Land  Department of the State of Arizona
(all the said  counties  and the said  offices  above  referred to being  herein
referred to as "jurisdictions"); and

     WHEREAS, by the Mortgage,  the Company covenanted that it would execute and
deliver such supplemental  indenture or indentures and such further  instruments
and do such  further  acts as might be  necessary  or  proper  to carry out more
effectually  the purposes of the Mortgage and to make subject to the Lien of the

                                       2
<PAGE>
Mortgage any property thereafter  acquired,  made or constructed and intended to
be subject to the Lien thereof; and

     WHEREAS,  the Company has executed and  delivered to the Trustee  fifty-six
indentures  supplemental to the Mortgage  (hereinafter  respectively  called the
First through the Fifty-sixth  Supplemental  Indentures) dated as of December 1,
1947,  April 1, 1949,  February  1, 1950,  December  1, 1950,  February 1, 1953,
November 1, 1953,  March 1, 1954,  October 1, 1957,  March 1, 1959,  November 1,
1961,  June 1, 1962,  December 1, 1962,  September  1, 1963,  September 1, 1967,
April 1, 1970, March 15, 1972,  April 1, 1974,  February 15, 1975, June 1, 1975,
November 15, 1975, April 15, 1977,  January 15, 1978, March 1, 1979, October 15,
1979, May 15, 1980,  February 2, 1982, April 15, 1982, July 1, 1983, October 15,
1983, June 15, 1984,  January 15, 1985, May 1, 1985,  June 1, 1985,  November 1,
1985,  January 15, 1986,  March 1, 1986, May 1, 1986,  February 1, 1987, June 1,
1987,  November 15, 1987, April 1, 1989,  February 15, 1990, May 15, 1990, April
15, 1991,  December 15, 1991,  January 15, 1992,  March 1, 1992,  June 15, 1992,
February 1, 1993, August 1, 1993,  August 1, 1993,  September 15, 1993, March 1,
1994,  November 15, 1996, April 1, 1997, and November 1, 2002, each of which has
been or will be  recorded  or filed in, or a  recording  or filing is or will be
effective with respect to, each jurisdiction referred to above; and

     WHEREAS,  in  addition  to  the  property  described  in the  Mortgage,  as
heretofore  supplemented  and amended,  the Company has acquired  certain  other
property, rights and interests in property; and

     WHEREAS,  the  Company  has  heretofore  issued,  in  accordance  with  the
provisions of the Mortgage, as heretofore  supplemented and amended,  bonds of a
series  entitled and  designated  First Mortgage  Bonds,  2-3/4% Series due 1976
(hereinafter  called the bonds of the First Series),  in the aggregate principal
amount of Eight Million Five Hundred Thousand Dollars  ($8,500,000);  bonds of a
series  entitled and  designated  First Mortgage  Bonds,  3-1/8% Series due 1977
(hereinafter  called the bonds of the Second Series), in the aggregate principal
amount of Two Million Five Hundred  Thousand  Dollars  ($2,500,000);  bonds of a
series  entitled  and  designated  First  Mortgage  Bonds,  3%  Series  due 1979
(hereinafter  called the bonds of the Third Series),  in the aggregate principal
amount of Four  Million  Dollars  ($4,000,000);  bonds of a series  entitled and
designated First Mortgage Bonds,  2-3/4% Series due 1980 (hereinafter called the
bonds of the Fourth Series),  in the aggregate  principal amount of Five Million
Dollars  ($5,000,000);  bonds of a series entitled and designated First Mortgage
Bonds,  2-7/8%  Series  due 1980  (hereinafter  called  the  bonds of the  Fifth
Series), in the aggregate principal amount of Six Million Dollars  ($6,000,000);
bonds of a series entitled and designated  First Mortgage  Bonds,  3-1/2% Series
due 1983  (hereinafter  called the bonds of the Sixth Series),  in the aggregate
principal   amount  of  Fourteen   Million   Five   Hundred   Thousand   Dollars
($14,500,000); bonds of a series entitled and designated First Mortgage Bonds, 3
1/2% Series due  November 1, 1983  (hereinafter  called the bonds of the Seventh
Series),  in the  aggregate  principal  amount  of Five  Million  Seven  Hundred
Twenty-three  Thousand  Dollars  ($5,723,000);  bonds of a series  entitled  and
designated First Mortgage Bonds,  3-1/4% Series due 1984 (hereinafter called the
bonds of the  Eighth  Series),  in the  aggregate  principal  amount of  Fifteen
Million Dollars  ($15,000,000);  bonds of a series entitled and designated First
Mortgage  Bonds,  5-1/8%  Series due 1987  (hereinafter  called the bonds of the
Ninth Series),  in the aggregate  principal  amount of Fifteen  Million  Dollars
($15,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
4.70% Series due 1989 (hereinafter called the bonds of the Tenth Series), in the
aggregate principal amount of Twenty Million Dollars  ($20,000,000);  bonds of a
series  entitled and  designated  First  Mortgage  Bonds,  4.80% Series due 1991
(hereinafter  called  the  bonds  of the  Eleventh  Series),  in  the  aggregate
principal amount of Thirty-five Million Dollars ($35,000,000); bonds of a series
entitled and designated First Mortgage Bonds, 4.45% Series due 1992 (hereinafter
called the bonds of the Twelfth  Series),  in the aggregate  principal amount of
Twenty-five  Million  Dollars  ($25,000,000);  bonds  of a series  entitled  and

                                       3
<PAGE>
designated First Mortgage Bonds,  4.40% Series due 1992 (hereinafter  called the
bonds  of  the  Thirteenth   Series),  in  the  aggregate  principal  amount  of
Twenty-five  Million  Dollars  ($25,000,000);  bonds  of a series  entitled  and
designated First Mortgage Bonds,  4.50% Series due 1993 (hereinafter  called the
bonds of the Fourteenth  Series),  in the aggregate  principal amount of Fifteen
Million Dollars  ($15,000,000);  bonds of a series entitled and designated First
Mortgage  Bonds,  6.25%  Series  due 1997  (hereinafter  called the bonds of the
Fifteenth  Series),  in the aggregate  principal  amount of Twenty-five  Million
Dollars ($25,000,000);  bonds of a series entitled and designated First Mortgage
Bonds,  8.50%  Series due 1975  (hereinafter  called the bonds of the  Sixteenth
Series),   in  the  aggregate   principal   amount  of  Thirty  Million  Dollars
($30,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
7.45% Series due 2002 (hereinafter called the bonds of the Seventeenth  Series),
in the aggregate principal amount of Sixty Million Dollars ($60,000,000);  bonds
of a series entitled and designated First Mortgage Bonds,  6.20% Series due 2004
(hereinafter  called  the  bonds of the  Eighteenth  Series),  in the  aggregate
principal  amount  of Fifty  Million  Dollars  ($50,000,000);  bonds of a series
entitled and designated First Mortgage Bonds, 9.50% Series due 1982 (hereinafter
called the bonds of the Nineteenth Series), in the aggregate principal amount of
One Hundred  Million  Dollars  ($100,000,000);  bonds of a series  entitled  and
designated First Mortgage Bonds,  9.80% Series due 1980 (hereinafter  called the
bonds  of  the  Twentieth  Series),   in  the  aggregate   principal  amount  of
Seventy-five  Million  Dollars  ($75,000,000);  bonds of a series  entitled  and
designated First Mortgage Bonds, 10.625% Series due 2000 (hereinafter called the
bonds  of  the  Twenty-first  Series),  in the  aggregate  principal  amount  of
Seventy-five  Million  Dollars  ($75,000,000);  bonds of a series  entitled  and
designated First Mortgage Bonds, 6.45% Series A due 2007 (hereinafter called the
bonds  of the  Twenty-second  Series),  in the  aggregate  principal  amount  of
Thirteen  Million  Dollars  ($13,000,000);   bonds  of  a  series  entitled  and
designated First Mortgage Bonds, 6.45% Series B due 2007 (hereinafter called the
bonds of the Twenty-third  Series),  in the aggregate principal amount of Thirty
Million Dollars  ($30,000,000);  bonds of a series entitled and designated First
Mortgage  Bonds,  6%  Series A due 2008  (hereinafter  called  the  bonds of the
Twenty-fourth  Series), in the aggregate principal amount of Thirty-four Million
Dollars ($34,000,000);  bonds of a series entitled and designated First Mortgage
Bonds,  9.95% Series due 2004 (hereinafter  called the bonds of the Twenty-fifth
Series),  in the aggregate  principal  amount of  Seventy-five  Million  Dollars
($75,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
12-1/8%  Series  due 2009  (hereinafter  called  the  bonds of the  Twenty-sixth
Series),  in the aggregate  principal  amount of  Seventy-five  Million  Dollars
($75,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
12-7/8%  Series due 2000  (hereinafter  called  the bonds of the  Twenty-seventh
Series),  in the aggregate  principal amount of One Hundred  Eighty-five Million
Dollars ($185,000,000); bonds of a series entitled and designated First Mortgage
Bonds,   10-3/8%  Series  due  1985   (hereinafter   called  the  bonds  of  the
Twenty-eighth  Series),  in the aggregate  principal amount of Sixty Million Two
Hundred Fifty Thousand  Dollars  ($60,250,000);  bonds of a series  entitled and
designated  First Mortgage Bonds,  16% Series due 1992  (hereinafter  called the
bonds of the  Twenty-ninth  Series),  in the aggregate  principal  amount of One
Hundred  Million  Dollars  ($100,000,000);   bonds  of  a  series  entitled  and
designated First Mortgage Bonds, 12-3/4% Series due 2013 (hereinafter called the
bonds of the Thirtieth Series), in the aggregate principal amount of One Hundred
Million Dollars ($100,000,000);  bonds of a series entitled and designated First
Mortgage  Bonds,  13-1/2% Series due 2013  (hereinafter  called the bonds of the
Thirty-first  Series),  in the aggregate principal amount of One Hundred Million
Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage
Bonds, 15% Series due 1994  (hereinafter  called the bonds of the  Thirty-second
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
12% Series due 1995 (hereinafter  called the bonds of the Thirty-third  Series),
in the aggregate  principal  amount of  One Hundred  Twenty-five Million Dollars
($125,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
13-1/4%  Series  due 2007  (hereinafter  called  the bonds of the  Thirty-fourth
Series),   in  the  aggregate   principal   amount  of  Fifty  Million   Dollars
($50,000,000);  bonds of a series entitled and designated  First Mortgage Bonds,
11-1/2%  Series  due 2015  (hereinafter  called  the  bonds of the  Thirty-fifth
Series),  in the aggregate principal amount of One Hundred Fifty Million Dollars
($150,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
11-1/2%  Series  due  November  1,  2015  (hereinafter  called  the bonds of the
Thirty-sixth  Series),  in the aggregate principal amount of One Hundred Million
Dollars ($100,000,000); bonds of a series entitled and designated First Mortgage

                                       4
<PAGE>
Bonds, 11% Series due 2016 (hereinafter  called the bonds of the  Thirty-seventh
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
9-1/4%  Series  due 1996  (hereinafter  called  the  bonds of the  Thirty-eighth
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
9% Series due 1996 (hereinafter called the bonds of the Thirty-ninth Series), in
the  aggregate  principal  amount of One  Hundred  Twenty-five  Million  Dollars
($125,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
9% Series due 2017 (hereinafter called the bonds of the Fortieth Series), in the
aggregate principal amount of One Hundred Fifty Million Dollars  ($150,000,000);
bonds of a series entitled and designated  First Mortgage  Bonds,  9-7/8% Series
due 1997  (hereinafter  called  the  bonds of the  Forty-first  Series),  in the
aggregate   principal  amount  of  One  Hundred   Twenty-five   Million  Dollars
($125,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
10-3/4%  Series  due 2017  (hereinafter  called  the  bonds of the  Forty-second
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
10-3/4%  Series  due 2019  (hereinafter  called  the  bonds  of the  Forty-third
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
10-1/4%  Series  due 2000  (hereinafter  called  the  bonds of the  Forty-fourth
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
10 1/4%  Series  due 2020  (hereinafter  called  the  bonds  of the  Forty-fifth
Series),  in the aggregate  principal amount of One Hundred  Twenty-five Million
Dollars ($125,000,000); bonds of a series entitled and designated First Mortgage
Bonds,  9-1/2% Series due 2021 (hereinafter  called the bonds of the Forty-sixth
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
9% Series due 2021 (hereinafter  called the bonds of the Forty-seventh  Series),
in  the  aggregate  principal  amount  of  One  Hundred  Fifty  Million  Dollars
($150,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
7-1/8% Series due 1997, in the aggregate  principal  amount of One Hundred Fifty
Million  Dollars  ($150,000,000),  and bonds of a series entitled and designated
First Mortgage Bonds,  8-3/4% Series due 2024, in the aggregate principal amount
of  One  Hundred  Seventy-five  Million  Dollars   ($175,000,000)   (hereinafter
collectively  called the bonds of the  Forty-eighth  Series);  bonds of a series
entitled and  designated  First Mortgage  Bonds,  7-5/8% Series due 1998, in the
aggregate  principal amount of One Hundred Million Dollars  ($100,000,000),  and
bonds of a series entitled and designated  First Mortgage  Bonds,  8-1/8% Series
due 2002, in the aggregate  principal amount of One Hundred  Twenty-five Million
Dollars  ($125,000,000)  (hereinafter  collectively  called  the  bonds  of  the
Forty-ninth  Series);  bonds of a series entitled and designated  First Mortgage
Bonds,  7-5/8%  Series due 1999  (hereinafter  called the bonds of the  Fiftieth
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
8% Series due 2025 (hereinafter called the bonds of the Fifty-first  Series), in
the  aggregate   principal   amount  of  One  Hundred   Fifty  Million   Dollars
($150,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
7-1/4%  Series  due 2023  (hereinafter  called  the  bonds  of the  Fifty-second
Series),  in the  aggregate  principal  amount of One  Hundred  Million  Dollars
($100,000,000);  bonds of a series entitled and designated First Mortgage Bonds,
5-7/8% Series due 2028 (hereinafter called bonds of the Fifty-third  Series), in
the aggregate  principal  amount of Twelve  Million Eight Hundred Fifty Thousand
Dollars ($12,850,000);  bonds of a series entitled and designated First Mortgage
Bonds,  5-7/8%  Series due 2028  (hereinafter  called bonds of the  Fifty-fourth
Series),  in the aggregate principal amount of One Hundred Forty-one Million One
Hundred Fifty Thousand  Dollars  ($141,150,000);  bonds of a series entitled and
designated  First Mortgage  Bonds,  5-1/2% Series due 2028  (hereinafter  called
bonds  of the  Fifty-  fifth  Series),  in the  aggregate  principal  amount  of
Twenty-five  Million  Dollars  ($25,000,000);  bonds  of a series  entitled  and
designated  First Mortgage  Bonds,  5-3/4% Series due 2000  (hereinafter  called
bonds of the  Fifty-sixth  Series)  in the  aggregate  principal  amount  of One
Hundred  Million  Dollars  ($100,000,000);   bonds  of  a  series  entitled  and
designated  First Mortgage  Bonds,  6-5/8% Series due 2004  (hereinafter  called
bonds of the  Fifty-seventh  Series) in the  aggregate  principal  amount of One

                                       5
<PAGE>
Hundred  Million  Dollars  ($100,000,000);   bonds  of  a  series  entitled  and
designated First Mortgage Bonds,  Senior Note Series A (hereinafter called bonds
of the  Fifty-eighth  Series) in the aggregate  principal  amount of One Hundred
Million Dollars ($100,000,000);  bonds of a series entitled and designated First
Mortgage  Bonds,   Senior  Note  Series  B  (hereinafter  called  bonds  of  the
Fifth-ninth  Series) in the aggregate  principal amount of Fifty Million Dollars
($50,000,000);  and bonds of a series  entitled and  designated  First  Mortgage
Bonds, Senior Note Series C (hereinafter called bonds of the Sixtieth Series) in
the aggregate principal amount of Ninety Million Dollars ($90,000,000); and

     WHEREAS, said The Bank of New York, by an instrument in writing,  effective
on the opening of business on September  29, 1995,  succeeded to Bank of America
National  Trust and Savings  Association  as Trustee  under the  Mortgage;  and,
pursuant to Section 104 of the  Mortgage,  The Bank of New York is the successor
Trustee under the Mortgage; and

     WHEREAS, Section 8 of the Mortgage provides that the form of each series of
bonds  (other  than  bonds  of the  First  Series)  issued  thereunder  shall be
established  by Resolution of the Board of Directors of the Company and that the
form of each series,  as established  by said Board of Directors,  shall specify
the descriptive title of the bonds and various other terms thereof, and may also
contain such provisions not inconsistent  with the provisions of the Mortgage as
the Board of  Directors  may, in its  discretion,  cause to be inserted  therein
expressing or referring to the terms and conditions upon which such bonds are to
be issued and/or secured under the Mortgage; and

     WHEREAS, Section 120 of the Mortgage provides, among other things, that any
power,  privilege  or right  expressly  or  impliedly  reserved to or in any way
conferred upon the Company by any provision of the Mortgage, whether such power,
privilege or right is in any way restricted or is unrestricted,  may be in whole
or in part waived or surrendered or subjected to any  restriction if at the time
unrestricted or to additional restriction if already restricted, and the Company
may enter  into any  further  covenants,  limitations  or  restrictions  for the
benefit of any one or more series of bonds issued thereunder, or the Company may
cure any ambiguity contained therein, or in any supplemental  indenture,  or may
establish the terms and  provisions of any series of bonds other than said First
Series,  by an instrument in writing executed and acknowledged by the Company in
such  manner as would be  necessary  to entitle a  conveyance  of real estate to
record in all of the  states in which any  property  at the time  subject to the
Lien of the Mortgage shall be situated; and

     WHEREAS,  the  Company  now  desires  to create a new series of bonds to be
issued under and pursuant to the Mortgage in accordance  with the  provisions of
Article VI thereof,  and to add to its covenants and agreements contained in the
Mortgage,  as heretofore  supplemented and amended,  certain other covenants and
agreements  to be observed by it and to alter and amend in certain  respects the
covenants and provisions contained in the Mortgage,  as heretofore  supplemented
and amended; and

     WHEREAS,  Maricopa  County,  Arizona  Pollution  Control  Corporation  (the
"Issuer") has issued  Fifty-Seven  Million  Dollars  ($57,000,000)  in aggregate
principal amount of the Maricopa County,  Arizona Pollution Control  Corporation
Pollution  Control Revenue  Refunding Bonds (Arizona Public Service Company Palo
Verde Project) 1994 Series C (the "Maricopa Bonds") pursuant to the Indenture of
Trust  dated as of May 1,  1994 (as  amended  from time to time,  the  "Maricopa
Indenture")  between the Issuer and The Bank of New York,  as trustee  (together
with its successors in such capacity, the "Maricopa Trustee"). The Issuer loaned
the proceeds of the Maricopa Bonds to the Company pursuant to the Loan Agreement
dated as of May 1, 1994 between the Issuer and the Company (as amended from time
to time,  the "Loan  Agreement"),  and the  Company  agreed to make  payments of
principal, premium, if any, and interest on, and purchase price of, the Maricopa
Bonds from time to time when due, to the extent  that  monies for such  payments
are not otherwise available pursuant to the terms of the Maricopa Indenture (the
"Loan Agreement Payment Obligations"); and

                                       6
<PAGE>
     WHEREAS, pursuant to the provisions of the Maricopa Indenture, the Maricopa
Bonds will bear  interest at a Term Rate (as defined in the Maricopa  Indenture)
during  the period  beginning  March 6, 2003 and ending on March 4, 2004 or such
earlier  termination  date as may occur  pursuant  to the terms of the  Maricopa
Indenture (the "Term Rate Period"); and

     WHEREAS,   in  order  to  secure  the  Company's  Loan  Agreement   Payment
Obligations  to and including the  hereinafter  defined  Termination  Date,  the
Company  desires to provide for the issuance  under the Mortgage of a new series
of bonds designated "1.70% First Mortgage Bonds,  Maricopa 1994 Series C, having
the same rate of interest,  payment dates and redemption  and tender  provisions
and in the same aggregate principal amount as the Maricopa Bonds; and

     WHEREAS,  the execution  and delivery by the Company of this  Fifty-seventh
Supplemental  Indenture,  and the terms of the bonds of the  Sixty-first  Series
hereinafter  referred to, have been duly authorized by the Board of Directors of
the Company by appropriate Resolutions of said Board of Directors;

     NOW  THEREFORE,  THIS  INDENTURE  WITNESSETH:  That Arizona  Public Service
Company,  in  consideration of the premises and of One Dollar to it duly paid by
the  Trustee at or before the  ensealing  and  delivery of these  presents,  the
receipt whereof is hereby acknowledged,  and in further evidence of assurance of
the estate,  title and rights of the Trustee and in order  further to secure the
payment of both the principal of and interest and premium,  if any, on the bonds
from time to time  heretofore,  herewith or hereafter issued under the Mortgage,
according to their tenor and effect,  and the  performance of all the provisions
of  the  Mortgage  (including  any  instruments  supplemental  thereto  and  any
modifications  made  as in the  Mortgage  provided)  and of said  bonds,  hereby
grants,  bargains,  sells, releases,  conveys,  assigns,  transfers,  mortgages,
pledges,  sets over and confirms (subject,  however, to Excepted Encumbrances as
defined in Section 6 of the Mortgage and to the liens permitted by Section 36 of
the Mortgage)  unto The Bank of New York, as Trustee under the Mortgage,  and to
its  successor  or  successors  in  said  trust,  and to  said  Trustee  and its
successors and assigns forever,  all the properties of the Company  described in
the Mortgage,  as heretofore  supplemented  and amended  (except any  properties
which have been released from the Lien of the Mortgage),  and all the properties
specifically described in Article V hereof.

     Also all other  property,  real,  personal and mixed, of the kind or nature
specifically  mentioned  in  Article  V hereof  or of any  other  kind or nature
(except any herein or in the Mortgage,  as heretofore  supplemented and amended,
expressly excepted and except any which may not lawfully be mortgaged or pledged
hereunder), now owned or, subject to the provisions of subsection (I) of Section
87  of  the   Mortgage,   hereafter   acquired  by  the  Company  (by  purchase,
consolidation, merger, donation, construction, erection or in any other way) and
wheresoever situated, including (without in anywise limiting or impairing by the
enumeration  of the same the scope and intent of the foregoing or of any general
description contained in this Fifty-seventh  Supplemental  Indenture) all lands,
power  sites,   flowage   rights,   water   rights,   water   locations,   water
appropriations,  ditches, flumes, reservoirs, reservoir sites, canals, raceways,
dams,  dam sites,  aqueducts,  and all other rights or means for  appropriating,
conveying,  storing and supplying water; all rights of way and roads; all plants
for the generation of electricity by steam,  water and/or other power; all power
houses,  gas plants,  street  lighting  systems,  standards and other  equipment
incidental thereto,  telephone,  radio and television systems,  air-conditioning
systems and equipment incidental thereto, water works, water systems, steam heat
and hot water plants,  substations,  lines, service and supply systems, bridges,
culverts, tracks, ice or refrigeration plants and equipment,  offices, buildings
and other structures and equipment  thereof;  all machinery,  engines,  boilers,
dynamos,  electric, gas and other machines,  regulators,  meters,  transformers,
generators, motors, electrical, gas and mechanical appliances, conduits, cables,
water,  steam heat,  gas or other  pipes,  gas mains and pipes,  service  pipes,
fittings,  valves and connections,  pole and transmission lines, wires,  cables,
tools, implements,  apparatus, furniture and chattels; all franchises,  consents
or permits; all lines for the transmission and distribution of electric current,

                                       7
<PAGE>
gas, steam heat or water for any purpose including towers, poles, wires, cables,
pipes,  conduits,  ducts and all apparatus for use in connection therewith;  all
real  estate,  lands,  easements,  servitudes,  licenses,  permits,  franchises,
privileges,  rights of way and other  rights in or relating to public or private
property,  real or personal,  or the  occupancy of such  property and (except as
herein or in the Mortgage,  as heretofore  supplemented  and amended,  expressly
excepted)  all the  right,  title  and  interest  the  Company  may now  have or
hereafter  acquire  in and to any  and  all  property  of  any  kind  or  nature
appertaining  to and/or used and/or  occupied  and/or enjoyed in connection with
any property  hereinbefore or in the Mortgage,  as heretofore  supplemented  and
amended, described.

     TOGETHER WITH all and singular the tenements, hereditaments, prescriptions,
servitudes  and  appurtenances  belonging  or in  anywise  appertaining  to  the
aforementioned  property or any part thereof, with the reversion and reversions,
remainder  and  remainders  and (subject to the  provisions of Section 57 of the
Mortgage) the tolls, rents,  revenues,  issues,  earnings,  income,  product and
profits  thereof,  and  all  the  estate,   right,  title,  interest  and  claim
whatsoever,  at law as well  as in  equity,  which  the  Company  now has or may
hereafter acquire in and to the aforementioned property and franchises and every
part and parcel thereof.

     IT IS HEREBY  AGREED by the  Company  that,  subject to the  provisions  of
subsection (I) of Section 87 of the Mortgage and to the extent permitted by law,
all the property,  rights and  franchises  acquired by the Company (by purchase,
consolidation,  merger,  donation,  construction,  erection or in any other way)
after the date  hereof,  except any  herein or in the  Mortgage,  as  heretofore
supplemented and amended,  expressly excepted, shall be and are as fully granted
and conveyed hereby and as fully embraced within the lien hereof and the Lien of
the Mortgage as if such property,  rights and  franchises  were now owned by the
Company and were specifically described herein and conveyed hereby.

     PROVIDED  that  the  following  are not and are not  intended  to be now or
hereafter granted, bargained, sold, released, conveyed,  assigned,  transferred,
mortgaged,  pledged,  set over or confirmed  hereunder and are hereby  expressly
excepted  from  the  lien  and  operation  of  this  Fifty-seventh  Supplemental
Indenture  and from the Lien and  operation  of the  Mortgage,  viz.:  (1) cash,
shares of stock,  bonds,  notes and other  obligations and other  securities not
hereafter  specifically pledged,  paid,  deposited,  delivered or held under the
Mortgage  or  covenanted  so  to  be;  (2)  merchandise,  equipment,  apparatus,
materials or supplies held for the purpose of sale or other  disposition  in the
usual  course  of  business;  fuel,  oil  and  similar  materials  and  supplies
consumable  in  the  operation  of  any  of  the   properties  of  the  Company;
construction  equipment  acquired for  temporary  use; all  aircraft,  tractors,
rolling stock, trolley coaches, buses, motor coaches, automobiles,  motor trucks
and other  vehicles and materials and supplies held for the purpose of repairing
or replacing (in whole or part) any of the same; all timber,  minerals,  mineral
rights and royalties and all Natural Gas and Oil Production Property, as defined
in  Section  4 of the  Mortgage;  (3)  bills,  notes  and  accounts  receivable,
judgments,  demands  and  chooses  in  action,  and all  contracts,  leases  and
operating  agreements not specifically  pledged under the Mortgage or covenanted
so to be; (4) the last day of the term of any lease or leasehold which may be or
become subject to the Lien of the Mortgage; (5) electric energy, gas, steam, ice
and other materials or products generated, manufactured,  produced, purchased or
acquired by the Company for sale,  distribution or use in the ordinary course of
its business;  and (6) the Company's  franchise to be a  corporation;  PROVIDED,
HOWEVER,  that the  property  and rights  expressly  excepted  from the Lien and
operation  of the Mortgage in the above  subdivisions  (2) and (3) shall (to the
extent permitted by law) cease to be so excepted in the event and as of the date
that the Trustee or a receiver or trustee  shall enter upon and take  possession
of the Mortgaged and Pledged  Property in the manner provided in Article XIII of
the Mortgage by reason of the  occurrence  of a Default as defined in Section 65
thereof.

     TO HAVE AND TO HOLD all such properties, real, personal and mixed, granted,
bargained, sold, released, conveyed, assigned, transferred,  mortgaged, pledged,
set over or  confirmed by the Company as  aforesaid,  or intended so to be, unto
The Bank of New York, the Trustee, and its successors and assigns forever.

                                       8
<PAGE>
     IN TRUST  NEVERTHELESS,  for the  same  purposes  and upon the same  terms,
trusts and conditions and subject to and with the same provisos and covenants as
are set forth in the Mortgage, as supplemented and amended.

     AND IT IS HEREBY COVENANTED by the Company that all the terms,  conditions,
provisos,  covenants and provisions  contained in the Mortgage,  as supplemented
and amended,  shall affect and apply to the property hereinbefore  described and
conveyed and to the estate,  rights,  obligations  and duties of the Company and
the Trustee and the  beneficiaries  of the trust with respect to said  property,
and to the Trustee and its  successors  as Trustee of said  property in the same
manner and with the same  effect as if the said  property  had been owned by the
Company at the time of the  execution of the Mortgage and had been  specifically
and at length  described  in and  conveyed to said  Trustee by the Mortgage as a
part of the property therein stated to be conveyed.

     The Company  further  covenants  and agrees to and with the Trustee and its
successors in said trust under the Mortgage, as follows:

                                   ARTICLE I.
                          SIXTY-FIRST SERIES OF BONDS.

     SECTION  1.  There  shall be a  series  of bonds  designated  "1.70%  First
Mortgage Bonds, Maricopa 1994 Series C (hereinafter sometimes referred to as the
"Sixty-first Series" or the "Bonds"),  limited to the aggregate principal amount
of  $57,000,000,  each of which  shall  also bear the  descriptive  title  First
Mortgage Bond, and the form thereof, which shall be established by Resolution of
the Board of Directors of the Company,  shall contain  suitable  provisions with
respect to the matters  hereinafter  specified in this  Supplemental  Indenture.
Bonds of the Sixty-first  Series shall be dated as provided in Section 10 of the
Mortgage;  shall be  issued  as a single  fully  registered  bond,  and shall be
registered  in the name of the  Maricopa  Trustee;  shall  evidence,  secure and
provide for the payment of the Company's Loan Agreement Payment Obligations; and
shall be payable on each date provided in or pursuant to the Maricopa  Indenture
for the payment of principal  (whether upon redemption or acceleration)  of, and
interest  on, the  Maricopa  Bonds,  until the  principal of and interest on the
Maricopa  Bonds shall have been fully paid or provision for the payment  thereof
shall have been made in accordance  with the Maricopa  Indenture,  in the amount
then payable as principal and interest upon the Maricopa Bonds; and on each date
provided  in or  pursuant  to the  Maricopa  Indenture  for the  payment  of the
purchase price of the Maricopa  Bonds  tendered for purchase in accordance  with
Section 2.01(d) or Section 2.01(e) of the Maricopa Indenture, in the amount then
payable as such purchase  price of the tendered  Maricopa  Bonds,  to the extent
proceeds of the remarketing of such tendered  Maricopa Bonds are insufficient to
pay the  purchase  price  thereof;  provided,  however,  that  the  Bonds  shall
terminate  and expire  and shall be of no further  force and effect at 5:00 p.m.
Eastern Standard Time on the Termination Date (defined below). The principal and
purchase  price of and  interest on the Bonds shall be payable by the Company to
the Maricopa Trustee,  as pledgee and assignee of the Issuer, in accordance with
the requirements of the Maricopa  Indenture.  All payments by the Company on the
Bonds shall be made on or prior to the due date thereof.

     The Bonds of the Sixty-first Series will terminate and expire, and be of no
further force and effect,  at 5:00 p.m. Eastern Standard Time on the earlier of:
(1) the  effective  date of the first Rate  Period (as  defined in the  Maricopa
Indenture)  immediately  following  the Term Rate  Period and (2) the first date
during or after the Term Rate Period on which the Maricopa  Bonds are subject to
mandatory tender pursuant to Section 2.01(e) of the Maricopa Indenture,  in each
case, as long as tendering holders of Maricopa Bonds have been paid the purchase

                                       9
<PAGE>
price for the  Maricopa  Bonds  pursuant  to any  optional or  mandatory  tender
occurring on the Termination Date and the Company is not otherwise in default in
its Loan Agreement  Payment  Obligations under Section 4.2 of the Loan Agreement
on such date.  In the event that on the date  specified  in clause (1) or (2) of
the immediately preceding sentence, tendering holders of Maricopa Bonds have not
been paid the  purchase  price for  tendered  Maricopa  Bonds or the  Company is
otherwise in default in such Loan Agreement Payment Obligations,  the Bonds will
terminate  and  expire  on the  first  date  thereafter  on which  such  payment
obligations have been satisfied.  Such date of termination and expiration of the
Bonds is herein referred to as the "Termination Date."

     The Company  shall have no  obligation to make payments with respect to the
Bonds unless and until,  and only to the extent that,  payments shall be due and
payable  on the  Maricopa  Bonds to and  including  the  Termination  Date.  Any
provision  hereof to the contrary  notwithstanding,  the Company shall receive a
credit against its obligation to make any payment of interest on the Bonds in an
amount  equal to the amount,  if any,  held by the  Maricopa  Trustee  under the
Maricopa  Indenture  on  deposit in the Bond Fund (as  defined  in the  Maricopa
Indenture)  and  available  to make the  corresponding  payment on the  Maricopa
Bonds. In addition, the Company shall receive a credit against its obligation to
make any payment of  principal  or  purchase  price of the Bonds,  whether  upon
redemption,  acceleration  or tender of the Maricopa  Bonds or otherwise,  in an
amount  equal to the amount,  if any,  held by the  Maricopa  Trustee  under the
Maricopa  Indenture  on  deposit  in said  Bond Fund and  available  to make the
corresponding payment on the Maricopa Bonds.

     The Company  covenants and agrees that,  prior to the Termination  Date, it
will not take any action (except as described  herein or as  contemplated in the
Maricopa  Indenture  or the Loan  Agreement)  that would  cause the  outstanding
principal  amount  of the  Bonds of the  Sixty-first  Series to be less than the
outstanding principal amount of the Maricopa Bonds.

     SECTION  2.  Upon  payment  of the  principal  of and  interest  due on the
Maricopa Bonds, whether by acceleration or otherwise,  or upon provision for the
payment  thereof  having been made in  accordance  with the Maricopa  Indenture,
whether with payments  made pursuant to the Bonds or with other funds  available
for such payment,  Bonds in a principal  amount equal to the principal amount of
Maricopa  Bonds so paid or for which such  provision  for  payment has been made
shall be deemed fully paid,  satisfied and discharged and the obligations of the
Company  thereunder  shall be terminated  and such Bonds shall be surrendered to
and  cancelled  by the  Trustee.  The Company  will issue and the  Trustee  will
authenticate a new Bond for the unpaid portion thereof.

     SECTION 3. Bonds of the  Sixty-first  Series  shall be held by the Maricopa
Trustee and shall not be  transferable  except to its permitted  successors  and
assigns under the Maricopa Indenture. The Maricopa Trustee, as the holder of the
Bonds,  shall attend  meetings of bondholders  under the Mortgage or deliver its
proxy in connection  therewith.  Either at such meeting,  or otherwise  when the
consent of the holders of the Bonds is sought  without a meeting,  the  Maricopa
Trustee  shall vote as the holder of the Bonds,  or shall  consent  with respect
thereto;  provided,  however,  that the Maricopa Trustee shall not vote in favor
of, or consent to, any  modification  of the Mortgage  which is correlative to a
modification of the Maricopa Indenture or the Loan Agreement which would require
the approval of owners of Maricopa  Bonds  without the approval of the owners of
Maricopa Bonds and other bonds issued under the Maricopa  Indenture  which would
be required for such correlative modification of such Maricopa Indenture or Loan
Agreement.

                                       10
<PAGE>
                                  ARTICLE II.
                    REDEMPTION OF BONDS AND OTHER PROVISIONS

     The Bonds shall be redeemed, in whole or in part, from time to time, on the
date on which a corresponding  principal amount of Maricopa Bonds is redeemed as
provided in the Maricopa Indenture,  upon the Maricopa Trustee's notification of
the Trustee of such  redemption,  at a redemption  price equal to the redemption
price of such  Maricopa  Bonds  being so  redeemed.  Any  such  notice  shall be
received by the Trustee no later than 5 days prior to any redemption  date fixed
for the Bonds to be  redeemed  and shall  specify the  principal  amount of such
Bonds to be redeemed, the redemption date, and the amount of accrued interest to
be paid  thereon.  The  Company  shall  deposit in trust with the Trustee on the
redemption date an amount of money  sufficient to pay the principal  amount plus
accrued interest, if any, on the Bonds to be redeemed.  Upon presentation to the
Trustee of any Bonds by the Maricopa  Trustee for payment under this Article II,
such  Bonds so  presented  shall be  redeemed  and paid in full to the extent so
redeemed.  In the event of  redemption  of the Bonds in part only, a new bond of
the Sixty-first Series and of like tenor for the unredeemed portion thereof will
be issued in the name of the Maricopa  Trustee upon the cancellation of the then
existing Bond.

     Redemption of the Bonds shall be effected,  without  further  notice by the
Company  to  the  Trustee,  by the  payment  by the  Company  of the  applicable
redemption price specified in this Article II at the place specified for payment
of principal of and interest on such bonds.

     In the  event the  principal  of all  Maricopa  Bonds is  declared  due and
payable pursuant to the Maricopa Indenture,  upon the filing with the Trustee of
a written demand for the  acceleration of the payment of principal of all Bonds,
the payment of principal on all Bonds shall become immediately due and payable.

     The Bonds will not be subject to prepayment or redemption prior to maturity
except as provided herein, notwithstanding the provisions of Section 39, Section
64 or Section 87 of the Mortgage,  or with  "Proceeds of Released  Property," as
defined in the Mortgage.

     The Company hereby covenants and agrees that until the Termination Date, it
will not  consolidate  with or merge  into any other  corporation,  or convey or
transfer,  subject to the Lien of the Indenture, all or substantially all of the
Mortgaged and Pledged Property as an entirety.

     The Bonds will not be subject to any sinking fund.

                                  ARTICLE III.
             REPLACEMENT FUND PROVISIONS -- OTHER RELATED PROVISIONS
             OF THE MORTGAGE -- DIVIDEND COVENANT -- RECORD DATES --
                              AUTHENTICATING AGENT.

     SECTION 4. The Company  covenants  that the provisions of Section 39 of the
Mortgage,  which  were to  remain  in  effect  so long as any bonds of the First
Series  remained  Outstanding,  shall remain in full force and effect so long as
any bonds of the Sixty-first Series are Outstanding.

     Clause (d) of subsection  (II) of Section 4 of the Mortgage,  as heretofore
amended,  clause (6) and clause (e) of Section 5 of the Mortgage,  as heretofore
amended,  and Section 29 of the  Mortgage,  as  heretofore  amended,  are hereby
further amended by inserting  therein the words "and  Sixty-first  Series" after
the words  "bonds of the First  Series  and Second  Series and Third  Series and
Fourth  Series and Fifth Series and Sixth  Series and Seventh  Series and Eighth
Series and Ninth Series and Tenth Series and Eleventh  Series and Twelfth Series
and Thirteenth  Series and Fourteenth  Series and Fifteenth Series and Sixteenth

                                       11
<PAGE>
Series and Seventeenth  Series and Eighteenth  Series and Nineteenth  Series and
Twentieth  Series  and  Twenty-first   Series  and   Twenty-second   Series  and
Twenty-third  Series and  Twenty-fourth  Series  and  Twenty-  fifth  Series and
Twenty-sixth  Series and  Twenty-seventh  Series and Twenty-  eighth  Series and
Twenty-ninth   Series  and  Thirtieth   Series  and   Thirty-first   Series  and
Thirty-second  Series  and  Thirty-third  Series  and  Thirty-fourth  Series and
Thirty-fifth  Series  and  Thirty-sixth  Series  and  Thirty-seventh  Series and
Thirty-eighth Series and Thirty-ninth Series and Fortieth Series and Forty-first
Series and Forty-second  Series and Forty-third  Series and Forty-fourth  Series
and  Forty-fifth  Series and  Forty-sixth  Series and Forty-  seventh Series and
Forty-eighth  Series and Forty-ninth  Series and Fiftieth Series and Fifty-first
Series and Fifty-second  Series and Fifty-third  Series and Fifty-fourth  Series
and Fifty-fifth  Series and Fifty-sixth  Series,  and  Fifty-seventh  Series and
Fifty-eighth  Series and Fifty-ninth  Series and Sixtieth Series" each time such
words occur therein.

     Clause (e) of subsection  (II) of Section 4 of the Mortgage,  as heretofore
amended, is hereby further amended by the insertion therein after the words "and
Sixtieth" the words "and Sixty-first."

     The last  paragraph of Section 12 of the Mortgage,  as heretofore  amended,
the last paragraph of Section 17 of the Mortgage, as heretofore amended, and the
last paragraph of Section 110 of the Mortgage, as heretofore amended, are hereby
amended by inserting  therein the words "or the  Sixty-first  Series"  after the
words "Sixtieth Series" each time such words occur therein.

                                   ARTICLE IV.
                            MISCELLANEOUS PROVISIONS.

     SECTION 5. The terms defined in the Mortgage,  as supplemented and amended,
shall, for all purposes of this Fifty-seventh  Supplemental Indenture,  have the
meanings specified therein,  except that the term "Mortgage" shall mean only the
original  Mortgage  and  Deed of  Trust,  dated  as of July 1,  1946;  the  term
"Mortgage,  as heretofore  supplemented and amended" shall mean the Mortgage, as
supplemented  and  amended  by  the  First  through   Fifty-sixth   Supplemental
Indentures hereinabove referred to; and the term "Mortgage,  as supplemented and
amended,"  shall mean the  Mortgage,  as  supplemented  and amended by the First
through  Fifty-sixth  Supplemental  Indentures  hereinabove  referred  to and as
supplemented and amended by this  Fifty-seventh  Supplemental  Indenture and any
future supplemental indentures.

     SECTION 6. The Trustee hereby accepts the trusts herein declared, provided,
created,  supplemented  or amended and agrees to perform the same upon the terms
and  conditions  herein and in the  Mortgage,  as  heretofore  supplemented  and
amended, set forth and upon the following terms and conditions:

     The Trustee shall not be  responsible  in any manner  whatsoever  for or in
respect  of the  validity  or  sufficiency  of this  Fifty-seventh  Supplemental
Indenture or for or in respect of the recitals  contained  herein,  all of which
recitals  are made by the Company  solely.  In general,  each and every term and
condition contained in Article XVII of the Mortgage shall apply to and form part
of this Fifty-seventh  Supplemental  Indenture with the same force and effect as
if the same were herein set forth in full with such  omissions,  variations  and
insertions,  if any,  as may be  appropriate  to make  the same  conform  to the
provisions of this Fifty-seventh Supplemental Indenture.

     SECTION 7. Whenever in this Fifty-seventh  Supplemental Indenture either of
the  parties  hereto  is  named or  referred  to,  this  shall,  subject  to the
provisions  of Articles XVI and XVII of the  Mortgage,  be deemed to include the
successors  and assigns of such party,  and all the covenants and  agreements in
this  Fifty-seventh  Supplemental  Indenture  contained  by or on  behalf of the
Company or by or on behalf of the Trustee shall, subject as aforesaid,  bind and

                                       12
<PAGE>
inure to the  respective  benefits of the  respective  successors and assigns of
such parties, whether so expressed or not.

     SECTION 8. Nothing in this Fifty-seventh Supplemental Indenture,  expressed
or implied, is intended or shall be construed to confer upon, or to give to, any
person,  firm or  corporation,  other than the parties hereto and the holders of
the bonds Outstanding under the Mortgage, any right, remedy or claim under or by
reason of this Fifty-seventh Supplemental Indenture or any covenant,  condition,
stipulation,  promise or agreement  hereof,  and all the covenants,  conditions,
stipulations,   promises  and  agreements  in  this  Fifty-seventh  Supplemental
Indenture  contained  by or on behalf of the  Company  shall be for the sole and
exclusive  benefit  of  the  parties  hereto  and of the  holders  of the  bonds
Outstanding under the Mortgage.

     SECTION  9.  This  Fifty-seventh  Supplemental  Indenture  may be  executed
simultaneously in several  counterparts,  each of which shall be an original and
all of which shall constitute but one and the same instrument.

                                   ARTICLE V.
                        SPECIFIC DESCRIPTION OF PROPERTY.

     SECTION 10. CERTAIN REAL PROPERTY LOCATED IN:

                                  PINAL COUNTY
                                ROBSON SUBSTATION

That part of Section  17,  Township  7 South,  Range 7 East of the Gila and Salt
River Base and  Meridian,  Pinal  County,  Arizona,  lying North and East of the
Arizona Highway 84 more particularly described as follows:

Beginning at the Southeast corner of said Section 17; thence S  89(degree)40'35"
W along the South line of said  Section 17, a distance of 44.42 feet to a point;
Thence  N  0(degree)19'25"  W a  distance  of  50  feet  to a  point;  thence  N
0(degree)04'32" E a distance of 73.39 feet to the true point of beginning of the
parcel herein described; thence Northerly along a curve to the right, said curve
having a central angle of  27(degree)47'59",  and a radius of 290.00 feet, for a
distance of 140.71 feet to a point; said point being the beginning of a curve to
the left, said curve having a central angle of 28(degree)50'15", and a radius of
210.00 feet, for a distance of 105.70 feet to a point;  thence N 0(degree)57'45"
W a distance of 13.41 feet to a point; thence S 89(degree)40'35" W a distance of
309.17 feet to a point;  thence S 0(degree)19'15" E a distance of 250.00 feet to
a point; thence N 89(degree)40'35" E a distance of 250.00 feet to the true point
of beginning.

     SECTION  11.  THE  ELECTRIC  SUBSTATIONS  OF  THE  COMPANY,  including  all
buildings,  structures, towers, poles, all equipment, appliances and devices for
transforming, converting and distributing electric energy, and all land owned by
the  Company  upon  which  the  same  are  situated,  and  all of the  Company's
easements,  rights of way, rights, machinery,  equipment,  appliances,  devices,
licenses  and  supplies  forming  a part of said  substations,  or any of  them,
including additions and improvements to any of the foregoing, or used or enjoyed
or capable of being use or enjoyed in conjunction with any thereof.

     SECTION  12.  Additions,   extensions  and  improvements  to  THE  ELECTRIC
TRANSMISSION SYSTEMS of the Company.

     SECTION  13.  Additions,   extensions  and  improvements  to  THE  ELECTRIC
DISTRIBUTION SYSTEMS of the Company,  including,  the construction of additional
facilities  throughout  the  Company's  service  area,  as well as  extension of

                                       13
<PAGE>
residential  and  downtown  underground   distribution   facilities,   including
associated  distribution equipment such as voltage regulators,  capacitor banks,
sectionalizing  equipment,  transformers,  street lighting  systems,  meters and
services, including reconstruction and improvements to provide efficient Company
operation.

                                       14
<PAGE>
     IN WITNESS  WHEREOF,  ARIZONA PUBLIC SERVICE  COMPANY,  party hereto of the
first  part,  has caused its  corporate  name to be hereunto  affixed,  and this
instrument to be signed and sealed by its President, one of its Vice Presidents,
or its Treasurer,  and its corporate seal to be attested by its Secretary or one
of its Assistant  Secretaries or Associate Secretaries for and in its behalf, in
the City of  Phoenix,  Arizona,  and THE BANK OF NEW YORK,  party  hereto of the
second part,  has caused its  corporate  name to be hereunto  affixed,  and this
instrument  to be signed and sealed by one of its Vice  Presidents  or Assistant
Vice  Presidents  and its corporate  seal to be attested by one of its Assistant
Vice  Presidents or Assistant  Treasurers for and in its behalf,  in the City of
West Paterson, New Jersey, all as of the 1st day of March, 2003.


                                          ARIZONA PUBLIC SERVICE COMPANY


                                          Barbara M. Gomez
                                          --------------------------------------
                                                         TREASURER


Attest:

Betsy A. Pregulman
--------------------------------------
      ASSOCIATE SECRETARY


Executed, sealed and delivered by
  ARIZONA PUBLIC SERVICE COMPANY
  in the presence of:

Andrea Bernal
--------------------------------------
Andrea Bernal


Norann Asciutto                                       [SEAL]
--------------------------------------
Norann Asciutto


                                          THE BANK OF NEW YORK, As Trustee


                                          Thomas Vlahakis
                                          --------------------------------------
                                                       VICE PRESIDENT
Attest:

Thomas J. Provenzano
--------------------------------------
Thomas J. Provenzano, Vice President


Executed, sealed and delivered by
  THE BANK OF NEW YORK in the
  presence of:

Rosemary Melendez
--------------------------------------
Rosemary Melendez, Assistant Treasurer


David J. O'Brien                                      [SEAL]
--------------------------------------
David J. O'Brien, Vice President

                                       15
<PAGE>
STATE OF ARIZONA                    )
                                    ) ss.:
COUNTY OF MARICOPA                  )

     On  this  4th  day of  March,  2003,  before  me,  Debra  L.  Blondin,  the
undersigned  officer,  personally  appeared  Barbara M. Gomez,  who acknowledged
herself  to be the  Treasurer  of ARIZONA  PUBLIC  SERVICE  COMPANY,  an Arizona
corporation, and that she, as such Treasurer being authorized so to do, executed
the foregoing instrument for the purposes therein contained, by signing the name
of the corporation by herself as Treasurer.

     IN WITNESS WHEREOF, I have hereunto set my hand and seal.

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


                                          My Commission Expires June 7, 2004
                                                                ----------------
[SEAL]

STATE OF ARIZONA                    )
                                    ) ss.:
COUNTY OF MARICOPA                  )


     On  this  4th  day of  March,  2003,  before  me,  Debra  L.  Blondin,  the
undersigned officer, personally came Barbara M. Gomez, to me known, who being by
me duly sworn, did depose and say that she resides in Phoenix, Arizona, that she
is the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, the corporation described in
and  which  executed  the  above  instrument;  that she  knows  the seal of said
corporation;  that the seal affixed to said  instrument is such corporate  seal;
that it was so affixed by order of the Board of Directors  of said  corporation,
and that she signed her name thereto by like order.

     IN WITNESS WHEREOF, I have hereunto set my hand and seal.

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


                                          My Commission Expires June 7, 2004
                                                                ----------------
[SEAL]


STATE OF ARIZONA                    )
                                    ) ss.:
COUNTY OF MARICOPA                  )


     This instrument was  acknowledged  before me on March 4, 2003 by Barbara M.
Gomez  and  Betsy  A.   Pregulman,   as  Treasurer  and   Associate   Secretary,
respectively, of ARIZONA PUBLIC SERVICE COMPANY.

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


                                          My Commission Expires June 7, 2004
                                                                ----------------
[SEAL]

                                       16
<PAGE>
STATE OF NEW JERSEY                 )
                                    ) ss.:
COUNTY OF PASSAIC                   )


     On this 5th day of March,  2003, before me, Ronald M. Mania,  Notary Public
in and for the County and State aforesaid,  residing therein,  duly commissioned
and  sworn,  personally  appeared  Thomas  Vlahakis,  known  to me to be a  Vice
President  of THE  BANK OF NEW  YORK,  a New  York  banking  corporation,  which
executed the within  instrument,  and Thomas J. Provenzano,  known to me to be a
Vice President of The Bank of New York, who being by me duly sworn, acknowledged
before me that the seal affixed to said  instrument is the corporate seal of The
Bank of New York,  that they,  being  authorized  so to do,  executed the within
instrument  on  behalf  of The Bank of New  York by  authority  of its  board of
directors,  and that said instrument is the free act and deed of The Bank of New
York for the purposes therein contained.

     IN WITNESS  WHEREOF,  I have  hereunto  set my hand and affixed my official
seal the day and year in this certificate first above written.

                                          Ronald M. Mania
                                          --------------------------------------
                                                       Notary Public


                                          My Commission Expires     10/4/2006
                                                                ----------------

[SEAL]


STATE OF NEW JERSEY                 )
                                    ) ss.:
COUNTY OF PASSAIC                   )

     This  instrument  was  acknowledged  before me on March 5th, 2003 by Thomas
Vlahakis and Thomas J.  Provenzano,  each as a Vice President of THE BANK OF NEW
YORK.

                                          Ronald M. Mania
                                          --------------------------------------
                                                       Notary Public


                                          My Commission Expires     10/4/2006
                                                                ----------------

[SEAL]

                                       17

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.1A
<SEQUENCE>6
<FILENAME>ex10-1a.txt
<DESCRIPTION>2003 OFFICER VARIABLE INCENTIVE PLAN
<TEXT>
                                                                   Exhibit 10.1a

Under the 2003 Officers Variable Incentive Plan, the Chief Executive Officer,
with the approval of the Human Resources Committee of the Pinnacle West Board of
Directors, annually designates the officers who will participate in the program,
establishes their participation level, and establishes certain financial and
operational goals. The impact, if any, of each officer's performance on his or
her variable pay award is determined by the Chief Executive Officer, with the
approval by the Human Resources Committee. However, the calculation and the
amount of payment, if any, under this Plan are in the sole discretion of the
Human Resources Committee of the Board of Directors. Accordingly, achievement of
financial and operational goals is just one method that may be utilized to
measure performance.


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.2A
<SEQUENCE>7
<FILENAME>ex10-2a.txt
<DESCRIPTION>2003 CEO VARIABLE INCENTIVE PLAN
<TEXT>
                                                                   Exhibit 10.2a

Under the 2003 CEO Variable Incentive Plan, the Human Resources Committee of the
Pinnacle West Board of Directors, annually establishes the participation level
and establishes certain financial and operational goals. However, the
calculation and the amount of payment, if any, under this Plan are in the sole
discretion of the Human Resources Committee. Accordingly, achievement of
financial and operational goals is just one method that may be utilized to
measure performance.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.3A
<SEQUENCE>8
<FILENAME>ex10-3a.txt
<DESCRIPTION>SCHEDULES OF WJP & JED TO APS DEFERRED COMP PLAN
<TEXT>
                                                                   Exhibit 10.3a

                                                                            1986
Exhibit B

                      EXECUTIVES' BENEFIT SUMMARY DOCUMENT
                                       FOR
                                    BILL POST

                                          Annual Retirement     Total Retirement
Age          Year            Date              Benefit               Benefit
---          ----            ----              -------               -------
 60          2010           2-15-10            $162,020            $1,620,200
 61          2011           2-15-11             172,551             1,725,510
 62          2012           2-15-12             183,767             1,837,670
 63          2013           2-15-13             195,712             1,957,120
 64          2014           2-15-14             208,433             2,084,330
 65          2015           2-15-15             221,981             2,219,809
 66          2016           2-15-16             236,410             2,364,100

                                                                            1985
Exhibit B

                      EXECUTIVES' BENEFIT SUMMARY DOCUMENT
                                       FOR
                                   JOHN DAVIS

                                          Annual Retirement     Total Retirement
Age          Year            Date              Benefit               Benefit
---          ----            ----              -------               -------
 60          2006           3-15-06            $ 57,583            $  575,830
 61          2007           3-15-07              61,326               613,260
 62          2008           3-15-08              65,312               653,120
 63          2009           3-15-09              69,558               695,580
 64          2010           3-15-10              74,079               740,790
 65          2011           3-15-11              78,894               788,940
<PAGE>
                                                                            1984
Exhibit B

                      EXECUTIVES' BENEFIT SUMMARY DOCUMENT
                                       FOR
                                  JOHN E. DAVIS

                                          Annual Retirement     Total Retirement
Age          Year            Date              Benefit               Benefit
---          ----            ----              -------               -------
 60          2006           2-15-06            $ 94,454            $  944,540
 61          2007           2-15-07             100,594             1,005,940
 62          2008           2-15-08             107,132             1,071,320
 63          2009           2-15-09             114,096             1,140,960
 64          2010           2-15-10             121,512             1,215,120
 65          2011           2-15-11             129,410             1,294,100

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.4A
<SEQUENCE>9
<FILENAME>ex10-4a.txt
<DESCRIPTION>LETTER AGREEMENT DATED 6/28/01 - WHEELER
<TEXT>
                                                                   Exhibit 10.4a

               [LETTERHEAD OF PINNACLE WEST CAPITAL CORPORATION]


                                                                      JACK DAVIS
                                                                       President

June 28, 2001

Steve Wheeler
One Arizona Center
400 East Van Buran
Phoenix, AZ 85004-0001

Dear Steve,

I'm delighted that you have made the decision to join Pinnacle West Capital
Corporation (PNW) beginning June 29, 2001. This is an exciting and challenging
time in the Company, and your experience will have a direct impact on our
efforts. The information outlined below covers the major items we have discussed
regarding our offer of employment.

As you know, this offer is for the position of Senior Vice President of
Transmission Operations, Regulation and Planning with an annual base salary of
$275,000, effective your first day of employment. You will participate in the
officer annual incentive program with a maximum opportunity equal to fifty-two
percent of your annual base salary. Any incentive payout for 2001 results will
be paid in full and not pro-rated. Incentive dollars are generally paid during
the first quarter of the subsequent year.

Within two weeks of your first day of employment you will also receive a
$100,000 employment incentive, and three thousand shares of Pinnacle West stock.

In addition to the base and incentive compensation referenced above, you will
also receive a semi-monthly auto allowance totaling $7,440 per year.

I have enclosed a summary of our employee benefits and a schedule showing the
applicable premiums that are cost shared with our employees. Since you are not
immediately eligible for PNW medical plan coverage, the premium cost of any
external medical coverage you carry will be paid by the Company until your
eligibility date. Further, enclosed is a description of our Employee Savings
Plan in which you will be eligible to participate 31 days after employment.
Please note that the Employee Savings Plan is a pre-tax savings plan. Also the
premiums that apply to our medical and dental plans are on a pre-tax basis.
<PAGE>
Regarding pension, effective your first day of employment, you will be credited
with ten years of vested service solely for the purpose of calculating future
pension benefits. Additionally, you will receive two years of service for
pension purposes in each of the first two years of employment. Thereafter you
will receive pension crediting based on the pension policy applicable to
officers.

During 2001 you will be eligible for four weeks of vacation. For purposes of
vacation accrual, you will be eligible for five weeks vacation after five years.

Eligibility for all officer benefits not specifically mentioned above would be
in accordance with the applicable policies and plan documents.

Effective July 1, 2002 your base salary will increase to $300,000 and you will
receive an additional three thousand shares of stock. This stock award will be
in addition to any other officer stock distribution that may occur as determined
by the PNW Board of Directors.

This offer is contingent upon successful completion of employment prerequisites,
which include a background check, physical exam and drug screen.

On behalf of Pinnacle West Capital Corporation I'd like to welcome you to our
team. In the event you have any questions, feel free to contact me or Armando
Flores who will be coordinating the details of your employment.

Sincerely,

/s/ Jack Davis

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.5A
<SEQUENCE>10
<FILENAME>ex10-5a.txt
<DESCRIPTION>2002 LONG-TERM INCENTIVE PLAN
<TEXT>
                                                                   Exhibit 10.5a

                        PINNACLE WEST CAPITAL CORPORATION
                          2002 LONG-TERM INCENTIVE PLAN

1.   OBJECTIVES.

     The Pinnacle West Capital Corporation 2002 Long-Term Incentive Plan (the
     "Plan") is designed to attract, motivate and retain selected employees of
     the Company. These objectives are accomplished by making long-term
     incentive awards under the Plan, thereby providing Participants with a
     proprietary interest in the Company's growth and performance.

2.   DEFINITIONS.

     (A)  "AWARDS" -- The grant of any form of Stock Option, Performance Share,
          or Stock Ownership Incentive Award (whether granted singly, in
          combination or in tandem) to a Participant pursuant to such terms,
          conditions, performance requirements, limitations and restrictions as
          the Committee may establish in order to fulfill the objectives of the
          Plan.

     (B)  "AWARD AGREEMENT" -- An agreement between PNW and a Participant that
          sets forth the terms, conditions, performance requirements,
          limitations and restrictions applicable to an Award.

     (C)  "BOARD" -- The Board of Directors of Pinnacle West Capital Corporation
          ("PNW").

     (D)  "CAPITAL STOCK" OR "STOCK" -- PNW's common stock (no par value).

     (E)  "CODE" -- The Internal Revenue Code of 1986, as amended from time to
          time.

     (F)  "COMMITTEE" -- The Committee designated by the Board to administer the
          Plan and chosen from those of its members, each of whom qualify as:
          (i) a "Non-Employee Director" of PNW as defined in Rule 16b-3(b)(3)
          (or any successor provision) under the Securities Exchange Act of 1934
          and (ii) an "outside director" under section 162(m) (or any successor
          provision) of the Code and the regulations thereunder.

     (G)  "COMPANY" -- PNW or any of its subsidiaries (including subsidiaries of
          subsidiaries) or any other entity in which PNW or any of its
          subsidiaries has a significant equity or other interest, as determined
          by the Committee.

     (H)  "FAIR MARKET VALUE" -- The closing price of Capital Stock on the New
          York Stock Exchange for the date in question provided that if no sales
          of Capital Stock were made on said exchange on that date, the closing
          price of Capital Stock as reported for the most recent preceding day
          on which sales of Capital Stock were made on said exchange.

     (I)  "FISCAL YEAR" -- The Fiscal Year of PNW (may be changed from time to
          time).

     (J)  "PARTICIPANT" -- An individual to whom an Award has been made under
          the Plan. Awards may be made to employees of PNW or any of its
          subsidiaries (including subsidiaries of subsidiaries) or any other
<PAGE>
2002 Long-Term Incentive plan
Page 2

          entity in which PNW or any of its subsidiaries has a significant
          equity or other interest, as determined by the Committee.

     (K)  "PERFORMANCE PERIOD" -- A period of one or more consecutive Fiscal
          Years over which one or more of the performance criteria listed in
          Section 5(d) shall be measured pursuant to the grant of Awards
          (whether such Awards take the form of Stock Options, Performance Share
          Awards or Stock Ownership Incentive Awards). Performance Periods may
          overlap one another.

3.   CAPITAL STOCK AVAILABLE FOR AWARDS.

     Subject to adjustment pursuant to Section 12, the number of shares that may
     be issued under the Plan for Awards granted is six million (6,000,000).
     Shares of Capital Stock may be made available from the authorized but
     un-issued shares of PNW, from shares held in PNW's treasury and not
     reserved for some other purpose, or from shares purchased on the open
     market. For purposes of determining the number of shares of Capital Stock
     issued under the Plan, no shares shall be deemed issued until they are
     actually delivered to a Participant, or such other person in accordance
     with Section 9. Shares covered by Awards, that either wholly or in part are
     not earned or that expire or are forfeited, terminated, canceled, or
     exchanged or other Awards, shall be available for future issuance under
     Awards. Further, shares tendered to PNW in connection with the exercise of
     Stock Options, or withheld by PNW for the payment of tax withholding on any
     Award, shall also be available for future issuance under Awards.

4.   ADMINISTRATION.

     The Plan shall be administered by the Committee, which shall have full
     power to select Participants, interpret the Plan and adopt such rules,
     regulations and guidelines for carrying out the Plan as it may deem
     necessary or proper. A majority of the Committee shall constitute a quorum.
     The acts of a majority of the members present at any meeting at which a
     quorum is present and acts approved in writing by a majority of the
     Committee in lieu of a meeting shall be deemed acts of the Committee. Each
     member of the Committee is entitled to rely in good faith upon any report
     or other information furnished to that member by any officer or other
     employee of PNW, any subsidiary, PNW's certified public accountants, any
     executive compensation consultant or other professional retained by PNW to
     assist in the administration of the Plan.

5.   AWARDS.

     The Committee shall determine the type(s) of Award(s) to be made to each
     Participant and shall set forth in the related Award Agreement the terms,
     conditions, performance requirements, limitations and restrictions
     applicable to each Award. Awards may be granted singly, in combination or
     in tandem. Awards may also be made in combination or in tandem with, in
     replacement or payment of, or as alternatives to, grants, rights or
     compensation earned under any other Plan of the Company, including the Plan
     of any acquired entity.

     (A)  STOCK OPTION -- A Stock Option is a grant of a right to purchase a
          specified number of shares of Capital Stock. The exercise price of
          said Grant shall be not less than 100% of Fair Market Value on the
          date of Grant of such right. No individual may be granted Options to
          purchase more than 600,000 shares during any Fiscal Year. No Stock

                                        2
<PAGE>
2002 Long-Term Incentive plan
Page 3

          Option shall have a term of more than ten (10) years. No Stock Option
          may be repriced during its term. All Stock Options shall be
          non-qualified Stock Options.

     (B)  PERFORMANCE SHARE AWARD -- A Performance Share Award is an Award
          denominated in units of stock. The maximum number of shares of Capital
          Stock that may be issued under Performance Share Awards and Stock
          Ownership Incentive Awards shall not exceed 1,800,000. Performance
          Share Awards will provide for the payment of stock if performance
          goals are achieved over specified Performance Periods. The maximum
          possible Performance Share Grant to any single Participant is 120,000
          units in any Fiscal Year.

     (C)  STOCK OWNERSHIP INCENTIVE AWARD -- A Stock Ownership Incentive Award
          is an award of stock if certain performance goals and stock ownership
          requirements are achieved. The maximum possible Stock Ownership
          Incentive Award, which may be made to any single Participant in any
          Fiscal Year, is 15,000 shares.

     (D)  PERFORMANCE CRITERIA UNDER SECTION 162(M) OF THE CODE FOR PERFORMANCE
          SHARE AWARDS, AND STOCK OWNERSHIP INCENTIVE AWARDS -- The performance
          criteria for Performance Share Awards, and Stock Ownership Incentive
          Awards made to any "covered employee" (as defined in section 162(m) of
          the Code), and which are intended to qualify as "performance-based
          compensation" (as defined in section 162(m) of the Code), shall
          consist of objective tests based on one or more of the following:
          PNW's earnings per share growth compared to a comparative group of S&P
          Electric Utilities; earnings; cash flow; customer satisfaction;
          revenues; financial return ratios; market performance; shareholder
          return and/or value; operating profits (including earnings before
          income taxes, depreciation and amortization); net profits; earnings
          per share; earnings per share growth; profit returns and margins;
          stock price; working capital; business trends; production cost;
          project milestones; and plant and equipment performance, as well as
          one or more of the following operational measures: safety, environment
          and minimizing customer price per kilowatt-hour. Performance criteria
          may be measured solely on a corporate, subsidiary or business unit
          basis or a combination thereof. Satisfaction of Stock Ownership
          guidelines may also be a prerequisite to payment.

     (E)  DETERMINATIONS OF COMMITTEE -- Nothing herein shall preclude the
          Committee from making any payments or granting any Awards whether or
          not such payments or Awards qualify for tax deductibility under
          section 162(m) of the Code. No payments are to be made to a
          Participant if the applicable performance criteria are not achieved
          for a given Performance Period. If the applicable performance criteria
          are achieved for a given Performance Period, the Committee has full
          discretion to reduce or eliminate the amount otherwise payable for
          that Performance Period. Under no circumstances may the Committee use
          discretion to increase the amount payable to a Participant under a
          Performance Share Award, or a Stock Ownership Incentive Award.

6.   PAYMENT OF AWARDS.

     Payment of Awards shall be made in the form Stock and may include such
     restrictions as the Committee shall determine. Dividends or dividend
     equivalent rights may be extended to and made part of any Award denominated
     in Stock or units of Stock, subject to such terms, conditions and
     restrictions as the Committee may establish. At the discretion of the

                                        3
<PAGE>
2002 Long-Term Incentive plan
Page 4

     Committee, a Participant may be offered an election to substitute an Award
     for another Award (or Awards) of the same or different type.

7.   STOCK OPTION EXERCISE.

     The price at which shares of Capital Stock may be purchased under a Stock
     Option shall be paid in full in cash at the time of the exercise or, if
     permitted by the Committee, by means of tendering Capital Stock or
     surrendering another Award or any combination thereof. The Committee shall
     determine acceptable methods of tendering Capital Stock or other Awards and
     may impose such conditions on the use of Capital Stock or other Awards to
     exercise a Stock Option, as it deems appropriate. In addition, the Optionee
     may effect a "cashless exercise" of a Stock Option in which the option
     shares are sold through a broker and a portion of the proceeds, to cover
     the exercise price, is paid to PNW or otherwise in accordance with the
     rules and procedures adopted by the Committee.

8.   TAX WITHHOLDING.

     Prior to the payment or settlement of any Award, the Participant must pay,
     or make arrangements acceptable to PNW for the payment of, any and all
     federal, state and local tax withholding that in the opinion of PNW is
     required by law. PNW shall have the right to deduct applicable taxes from
     any Award payment and withhold (at the time of delivery or vesting of
     shares of Stock under the Plan) an appropriate number of shares for payment
     of taxes required by law or to take such other action as may be necessary
     in the opinion of PNW to satisfy all obligations for withholding of such
     taxes.

9.   TRANSFERABILITY.

     No Award shall be transferable, assignable, payable to, or exercisable by
     anyone other than the Participant to whom it was granted, except: (a) by
     will or the laws of descent and distribution; or (b) that the Committee (in
     the form of an Award Agreement or otherwise) may permit transfers of Awards
     by gift or otherwise to a member of a Participant's immediate family and/or
     trusts whose beneficiaries are members of the Participant's immediate
     family, or to such other persons or entities as may be approved by the
     Committee.

10.  AMENDMENT, MODIFICATION, SUSPENSION OR TERMINATION OF THE PLAN.

     The Board may amend, modify, suspend or terminate the Plan for the purpose
     of meeting or addressing any changes in law or other legal requirements or
     for any other purpose permitted by law; provided, however, that no such
     amendment, modification, suspension or termination of the Plan shall
     adversely affect in any material way any Award previously granted under the
     Plan, without the written consent of the Participant. Subject to changes in
     law or other legal requirements that would permit otherwise, the Plan may
     not be amended without the approval of the shareholders of PNW, to: (a)
     increase the aggregate number of shares of Capital Stock that may be issued
     under the Plan (except for adjustments pursuant to Section 12); (b) permit
     the granting of Stock Options with exercise prices lower than those
     specified in Section 5(a); (c) modify the Plan's eligibility requirements,
     or (d) change the performance criteria applicable to Covered Employees.

                                       4
<PAGE>
2002 Long-Term Incentive plan
Page 5

11.  TERMINATION OF EMPLOYMENT.

     If the employment of a Participant terminates, the status of the Award
     shall be as set forth in the Award Agreement, provided that if a
     Participant is covered by a Key Executive Employment and Severance
     Agreement ("KEESA"), which entitles the Participant's termination to be
     treated as a "Normal Termination", if such termination occurs within two
     years following a Change of Control (as defined in such KEESA), the Award
     Agreement shall give such Participant at least those rights provided for in
     such KEESA.

12.  ADJUSTMENTS.

     In the event of any change in the outstanding Capital Stock of PNW by
     reason of a stock split, stock dividend, combination or reclassification of
     shares, recapitalization, merger, or similar event, the Committee shall
     adjust appropriately: (a) the number of shares of Capital Stock: (i)
     available for issuance under the Plan; (ii) for which Awards may be granted
     to an individual Participant set forth in Section 5 and (iii) covered by
     outstanding Awards denominated in stock or units of stock; (b) the exercise
     and grant prices related to outstanding Awards, and (c) the appropriate
     Fair Market Value and other price determinations for such Awards. In the
     event of any other change affecting the Capital Stock or any distribution
     (other than normal cash dividends) to holders of Capital Stock such
     adjustments shall be made in the number and kind of shares and the
     exercise, grant and conversion prices of the affected Awards (including
     adjustments to avoid fractional shares) to give proper effect to such event
     as may be deemed equitable by the Committee. In the event of a corporate
     merger, consolidation, acquisition of property or stock, separation,
     reorganization or liquidation, the Committee shall be authorized to cause
     PNW to issue or assume Stock Options, whether or not in a transaction to
     which section 424(a) of the Code applies, by means of substitution of new
     Stock Options for previously issued Stock Options or an assumption of
     previously issued Stock Options. In such event, the aggregate number of
     shares of Capital Stock available for issuance under Awards under Section
     3, including the individual Participant maximums set forth in Section 5,
     will be adjusted to reflect such substitution or assumption.

13.  MISCELLANEOUS.

     (A)  Any notice to PNW required by any of the provisions of the Plan shall
          be addressed to the senior human resources officer of PNW in writing
          and shall become effective when it is received.

     (B)  The Plan shall be unfunded and the Company shall not be required to
          establish any special account or fund or to otherwise segregate or
          encumber assets to ensure payment of any Award.

     (C)  Nothing contained in the Plan shall prevent the Company from adopting
          other or additional compensation arrangements or plans, subject to
          shareholder approval (if such approval is required) and such
          arrangements or plans may be either generally applicable or applicable
          only in specific cases.

     (D)  No Participant shall have any claim or right to be granted an Award
          under the Plan and nothing contained in the Plan shall be deemed or
          construed to give any Participant the right to be retained in the
          employ of the Company or to interfere with the right of the Company to
          discharge any Participant at any time without regard to the effect
          such discharge may have upon the Participant under the Plan. Except to
          the extent otherwise provided in any plan or in an Award Agreement, no

                                        5
<PAGE>
2002 Long-Term Incentive plan
Page 6

          Award under the Plan shall be deemed compensation for purposes of
          computing benefits or contributions under any other plan of the
          Company.

     (E)  The Plan and each Award Agreement shall be governed by the laws of the
          State of Arizona, excluding any conflicts or choice of law rule or
          principle that might otherwise refer construction or interpretation of
          the Plan to the substantive law of another jurisdiction. Unless
          otherwise provided in the Award Agreement recipients of an Award under
          the Plan are deemed to submit to the exclusive jurisdiction and venue
          of the federal or state courts of Arizona, County of Maricopa to
          resolve any and all issues that may arise out of or relate to the Plan
          or any related Award Agreement.

     (F)  The Committee shall have full power and authority to interpret the
          Plan and to make any determinations thereunder. The Committee's
          determinations shall be binding and conclusive. Determinations made by
          the Committee under the Plan need not be uniform and may be made
          selectively among individuals, whether or not such individuals are
          similarly situated.

     (G)  If any provision of the Plan is, or becomes, or is deemed invalid,
          illegal or unenforceable in any jurisdiction, or would disqualify the
          Plan or any Award under any law deemed applicable by the Committee,
          such provision shall be construed or deemed amended or limited in
          scope to conform to applicable laws or, in the discretion of the
          Committee, it shall be stricken and the remainder of the Plan shall
          remain in full force and effect.

     (H)  The Plan, as adopted by the Board on March 20, 2002, is subject to
          approval of the stockholders of PNW within 12 months of the date it
          was adopted. Awards may be granted prior to such approval but no such
          Award may be exercised, vested or settled prior to such approval. If
          such approval is not obtained, any such Award shall be void ab initio
          and of no force or effect. If such approval is obtained, no further
          Awards shall be granted under the Pinnacle West Capital Corporation
          1994 Long-Term Incentive Plan other than Awards providing for the
          issuance of up to 20,000 shares of Stock to be used under such plan to
          satisfy PNW's obligations to make Stock Awards to certain executives.

     (I)  Subject to earlier termination, pursuant to Section 10, the Plan will
          terminate on March 19, 2012. Awards outstanding at the termination of
          the Plan will not be affected by such termination.

                                        6

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12.1
<SEQUENCE>11
<FILENAME>ex12-1.txt
<DESCRIPTION>COMPUTATION OF EARNINGS TO FIXED CHARGES
<TEXT>
                                                                    Exhibit 12.1

                        PINNACLE WEST CAPITAL CORPORATION
                    Computation of Earnings to Fixed Charges
                                    ($000's)

<TABLE>
<CAPTION>
                                                     2002        2001        2000        1999        1998
                                                   ---------   ---------   ---------   ---------   ---------
<S>                                                <C>         <C>         <C>         <C>         <C>
Income From Continuing Operations                  $ 215,153   $ 327,367   $ 302,332   $ 269,772   $ 242,892
Income Taxes                                         138,100     213,535     194,200     141,592     138,589
Fixed Charges                                        220,492     211,958     202,804     194,070     201,184
                                                   ---------   ---------   ---------   ---------   ---------
    Total                                            573,745     752,860     699,336     605,434     582,665

Fixed Charges:
    Interest Expense                                 188,353     175,822     166,447     157,142     163,975
    Estimated Interest Portion of Annual Rents        32,139      36,136      36,357      36,928      37,209
                                                   ---------   ---------   ---------   ---------   ---------
        Total Fixed Charges                          220,492     211,958     202,804     194,070     201,184

Ratio of Earnings to Fixed Charges (rounded down)       2.60        3.55        3.44        3.11        2.89
                                                   =========   =========   =========   =========   =========
</TABLE>

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21.1
<SEQUENCE>12
<FILENAME>ex21-1.txt
<DESCRIPTION>SUBSIDIARIES OF THE COMPANY
<TEXT>
                                                                    Exhibit 21.1

               SUBSIDIARIES OF PINNACLE WEST CAPITAL CORPORATION

Arizona Public Service Company
State of Incorporation: Arizona

Axiom Power Solutions, Inc.
State of Incorporation: Arizona

Bixco, Inc.
State of Incorporation: Arizona

PWENewco, Inc.
State of Incorporation: Arizona

APS Energy Services Company, Inc.
State of Incorporation: Arizona

Tucson District LLC
State of Incorporation: Arizona

SunCor Development Company
State of Incorporation: Arizona

SunCor Golf, Inc.
State of Incorporation: Arizona

Golden Heritage Homes, Inc.
State of Incorporation: Arizona

Golden Heritage Construction, Inc.
State of Incorporation: Arizona

SCM, Inc.
State of Incorporation: Arizona

Golf de Mexico, S.A. DE C.V.
Incorporation: Tijuana, Baja California, Mexico

SunCor Realty & Management Company
State of Incorporation: Arizona

Palm Valley Golf Club, Inc.
State of Incorporation: Arizona

Rancho Viejo de Santa Fe, Inc.
State of Incorporation: New Mexico

Ranchland Utility Company
State of Incorporation: New Mexico

El Dorado Investment Company
State of Incorporation: Arizona

El Dorado Ventures
State of Incorporation: Arizona

NAC Holding, Inc.
State of Incorporation: Delaware

Pinnacle West Energy Corporation
State of Incorporation: Arizona

GenWest, LLC
State of Incorporation: Delaware

SunCor Realty & Management Company
State of Incorporation: Arizona

Hidden Hills of Scottsdale LLC
State of Incorporation: Arizona

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23.1
<SEQUENCE>13
<FILENAME>ex23-1.txt
<DESCRIPTION>CONSENT OF DELOITTE & TOUCHE LLP
<TEXT>
                                                                    Exhibit 23.1

INDEPENDENT AUDITORS' CONSENT

We consent to the incorporation by reference in Registration Statement Nos.
33-15190, 333-52476, 333-101457 and 333-53150 on Form S-3; Registration
Statement Nos. 33-47534, 333-40796, 33-54307, 333-95035, 333-91786 and 33-1720
on Form S-8; and Registration Statement No. 2-96386 on Form S-14, all of
Pinnacle West Capital Corporation, of our report dated February 3, 2003 (March
4, 14, 26 and 27, 2003 as to Note 24) (which report expresses an unqualified
opinion and includes explanatory paragraphs relating to the change in 2002 in
the method of accounting for trading activities in order to comply with the
provisions of Emerging Issues Task Force Issue No. 02-3, ISSUES INVOLVED IN
ACCOUNTING FOR DERIVATIVE CONTRACTS HELD FOR TRADING PURPOSES AND CONTRACTS
INVOLVED IN ENERGY TRADING AND RISK MANAGEMENT ACTIVITIES, and to the change in
2001 in the method of accounting for derivatives and hedging activities in order
to comply with the provisions of Statement of Financial Accounting Standards No.
133, ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES) appearing in
this Annual Report on Form 10-K of Pinnacle West Capital Corporation for the
year ended December 31, 2002.

DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP
Phoenix, Arizona

March 27, 2003

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99.1
<SEQUENCE>14
<FILENAME>ex99-1.txt
<DESCRIPTION>CERTIFICATION OF WILLIAM J. POST
<TEXT>
                                                                    Exhibit 99.1

 FORM OF CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
                                (WILLIAM J. POST)

     I, William J. Post, the Chairman of the Board and Chief Executive Officer
of Pinnacle West Capital Corporation ("Pinnacle West"), certify, to the best of
my knowledge, that: (a) the attached Annual Report on Form 10-K of Pinnacle West
for the fiscal year ended December 31, 2002 (the "December 2002 Form 10-K")
fully complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 and (b) the information contained in the December 2002 Form
10-K Report fairly presents, in all material respects, the financial condition
and results of operations of Pinnacle West.


                                        William J. Post
                                        ----------------------------------------
                                        William J. Post
                                        Chairman of the Board and
                                        Chief Executive Officer

                                        Date: March 31, 2003

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99.2
<SEQUENCE>15
<FILENAME>ex99-2.txt
<DESCRIPTION>CERTIFICATION OF DONALD E. BRANDT
<TEXT>
                                                                    Exhibit 99.2

 FORM OF CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
                               (DONALD E. BRANDT)

     I, Donald E. Brandt, Senior Vice President and Chief Financial Officer, of
Pinnacle West Capital Corporation ("Pinnacle West"), certify, to the best of my
knowledge, that: (a) the attached Annual Report on Form 10-K of Pinnacle West
for the fiscal year ended December 31, 2002 (the "December 2002 Form 10-K")
fully complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 and (b) the information contained in the December 2002 Form
10-K Report fairly presents, in all material respects, the financial condition
and results of operations of Pinnacle West.


                                        Donald E. Brandt
                                        ----------------------------------------
                                        Donald E. Brandt
                                        Senior Vice President and
                                        Chief Financial Officer

                                        Date: March 31, 2003

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99.3
<SEQUENCE>16
<FILENAME>ex99-3.txt
<DESCRIPTION>RISK FACTORS
<TEXT>
                                                                    Exhibit 99.3

                                  RISK FACTORS

Set forth below and in other documents we file with the SEC are risks and
uncertainties that could affect our financial results.

IF WE ARE NOT ABLE TO ACCESS CAPITAL AT COMPETITIVE RATES, OUR ABILITY TO
IMPLEMENT OUR FINANCIAL STRATEGY WILL BE ADVERSELY AFFECTED.

We rely on access to both short-term money markets and longer-term capital
markets as a significant source of liquidity and for capital requirements not
satisfied by the cash flow from our operations. We believe that we will maintain
sufficient access to these financial markets based upon current credit ratings.
However, certain market disruptions or a downgrade of our credit rating may
increase our cost of borrowing or adversely affect our ability to access one or
more financial markets. Such disruptions could include:

     *    an economic downturn;

     *    capital market conditions generally;

     *    the bankruptcy of an unrelated energy company;

     *    market prices for electricity and gas;

     *    terrorist attacks or threatened attacks on our facilities or unrelated
          energy companies; or

     *    the overall health of the utility industry.

Changes in economic conditions could result in higher interest rates, which
would increase our interest expense on our debt and reduce funds available to us
for our current plans. Additionally, an increase in our leverage could adversely
affect us by:

     *    increasing the cost of future debt financing;

     *    increasing our vulnerability to adverse economic and industry
          conditions;

     *    requiring us to dedicate a substantial portion of our cash flow from
          operations to payments on our debt, which would reduce funds available
          to us for operations, future business opportunities or other purposes;
          and

     *    placing us at a competitive disadvantage compared to our competitors
          that have less debt.
<PAGE>
See the following Risk Factor for more information relating to this discussion.

A SIGNIFICANT REDUCTION IN OUR CREDIT RATINGS COULD MATERIALLY AND ADVERSELY
AFFECT OUR BUSINESS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

We cannot be sure that any of our current ratings will remain in effect for any
given period of time or that a rating will not be lowered or withdrawn entirely
by a rating agency if, in its judgment, circumstances in the future so warrant.
Any downgrade could increase our borrowing costs which would diminish our
financial results. We would likely be required to pay a higher interest rate in
future financings, and our potential pool of investors and funding sources could
decrease. A downgrade could require additional support in the form of letters of
credit or cash or other collateral and otherwise have a material adverse effect
on our business, financial condition and results of operations. If our
short-term ratings were to be lowered, it could limit our access to the
commercial paper market. We note that the ratings from credit agencies are not
recommendations to buy, sell or hold our securities and that each rating should
be evaluated independently of any other rating.

DEREGULATION OR RESTRUCTURING OF THE ELECTRIC INDUSTRY MAY RESULT IN INCREASED
COMPETITION, WHICH COULD HAVE A SIGNIFICANT ADVERSE IMPACT ON OUR BUSINESS AND
OUR FINANCIAL RESULTS.

Retail competition could have a significant adverse financial impact on us due
to an impairment of assets, a loss of retail customers, lower profit margins or
increased costs of capital. In 1999, the ACC approved rules that provide a
framework for the introduction of retail electric competition in Arizona. Under
the rules, as modified by a 1999 settlement agreement among APS and various
parties, APS was required to transfer all of its competitive electric assets and
services to an unaffiliated party or parties or to a separate corporate
affiliate or affiliates no later than December 31, 2002. Pursuant to an ACC
order dated September 10, 2002, the ACC unilaterally modified the 1999
settlement agreement and directed APS to cancel any plans to divest interests in
any of its generating assets. The ACC has further established a requirement that
APS solicit bids for certain estimated capacity and energy requirements for
periods beginning July 1, 2003. These regulatory developments and legal
challenges to the rules have raised considerable uncertainty about the status
and pace of retail electric competition in Arizona. Although some very limited
retail competition existed in APS' service area in 1999 and 2000, there are
currently no active retail competitors offering unbundled energy or other
utility services to APS' customers. As a result, we cannot predict when, and the
extent to which, additional competitors will re-enter APS' service territory.

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

                                        2
<PAGE>
THE PROCUREMENT OF WHOLESALE POWER BY APS WITHOUT THE ABILITY TO ADJUST RETAIL
RATES COULD HAVE AN ADVERSE IMPACT ON OUR BUSINESS AND FINANCIAL RESULTS.

A 1999 settlement agreement limits APS' ability to change retail rates until at
least July 1, 2004, which could have a significant adverse financial impact on
us if wholesale power prices significantly exceed the amount included for
generation costs in APS' current bundled retail rates. Under the ACC's rules,
APS is the "provider of last resort" for standard-offer, full-service customers
under rates that have been approved by the ACC. These rates are established
until at least July 1, 2004. The 1999 settlement agreement allows APS to seek
adjustment of these rates in the event of emergency conditions or circumstances,
such as the inability to secure financing on reasonable terms; material changes
in APS' cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws; regulatory requirements; or judicial decisions,
actions or orders. Energy prices in the western wholesale market vary and,
during the course of the last two years, have been volatile. At various times,
prices in the spot wholesale market have significantly exceeded the amount of
generation costs per kilowatt hour (kWh) included in APS' current retail rates.
In the event of shortfalls due to unforeseen increases in load demand or
generation or transmission outages, APS may need to purchase additional
supplemental power in the wholesale spot market. The ACC has further established
a requirement that APS solicit bids for certain estimated capacity and energy
requirements for periods beginning July 1, 2003. This competitive procurement
process may adversely affect the cost of APS' procurement of wholesale power. In
sum, there can be no assurance that APS would be able to fully recover the costs
of wholesale power under its present rate structure. Although APS could seek to
adjust its rates under the emergency provisions of the settlement agreement
discussed above, ACC approval of such an adjustment also cannot be assured.

WE ARE SUBJECT TO COMPLEX GOVERNMENT REGULATION WHICH MAY HAVE A NEGATIVE IMPACT
ON OUR BUSINESS AND OUR RESULTS OF OPERATIONS.

We are, directly and through our subsidiaries, subject to governmental
regulation which may have a negative impact on our business and results of
operations. We are a "holding company" within the meaning of the Public Utility
Holding Company Act ("PUHCA"); however, we are exempt from the provisions of
PUHCA by virtue of our filing of an annual exemption statement with the SEC.

APS is subject to comprehensive regulation by several federal, state and local
regulatory agencies, which significantly influence its operating environment and
may affect its ability to recover costs from utility customers. APS is required
to have numerous permits, approvals and certificates from the agencies that
regulate APS' business. The Federal Energy Regulatory Commission ("FERC"), the
Nuclear Regulatory Commission ("NRC"), the Environmental Protection Agency
("EPA"), and the Arizona Corporation Commission ("ACC") regulate many aspects of
our utility operations, including siting and construction of facilities,
customer service and the rates that APS can charge customers. We believe the

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necessary permits, approvals and certificates have been obtained for APS'
existing operations. However, we are unable to predict the impact on our
business and operating results from the future regulatory activities of any of
these agencies. Changes in regulations or the imposition of additional
regulations could have an adverse impact on our results of operations.

RECENT EVENTS IN THE ENERGY MARKETS THAT ARE BEYOND OUR CONTROL MAY HAVE
NEGATIVE IMPACTS ON OUR BUSINESS.

As a result of the energy crisis in California during the summer of 2001, the
recent volatility of natural gas prices in North America, the filing of
bankruptcy by the Enron Corporation, and investigations by governmental
authorities into energy trading activities, companies generally in the regulated
and unregulated utility businesses have been under an increased amount of public
and regulatory scrutiny. The capital markets and ratings agencies also have
increased their level of scrutiny. We believe that we are complying with all
applicable laws, but it is difficult or impossible to predict or control what
effect these or related issues may have on our business or our access to the
capital markets.

OUR RESULTS OF OPERATIONS CAN BE ADVERSELY AFFECTED BY MILDER WEATHER.

Weather conditions directly influence the demand for electricity and affect the
price of energy commodities. Electric power demand is generally a seasonal
business. In Arizona, demand for power peaks during the hot summer months, with
market prices also peaking at that time. As a result, our overall operating
results fluctuate substantially on a seasonal basis. In addition, we have
historically sold less power, and consequently earned less income, when weather
conditions are milder. As a result, unusually mild weather could diminish our
results of operations and harm our financial condition.

THERE ARE INHERENT RISKS IN THE OPERATION OF NUCLEAR FACILITIES, SUCH AS
ENVIRONMENTAL, HEALTH AND FINANCIAL RISKS AND THE RISK OF TERRORIST ATTACK.

Through APS, we have an ownership interest in and operate the Palo Verde Nuclear
Generating Station ("Palo Verde"). Palo Verde is subject to environmental,
health and financial risks such as the ability to dispose of spent nuclear fuel,
the ability to maintain adequate reserves for decommissioning, potential
liabilities arising out of the operation of these facilities, and the costs of
securing the facilities against possible terrorist attacks. We maintain nuclear
decommissioning trust funds and external insurance coverage to minimize our
financial exposure to these risks; however, it is possible that damages could
exceed the amount of insurance coverage.

The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of noncompliance, the NRC has the authority to impose fines or shut
down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. In addition, although we have no reason
to anticipate a serious nuclear incident at Palo Verde, if an incident did
occur, it could materially and adversely affect our results of operations or

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financial condition. A major incident at a nuclear facility anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of any
domestic nuclear unit.

The operation of Palo Verde requires licenses that need to be periodically
renewed and/or extended. We do not anticipate any problems renewing these
licenses. However, as a result of potential terrorist threats and increased
public scrutiny of utilities, the licensing process could result in increased
licensing or compliance costs that are difficult or impossible to predict.

THE USE OF DERIVATIVE CONTRACTS IN THE NORMAL COURSE OF OUR BUSINESS COULD
RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT OUR RESULTS OF OPERATIONS.

Our operations include managing market risks related to commodity prices,
changes in interest rates, and investments held by our pension plan and nuclear
decommissioning trust funds. We are exposed to the impact of market fluctuations
in the price and transportation costs of electricity, natural gas, coal, and
emissions allowances and credits. We have established procedures to manage risks
associated with these market fluctuations by utilizing various commodity
derivatives, including exchange-traded futures and options and over-the-counter
forwards, options, and swaps. As part of our overall risk management program, we
enter into derivative transactions to hedge purchases and sales of electricity,
fuels, and emissions allowances and credits. The changes in market value of such
contracts have a high correlation to price changes in the hedged commodity.

We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We use a risk management process to assess and monitor the
financial exposure of all counterparties. Despite the fact that the majority of
trading counterparties are rated as investment grade by the credit rating
agencies, there is still a possibility that one or more of these companies could
default, resulting in a material adverse impact on our earnings for a given
period.

Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our pension plan and nuclear decommissioning trust funds. Our
policy is to manage interest rates through the use of a combination of
fixed-rate and floating-rate debt. The pension plan and nuclear decommissioning
trust funds also have risks associated with changing market values of equity
investments. Most of the pension costs and all of the nuclear decommissioning
costs are recovered in regulated electricity prices.

THE UNCERTAIN OUTCOME REGARDING THE CREATION OF REGIONAL TRANSMISSION
ORGANIZATIONS, OR RTOS, MAY MATERIALLY IMPACT OUR OPERATIONS, CASH FLOWS OR
FINANCIAL POSITION.

In a December 1999 order, the FERC set minimum characteristics and functions
that must be met by utilities that participate in regional transmission
organizations. 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

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maintain short-term reliability. On October 16, 2001, APS and other owners of
electric transmission lines in the Southwest filed with the FERC a request for a
declaratory order confirming that their proposal to form WestConnect RTO, LLC
would satisfy the FERC's requirements for the formation of an RTO. On October
10, 2002, the FERC issued an order finding that the WestConnect proposal, if
modified to address specified issues, could meet the FERC's RTO requirements and
provide the basic framework for a standard market design for the Southwest. As
of March 28, 2003, the FERC was considering various aspects of its order as a
result of requests for clarification filed by the WestConnect applicants.

WE ARE SUBJECT TO NUMEROUS ENVIRONMENTAL LAWS AND REGULATIONS WHICH MAY INCREASE
OUR COST OF OPERATIONS, IMPACT OUR BUSINESS PLANS, OR EXPOSE US TO ENVIRONMENTAL
LIABILITIES.

We are subject to numerous environmental regulations affecting many aspects of
our present and future operations, including air emissions, water quality,
wastewater discharges, solid waste, and hazardous waste. These laws and
regulations can result in increased capital, operating, and other costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require us to obtain and
comply with a wide variety of environmental licenses, permits, inspections and
other approvals. Both public officials and private individuals may seek to
enforce applicable environmental laws and regulations. We cannot predict the
outcome (financial or operational) of any related litigation that may arise.

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

We cannot be sure that existing environmental regulations will not be revised or
that new regulations seeking to protect the environment will not be adopted or
become applicable to us. Revised or additional regulations that result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from APS' customers, could have a material
adverse effect on our results of operations.

THE MARKET PRICE OF OUR COMMON STOCK MAY BE VOLATILE.

The market price of our common stock could be subject to significant
fluctuations in response to factors such as the following, some of which are
beyond our control:

     *    variations in our quarterly operating results;

     *    operating results that vary from the expectations of management,
          securities analysts and investors;

     *    changes in expectations as to our future financial performance,
          including financial estimates by securities analysts and investors;

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<PAGE>
     *    developments generally affecting industries in which we operate,
          particularly the energy distribution and energy generation industries;

     *    announcements by us or our competitors of significant contracts,
          acquisitions, joint marketing relationships, joint ventures or capital
          commitments;

     *    announcements by third parties of significant claims or proceedings
          against us;

     *    favorable or adverse regulatory developments;

     *    our dividend policy;

     *    future sales of our equity or equity-linked securities; and

     *    general domestic and international economic conditions.

In addition, the stock market in general has experienced extreme volatility that
has often been unrelated to the operating performance of a particular company.
These broad market fluctuations may adversely affect the market price of our
common stock.

OUR STOCK PRICE COULD BE AFFECTED BECAUSE A SUBSTANTIAL NUMBER OF SHARES OF OUR
COMMON STOCK COULD BE AVAILABLE FOR SALE IN THE FUTURE.

Sales in the public market of a substantial number of shares of common stock
could depress the market price of the common stock and could impair our ability
to raise capital through the sale of additional equity securities. Because of
the number of shares of our common stock that we are authorized to issue under
our articles of incorporation, a substantial number of shares of our common
stock could be available for future sale.

OUR CASH FLOW AND ABILITY TO PAY DIVIDENDS LARGELY DEPENDS ON THE PERFORMANCE OF
OUR SUBSIDIARIES.

We conduct our operations primarily through subsidiaries. Substantially all of
our consolidated assets are held by such subsidiaries. Accordingly, our cash
flow and our ability to pay dividends on our capital stock are largely dependent
upon the earnings of these subsidiaries and the distribution or other payment of
such earnings to us in the form of dividends, loans or advances or repayment of
loans and advances from us. The subsidiaries are separate and distinct legal
entities and have no obligation to pay dividends or to make any funds available
for such payment.

The debt agreements of some of our subsidiaries may restrict their ability to
pay dividends, make distributions or otherwise transfer funds to us. Section
39(III) of APS' mortgage requires APS to meet a financial covenant before paying
common stock dividends. Under this covenant, APS may pay dividends on its common

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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, 2002,
the amount "available" under the mortgage would have allowed APS to pay
approximately $3 billion of dividends compared to APS' current annual common
stock dividends of $170 million. As part of the ACC's approval of a $500 million
financing arrangement between APS and Pinnacle West Energy, the ACC required APS
to maintain a common equity ratio of at least forty percent and prohibited APS
from paying common stock dividends if such payment would reduce its common
equity below that threshold.

WE HAVE AND MAY ENTER INTO CREDIT AND OTHER AGREEMENTS FROM TIME TO TIME THAT
RESTRICT OUR ABILITY TO PAY DIVIDENDS.

Payment of dividends on the common stock may be restricted by loan agreements,
indentures and other transactions entered into by us from time to time. As of
March 28, 2003, one of our loan agreements restricts our ability to pay
dividends to dividends paid on our capital stock in the ordinary course and
consistent with past practice (including increases in such dividends consistent
with past practices). However, if an event of default exists under that
agreement, we would be prohibited from paying any dividends while the event of
default continues.

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</SUBMISSION>
