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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, 2001

                                       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 1-4473

                         ARIZONA PUBLIC SERVICE COMPANY
             (Exact name of registrant as specified in its charter)

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OR 12(G) OF THE ACT: None.

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

     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in any amendment to this Form 10-K. [ X ]

     As of March 27, 2002, there were issued and outstanding 71,264,947 shares
of the registrant's common stock, $2.50 par value, all of which were held
beneficially and of record by Pinnacle West Capital Corporation.

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     THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I1(A)
AND (B) AND IS THEREFORE FILING THIS DOCUMENT WITH THE REDUCED DISCLOSURE
FORMAT.
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                                TABLE OF CONTENTS

                                                                            Page
                                                                            ----
GLOSSARY....................................................................   1

PART I
     Item 1.   Business.....................................................   3
     Item 2.   Properties...................................................  15
     Item 3.   Legal Proceedings............................................  19
     Item 4.   Submission of Matters to a Vote of Security Holders..........  19

PART II
     Item 5.   Market for Registrant's Common Stock and Related
               Stockholder Matters..........................................  20
     Item 6.   Selected Financial Data......................................  21
     Item 7.   Management's Discussion and Analysis of Financial Condition
               and Results of Operations....................................  22
     Item 7A.  Quantitative and Qualitative Disclosures about Market Risk...  39
     Item 8.   Financial Statements and Supplementary Data..................  40
     Item 9.   Changes in and Disagreements with Accountants on
               Accounting and Financial Disclosure..........................  84

PART III
     Item 10.  Directors and Executive Officers of the Registrant...........  84
     Item 11.  Executive Compensation.......................................  84
     Item 12.  Security Ownership of Certain Beneficial Owners and
               Management and Related Stockholder Matters...................  84
     Item 13.  Certain Relationships and Related Transactions...............  84

PART IV
     Item 14.  Exhibits, Financial Statements, Financial Statement
               Schedules, and Reports on Form 8-K...........................  85

SIGNATURES.................................................................. 110

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                                    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

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

CC&N - Certificate of Convenience and Necessity

Cholla - Cholla Power Plant

Citizens - Citizens Communications Company

Clean Air Act - Clean Air Act, as amended

Company - Arizona Public Service Company

DOE - United States Department of Energy

EITF - Emerging Issues Task Force

EPA - United States Environmental Protection Agency

ERMC - Energy Risk Management Committee

FASB - Financial Accounting Standards Board

FERC - United States Federal Energy Regulatory Commission

FIP - Federal Implementation Plan

Four Corners - Four Corners Power Plant

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

ISO - California Independent System Operator

ITC - investment tax credit

KW - kilowatt, one thousand watts

KWh - kilowatt-hour, one thousand watts per hour

MW - megawatt, one million watts

MWh - megawatt-hours, one million watts per hour

1999 Settlement Agreement - Settlement Agreement among the Company and other
parties related to the implementation of retail electric competition in Arizona

NOV - Notice of Violation

NRC - United States Nuclear Regulatory Commission

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

Palo Verde - Palo Verde Nuclear Generating Station

PG&E - PG&E Corp.

Pinnacle West - Pinnacle West Capital Corporation, parent company of the Company

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

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PPA - Purchase power agreement

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

SFAS - Statement of Financial Accounting Standards

Superfund - Comprehensive Environmental Response, Compensation, and Liability
Act

T&D - transmission and distribution

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

                                       2
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                                     PART I

                                ITEM 1. BUSINESS

                                     GENERAL

OVERVIEW OF OUR BUSINESS

     We were incorporated in 1920 under the laws of Arizona and are Arizona's
largest electric utility, with more than 874,000 customers. We are a
wholly-owned subsidiary of Pinnacle West Capital Corporation. We provide either
retail or wholesale electric service to substantially all of the state of
Arizona, with the major exceptions of the Tucson metropolitan area and about
one-half of the Phoenix metropolitan area. We also generate and, through
Pinnacle West's marketing and trading division, sell and deliver electricity to
wholesale customers in the western United States. During 2001, no single
purchaser or user of energy accounted for more than 1.4% of total electric
revenues.

     At December 31, 2001, we employed approximately 5,500 people, which
includes employees assigned to jointly-owned generating facilities for which we
serve as the generating facility manager. Our principal executive offices are
located at 400 North Fifth Street, Phoenix, Arizona 85004 (telephone
602-250-1000).

ARIZONA REGULATORY DEVELOPMENTS - 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 us and various
parties related to the implementation of retail electric competition in Arizona.
See "Retail Electric Competition Rules" and "1999 Settlement Agreement" in Note
3 of Notes to Financial Statements in Item 8 for additional information about
the 1999 Settlement Agreement and the Rules, including outstanding legal
challenges to the Rules.

     Under the Rules, as modified by the 1999 Settlement Agreement, we are
required to transfer all of our competitive electric assets and services either
to an unaffiliated party or to a separate corporate affiliate no later than
December 31, 2002. Consistent with that requirement, we have been addressing the
legal and regulatory requirements necessary to complete the transfer of our
generation assets to Pinnacle West Energy, another wholly-owned subsidiary of
Pinnacle West, on or before that date. In anticipation of our transfer of
generation assets, Pinnacle West Energy has completed, and is in the process of
developing and planning, various generation expansion projects so that we can
reliably meet the energy requirements of our Arizona customers. See Note 1 of
Notes to Financial Statements in Item 8 for information relating to our pending
transfer of generation assets and associated liabilities to Pinnacle West
Energy.

     Following the transfer of our fossil-fueled generation assets and the
receipt of certain regulatory approvals, Pinnacle West Energy expects to sell
its power at wholesale to Pinnacle West's marketing and trading division, which,
in turn, is expected to sell power to us and to non-affiliated power purchasers.
In a filing with the ACC on October 18, 2001, we requested the ACC to:

     *    grant us a partial variance from an ACC Rule that would obligate us to
          acquire all of our customers' standard-offer generation requirements
          from the competitive market (with at least 50% of those requirements
          coming from a "competitive bidding" process) starting in 2003; and

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     *    approve as just and reasonable a long-term purchase power agreement
          between us and Pinnacle West.

We requested these ACC actions to ensure ongoing reliable service to our
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve our load. See
"Proposed Rule Variance and Purchase Power Agreement" in Note 3 of Notes to
Financial Statements in Item 8 for additional information about our October 2001
filing.

     On February 8, 2002, the ACC's Chief ALJ issued a procedural order which
consolidated the ACC docket relating to our October 2001 filing with several
other pending ACC dockets, including a "generic" docket requested by the ACC
Chairman to "determine if changed circumstances require the [ACC] to take
another look at restructuring in Arizona." Although the order consolidates
several dockets, it states that a hearing on our matter will commence on April
29, 2002. The order went on to state that, contrary to our position, the ALJ was
construing the October 2001 filing as a request by us to amend the 1999 ACC
order that approved the 1999 Settlement Agreement.

     On March 22, 2002, the ACC Staff issued a report to the ACC recommending
that the ACC address the following issues in the generic docket:

     *    The extent and manner of the ACC's involvement in monitoring market
          conditions and/or mitigating the development of market power for
          generation and transmission;

     *    The lack of guidance in the Rules regarding the mechanics of the
          "competitive bidding process" referenced above;

     *    The consideration of alternatives to the transfer of generation assets
          required by the Rules (the ACC Staff stated that such transfers would
          be "unwise" at the present time and recommended that "all transfer and
          separation of utilities' assets be stayed pending the completion of
          the generic docket");

     *    The consideration of transmission constraints that could impact the
          development of the wholesale power market;

     *    The reassessment of adjustor mechanisms for standard-offer rates in
          light of problems with the development of a wholesale power market;
          and

     *    The adequacy of customer "shopping credits" in the context of the
          development of a competitive retail market (a shopping credit is the
          cost a customer does not pay to a utility distribution company if the
          customer obtains generation from another party).

Although not a specific ACC Staff recommendation, the report was also critical
of certain aspects of the proposed purchase power agreement between the Company
and Pinnacle West.

     A modification to the electric competition Rules or the 1999 Settlement
Agreement could, among other things, adversely affect our ability to transfer
our generation assets to Pinnacle West Energy by December 31, 2002. We cannot
predict the outcome of the consolidated docket or its effect on the specific
requests in our October 2001 filing, the Rules or the 1999 Settlement Agreement.

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FORWARD-LOOKING STATEMENTS

     This document contains forward-looking statements based on current
expectations and we assume no obligation to update these statements. 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 our October 2001 ACC filing; the outcome of
regulatory and legislative proceedings relating to the restructuring; state and
federal regulatory and legislative decisions and actions, including the price
mitigation plan adopted by the FERC in June 2001; regional economic and market
conditions, including the California energy situation and completion of
generation construction in the region, which could affect customer growth and
the cost of power supplies; the cost of debt and equity capital; weather
variations affecting local and regional customer energy usage; conservation
programs; power plant performance; and our ability to compete successfully
outside traditional regulated markets (including the wholesale market); and
technological developments in the electric industry.

                           REGULATION AND COMPETITION

RETAIL

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

     We are subject to varying degrees of competition from other utilities in
our region (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). We also face 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.

WHOLESALE

     GENERAL

     The FERC regulates rates for wholesale power sales and transmission
services. During 2001, approximately 39% of our electric operating revenues
resulted from such sales and services. We transferred most of the wholesale
marketing and trading activities to Pinnacle West during 2001. Pinnacle West's
marketing and trading division sells in the wholesale market our and Pinnacle
West Energy's generation production output that is not needed for our native
load and, in doing so, competes with other utilities, power marketers, and
independent power producers.

                                        5
<PAGE>
     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 order
provides for an open, flexible structure for RTOs to meet the needs of the
market and provides for the possibility of incentive ratemaking and other
benefits for utilities that participate in an RTO.

     The characteristics for an acceptable RTO include independence from market
participants, operational control over a region large enough to support
efficient and nondiscriminatory markets, and exclusive authority to maintain
short-term reliability. On October 16, 2001, we and other owners of electric
transmission lines in the Southwest filed with the FERC a request for a
declaratory order confirming that our proposal to form WestConnect RTO, LLC
would satisfy the FERC's requirements for the formation of an RTO. We and the
other filing parties have agreed to fund the start-up of WestConnect's
operations, which are subject to FERC approval. WestConnect is projected to
begin operations in 2004. WestConnect has been structured as a for-profit RTO
and evolved from DesertSTAR, a not-for-profit corporation in which we
participated, which was originally designed to serve as an RTO for the
southwestern United States.

     The ACC retail electric competition Rules also required the formation and
implementation of an Arizona Independent Scheduling Administrator. The purpose
of the AISA is to oversee the application of operating protocols to ensure
statewide consistency for transmission access. The AISA is anticipated to be a
temporary organization until the implementation of an independent system
operator or RTO. We participated in the creation of the AISA, a not-for-profit
entity, and the filing at the FERC for 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, including a "generic" docket requested by the ACC Chairman
to "determine if changed circumstances require the [ACC] to take another look at
restructuring in Arizona." See "Arizona Regulatory Developments - Overview"
above and "Proposed Rule Variance and Purchase Power Agreement" in Note 3 of
Notes to Financial Statements in Item 8 for additional information about the
consolidated ACC docket.

GENERATING FUEL AND PURCHASED POWER

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

     2001 ENERGY MIX

     Our sources of energy during 2001 were: coal - 35.7%; purchased power and
interchange (net) - 30.3% (approximately 10% of which was for wholesale power
operations); nuclear - 23.9%; gas - 9.3%; and other (includes oil, hydro and
solar) - 0.8%.

     COAL SUPPLY

     CHOLLA Cholla is a coal-fired power plant located in northeastern Arizona.
It is a jointly-owned facility operated by us. We purchase most of Cholla's coal
requirements from a coal supplier that mines all of the coal under a long-term
lease of coal reserves owned by the Navajo Nation, the federal government, and
private landholders. Cholla has sufficient coal under current contracts to
ensure a reliable fuel supply through 2005. We purchase a portion of Cholla's
coal requirements on

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the spot market to take advantage of competitive pricing options. Following
expiration of current contracts, we believe that numerous competitive fuel
supply options will exist to ensure continuous plant operation. We expect the
current supplier to continue to provide most of Cholla's low sulfur coal
requirements through the current contract. We believe that there are sufficient
reserves of low sulfur coal available from other suppliers 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 us.
We purchase all of Four Corners' coal requirements from a supplier with a
long-term lease of coal reserves owned by the Navajo Nation. Four Corners is
under contract for coal through 2004, with options to extend the contract
through the plant site lease expiration in 2016. The Four Corners lease and
related federal rights of way and easements include covenants to prevent the
Navajo Nation from taxing or assessing Four Corners or the fuel used by the
facility. These covenants expired in July 2001, and the Navajo Nation has
assessed taxes in the form of a Business Activity Tax and a Possessory Interest
Tax on the coal supplier and the plant. The tax paid by the coal supplier is
passed on to the Four Corners participants through the fuel supply agreement.
These amounts have been largely mitigated due to a New Mexico law which provides
tax credits for coal purchased on the Navajo reservation. We have contested, on
jurisdictional grounds, the right of the Navajo Nation to assess these taxes on
the plant. We are currently engaged in negotiations with the Navajo Nation on a
settlement that will provide for payments to the Navajo Nation that will allow
the continued economic operation of Four Corners. However, a settlement has not
been finalized and we cannot currently predict the outcome of this matter.

     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 - Accredited Capacity" in Item 2 for information about our
ownership interest in Cholla, Four Corners, and the Navajo Generating Station.
See Note 10 of Notes to Financial Statements in Item 8 for information regarding
our coal mine reclamation obligations.

     NATURAL GAS SUPPLY

     We purchase the majority of our natural gas requirements for our gas-fired
plants under contracts with a number of natural gas suppliers. Our natural gas
supply is transported pursuant to a firm transportation service contract with El
Paso Natural Gas Company (see description below). We continue to analyze the
market to determine the most favorable source and method of meeting our natural
gas requirements.

     The gas supply for our and Pinnacle West Energy's gas-fired facilities
located, and to be located in Pinal, Maricopa and Yuma Counties in Arizona, 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.

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     In a pending FERC proceeding, El Paso Natural Gas Company has proposed
allocating its gas pipeline capacity in such a way that our (and other companies
with the same contract type) gas transportation rights could be significantly
impacted. Various parties, including us and Pinnacle West Energy, have
challenged this allocation as being inconsistent with El Paso Natural Gas
Company's existing contractual obligations and the 1996 settlement. The FERC has
scheduled a public conference in April 2002 to discuss an appropriate mechanism
for allocating capacity on the El Paso Natural Gas Company pipeline. We cannot
currently predict the outcome of this matter.

     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 us.
The fuel cycle for Palo Verde is comprised of the following stages:

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

     The Palo Verde participants have contracted for sufficient uranium
concentrates to meet operational requirements through 2002. Spot purchases on
the uranium market will be made, as appropriate, in lieu of any uranium that
might be obtained through contractual options. Existing uranium concentrates
contracts and options could be utilized to meet approximately 67% of
requirements in 2003.

     The Palo Verde participants have contracts and options for uranium
conversion services that could be utilized to meet approximately 100% of
requirements in 2002 and 2003. The Palo Verde participants have an enrichment
services contract and an enriched uranium product contract that furnish
enrichment services required for the operation of the three Palo Verde units
through 2003.

     The Palo Verde participants have a new enriched uranium product contract
that will furnish up to 100% of Palo Verde's requirements for uranium
concentrates, conversion services and enrichment services from 2004 through
2008. This contract could also provide 100% of enrichment services in 2009 and
2010.

     In addition, existing contracts will provide 100% of fuel assembly
fabrication services until at least 2015 for each Palo Verde unit.

     SPENT NUCLEAR FUEL AND WASTE DISPOSAL Nuclear power plant operators are
required to enter into spent fuel disposal contracts with DOE, and 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 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 DOE's
delay, a number of utilities filed damages lawsuits against DOE in the Court of
Federal Claims.

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     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. A Congressional decision on this issue is expected sometime during
mid-summer 2002. We cannot currently predict what further steps will be taken in
this area.

     Facility funding is a further complication. While all nuclear utilities pay
into a so-called nuclear waste fund an amount calculated on the basis of the
output of their respective plants, 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).

     We have existing fuel storage pools at Palo Verde and are in the process of
completing construction of a new facility for on-site dry storage of spent fuel.
With the existing storage pools and the addition of the new facility, we believe
that spent 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 10
of Notes to Financial Statements in Item 8 for a discussion of interim spent
fuel storage costs.

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

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

PURCHASED POWER AGREEMENTS

     In addition to that available from our own generating capacity (see
"Properties" in Item 2), we purchase electricity under various arrangements. One
of the most important of these is a long-term contract with Salt River Project.
The amount of electricity available to us is based in large part on customer
demand within certain areas now served by us pursuant to a related territorial
agreement. The generating capacity available to us pursuant to the contract was
329 MW from January through May 2001, and starting in June 2001, as part of a
broad renegotiation of the agreement in light of the electric industry
transition to a competitive generation market, it changed to 336 MW. In 2001, we
received approximately 1,741,000 MWh of energy under the contract and paid about
$81.5 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. We may also cancel the contract on five years' notice, given
no earlier than December 31, 2006.

     In September 1990, we entered into a thirty-year seasonal capacity exchange
agreement with PacifiCorp. Under this agreement, we receive electricity from
PacifiCorp during the summer peak season (from May 15 to September 15) and we
return electricity to PacifiCorp during the winter season (from October 15 to
February 15). Until 2020, the Company and PacifiCorp each has 480 MW of capacity
and a related amount of energy available to it under the agreement for their
respective seasons. In 2001, we received approximately 571,000 MWh of energy
under the capacity exchange. We must also make additional offers of energy to
PacifiCorp each year through October

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31, 2020. Pursuant to this requirement, during 2001, PacifiCorp received offers
of 1,112,300 MWh and purchased about 434,000 MWh.

CONSTRUCTION PROGRAM

     During the years 1999 through 2001, we incurred approximately $1.3 billion
in capital expenditures. Our capital expenditures for the years 2002 through
2004 are expected to be primarily for expanding transmission and distribution
capabilities to meet growing customer needs, for upgrading existing utility
property, and for environmental purposes. Our capital expenditures were $471
million in 2001. Our capital expenditures, including expenditures for
environmental control facilities, for the years 2002 through 2004 have been
estimated as follows:

                              (dollars in millions)

               BY YEAR                       BY MAJOR FACILITIES
     ---------------------------    ---------------------------------------
     2002                 $  498    Production                       $  149
     2003                    271    Transmission and Distribution       900
     2004                    280                                     ------
                          ------    Total                            $1,049
     Total                $1,049                                     ======
                          ======

     The amounts for 2002 through 2004 assume that our generation (production)
assets are transferred to Pinnacle West Energy as of December 31, 2002. These
amounts exclude capitalized interest costs and include capitalized property
taxes and approximately $30 million (only in 2002) for nuclear fuel. We conduct
a continuing review of our construction program.

     See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Capital Needs and Resources" in Item 7 for additional
information about our construction program.

MORTGAGE REPLACEMENT FUND REQUIREMENTS

     So long as any of our first mortgage bonds are outstanding, we are required
for each calendar year to deposit with the trustee under our mortgage cash in a
formularized amount related to net additions to our mortgaged utility plant. We
may satisfy all or any part of this "replacement fund" requirement by using
redeemed or retired bonds, net property additions, or property retirements. For
2001, the replacement fund requirement amounted to approximately $155 million.
Certain of the bonds we have issued under the mortgage that are callable prior
to maturity are redeemable at their par value plus accrued interest with cash we
deposit 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 Notes 6 and 17 of Notes to Financial
Statements in Item 8 for information regarding our 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
     *    areas that have not attained national ambient air quality standards.

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     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 is currently reviewing an "Annex" to the Visibility Commission
recommendations that specifies the regional sulfur dioxide emission milestones.
The EPA's approval of the Annex would allow the Visibility Commission 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
revised implementation plans in 2008 to address visibility in those Class I
Areas which were not included in the Visibility Commission process. Because the
Annex is not final and Arizona and the Navajo Nation have the discretion to
choose between the national or the alternate options, the actual impact on us
cannot be determined at this time.

     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. A federal court determined that the EPA's promulgation of the National
Ambient Air Quality Standards violated the constitutional

                                       11
<PAGE>
prohibition on delegation of legislative power. The court remanded the ozone
standard, vacated the particulate matter standard, and invited the parties that
challenged the standards to brief the court on vacating or remanding the very
fine particulates standard. On February 27, 2001, the U.S. Supreme Court
overruled the federal court's ruling. The Supreme Court further held that the
EPA could not consider the cost of reducing harmful emissions when setting air
quality standards. However, the Supreme Court found the EPA implementation
policy for the revised ozone standards to be unlawful, and remanded this issue
for consideration along with the other preserved challenges to the National
Ambient Air Quality Standards. Because the actual level of emissions controls,
if any, for any unit cannot be determined at this time, we currently cannot
estimate the capital expenditures, if any, which would result from the final
rules. However, we do not currently expect these rules to have a material
adverse effect on our financial position, results of operations, or liquidity.

     With respect to hazardous air pollutants emitted by electric utility steam
generating units, the EPA recently 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 us to make related
expenditures, such as permit fees. We do not expect any of these expenditures to
have a material impact on our 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. We do not currently expect the FIP to have a material impact on
our 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
us that the EPA considers us to be a PRP in the Indian Bend Wash Superfund Site,
South Area. Our 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, we do not expect this matter to have a material impact on our
financial position, results of operations, or liquidity.

     MANUFACTURED GAS PLANT SITES We are currently investigating properties
which we now own or which were previously owned by us or our corporate
predecessors, that were at one time sites of, or sites associated with,
manufactured gas plants. The purpose of this investigation is to determine if:

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

     Where appropriate, we have begun clean-up of certain of these sites. We do
not expect these matters to have a material adverse effect on our financial
position, results of operations, or liquidity.

                                       12
<PAGE>
     ARIZONA DEPARTMENT OF ENVIRONMENTAL QUALITY

     ADEQ issued to us Notices of Violation (NOV), dated September 25, 2001 and
October 15, 2001 alleging, among other things, burning of unauthorized materials
and storage of hazardous waste without a permit at the Cholla Power Plant. Each
Notice of Violation requires us to achieve and document compliance with specific
environmental requirements. We have submitted responses to the NOVs as well as
additional information requested by the agency. To date, ADEQ has not sought
penalties or taken other enforcement actions against us. We do not expect these
matters to have a material adverse effect on our 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. We are the Four Corners operating agent.
We own a 100% interest in Four Corners Units 1, 2, and 3, and a 15% interest in
Four Corners Units 4 and 5. We own a 14% interest in Navajo Generating Station
Units 1, 2, and 3.

     In July 1995, the Navajo Nation enacted the Navajo Nation Air Pollution
Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the
Navajo Nation Pesticide Act (collectively, the Navajo Acts). The Navajo Acts
purport to give the Navajo Nation Environmental Protection Agency authority to
promulgate regulations covering air quality, drinking water, and pesticide
activities, including those 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
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. We cannot currently predict the outcome of this matter.

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

                                       13
<PAGE>
     On August 8, 2000, the EPA signed an Eligibility Determination for the
Navajo Nation for Grants Under Section 105 of the Clean Air Act in which the EPA
determined that the Navajo Nation was eligible to receive grants under the Clean
Air Act. On September 8, 2001, after learning of the eligibility determination,
we filed a Petition for Review of the EPA's decision in the United States Court
of Appeals for the Ninth Circuit in order to ensure that the EPA's August 2000
determination not be construed to constitute a determination of the Navajo
Nation's authority to regulate Four Corners and the Navajo Generating Station.
APS V. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY, No. 01-71577. The Company,
the EPA and other parties have requested that the Court stay any further
briefing while they negotiate a settlement.

     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, we have adequate water to meet our needs. However, conflicting
claims to limited amounts of water in the southwestern United States have
resulted in numerous court actions.

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

     A summons served on us in early 1986 required all water claimants in the
Lower Gila River Watershed in Arizona to assert any claims to water on or before
January 20, 1987, in an action pending in Maricopa County Superior Court. (IN RE
THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE GILA RIVER SYSTEM AND
SOURCE, Supreme Court Nos. WC-79-0001 through WC-79-0004 (Consolidated) [WC-1,
WC-2, WC-3 and WC-4 (Consolidated)], Maricopa County Nos. W-1, W-2, W-3 and W-4
(Consolidated)). Palo Verde is located within the geographic area subject to the
summons. Our rights and the rights of the Palo Verde participants to the use of
groundwater and effluent at Palo Verde are potentially at issue in this action.
As project manager of Palo Verde, we filed claims that dispute the court's
jurisdiction over the Palo Verde participants' groundwater rights and their
contractual rights to effluent relating to Palo Verde. Alternatively, we seek
confirmation of such rights. Three of our other power plants and one of Pinnacle
West Energy's power plants are also located within the geographic area subject
to the summons. Our claims dispute the court's jurisdiction over our groundwater
rights with respect to these plants. Alternatively, we seek confirmation of such
rights. In November 1999, the Arizona Supreme Court issued a decision confirming
that certain groundwater rights may be available to the federal government and
Indian tribes. In addition, in September 2000, the Arizona Supreme Court issued
a decision affirming the lower court's criteria for resolving groundwater
claims. Litigation on both of these issues will

                                       14
<PAGE>
continue in the trial court. No trial date concerning our water rights claims
has been set in this matter.

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

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

                               ITEM 2. PROPERTIES

ACCREDITED CAPACITY

     Our present generating facilities have an accredited capacity 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(1)
     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..................................................       6,585
                                                                    ---------

Total Facilities.................................................   3,982,885
                                                                    ---------

----------
(1)  Does not include West Phoenix steam units (108,300 kW), which were removed
     from mothballs and placed in service for 2001 summer reliability.

                                       15
<PAGE>
RESERVE MARGIN

     Our 2001 peak one-hour demand on our electric system was recorded on July
2, 2001, at 5,687,200 kW, compared to the 2000 peak of 5,478,500 kW recorded on
July 25, 2000. Taking into account additional capacity then available to us
under long-term purchase power contracts as well as our and Pinnacle West
Energy's generating capacity, our capability of meeting system demand on July 2,
2001, amounted to 5,180,600 kW, including capacity from Pinnacle West Energy's
West Phoenix Unit 4 (112,000 kW), for an installed reserve margin of (11.1%).
The power actually available to us from our 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 2001 peak amounted to
3,234,500 kW, for a margin of (43.3%). Firm purchases, including short-term
seasonal purchases and unit contingent purchases, totaling 2,490,000 kW were in
place at the time of the peak ensuring the ability to meet the load requirement,
with an actual reserve margin of 1.1%.

     See "Generating Fuel and Purchased Power - Purchased Power Agreements" in
Item 1 for information about certain of our 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 "Generating Fuel and Purchased Power -- Coal Supply" in Item 1.

PALO VERDE NUCLEAR GENERATING STATION

     PALO VERDE LEASES

     See Note 8 of Notes to 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
us, as operating agent for Palo Verde, to operate the three Palo Verde units at
full power.

     NUCLEAR DECOMMISSIONING COSTS

     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." Other mechanisms are prescribed, including prepayment, if the
requirements for exclusive reliance on the external sinking fund mechanism are
not met. We currently rely on the external sinking fund mechanism to meet the
NRC financial assurance requirements for our interests in Palo Verde Units 1, 2,
and 3. The decommissioning costs of Palo Verde Units 1, 2, and 3 are currently
included in our ACC jurisdictional rates. ACC retail electric

                                       16
<PAGE>
competition Rules provide that decommissioning costs would be recovered through
a non-bypassable "system benefits" charge, which would allow us to maintain our
external sinking fund mechanism. See Note 11 of Notes to Financial Statements in
Item 8 for additional information about our nuclear decommissioning costs. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Business Outlook - Others Factors Affecting Our Financial Outlook"
in Item 7 and Note 3 of Notes to Financial Statements in Item 8 for additional
information about the ACC retail electric competition Rules and the legal
challenges to these Rules.

     PALO VERDE LIABILITY AND INSURANCE MATTERS

     See "Palo Verde Nuclear Generating Station" in Note 10 of Notes to
Financial Statements in Item 8 for a discussion of the insurance maintained by
the Palo Verde participants, including us, for Palo Verde.

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.

     See Notes 6, 8, and 9 of Notes to Financial Statements in Item 8 with
respect to our property not held in fee or held subject to any major
encumbrance.

                                       17
<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 our service area, the location of its major power
plants and principal transmission lines, the location of Pinnacle West Energy's
power plant, and the location of transmission lines operated by us for others.
Our 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; and the Palo Verde
Nuclear Generating Station, located about 55 miles west of Phoenix, Arizona
(each of which plants is reflected on such map as being jointly owned with other
utilities), as well as the Ocotillo Power Plant and West Phoenix Power Plant,
each located near Phoenix, Arizona, and the Saguaro Power Plant, located near
Tucson, Arizona. Pinnacle West Energy's power plant shown on such map is Unit 4
of the West Phoenix Power Plant located near Phoenix, Arizona. Our 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.

                                       18
<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
Financial Statements in Item 8 for a discussion of competition and the ACC
retail electric competition Rules and related litigation. In December 1999, we
filed a lawsuit to protect our legal rights regarding the Rules, and in the
complaint we asked the Court for (i) a judgment vacating the retail electric
competition Rules, (ii) a declaratory judgment that the Rules are unlawful
because, among other things, they were entered into without proper legal
authorization, and (iii) a permanent injunction barring the ACC from enforcing
or implementing the Rules and from promulgating any other regulations without
lawful authority. ARIZONA PUBLIC SERVICE COMPANY V. ARIZONA CORPORATION
COMMISSION, CV 99-21907. On August 28, 1998, we filed two lawsuits to protect
our legal rights under the stranded cost order and in our complaints we asked
the Court to vacate and set aside the order. ARIZONA PUBLIC SERVICE COMPANY V.
ARIZONA CORPORATION COMMISSION, CV 98-15728. ARIZONA PUBLIC SERVICE COMPANY V.
ARIZONA CORPORATION COMMISSION, 1-CA-CC-98-0008. Consistent with our obligations
under the 1999 Settlement Agreement, on January 7, 2002, we and the ACC filed in
Maricopa County, Arizona, Superior Court a stipulation to dismiss the foregoing
litigation. On January 15, 2002, a Maricopa County Superior Court judge issued
an order dismissing the litigation. See "1999 Settlement Agreement" in Note 3 of
Notes to Financial Statements in Item 8 for additional information about the
1999 Settlement Agreement and the resolution of legal challenges to the 1999
Settlement Agreement.

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

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

     Not applicable.

                                       19
<PAGE>
                                     PART II

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

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

     The chart below sets forth the dividends declared on the Company's common
stock for each of the four quarters for 2001 and 2000.

                             COMMON STOCK DIVIDENDS
                             (DOLLARS IN THOUSANDS)
--------------------------------------------------------------------------------
       QUARTER                        2001                            2000
--------------------------------------------------------------------------------
     1st Quarter                    $42,500                         $42,500
     2nd Quarter                     42,500                          42,500
     3rd Quarter                     42,500                          42,500
     4th Quarter                     42,500                          42,500
--------------------------------------------------------------------------------

     After payment or setting aside for payment of cumulative dividends and
mandatory sinking fund requirements, where applicable, on all outstanding issues
of preferred stock, the holders of common stock are entitled to dividends when
and as declared out of funds legally available therefor. See Note 6 of Notes to
Financial Statements in Item 8 for restrictions on retained earnings available
for the payment of common stock dividends. As of December 31, 2001, we did not
have any outstanding preferred stock.

                                       20
<PAGE>
                         ITEM 6. SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
                                              2001           2000           1999           1998          1997
                                           -----------    -----------    -----------    -----------   -----------
                                                                    (DOLLARS IN THOUSANDS)
<S>                                        <C>            <C>            <C>            <C>           <C>
Electric operating revenues ............   $ 3,310,792    $ 3,480,252    $ 2,292,798    $ 2,006,398   $ 1,878,553
Purchased power and fuel ...............     1,740,643      1,878,738        793,316        543,153       441,533
Operating expenses .....................     1,171,171      1,155,278      1,115,664      1,097,471     1,070,517
                                           -----------    -----------    -----------    -----------   -----------
  Operating income .....................       398,978        446,236        383,818        365,774       366,503
Other income/(expense) .................           (79)        (6,545)        20,857         20,315        21,453
Interest deductions -- net .............       118,211        133,097        136,353        130,842       136,463
                                           -----------    -----------    -----------    -----------   -----------
  Income before extraordinary charge
    and cumulative effect adjustment ...       280,688        306,594        268,322        255,247       251,493
  Extraordinary charge - net of tax ....            --             --       (139,885)            --            --
  Cumulative effect of change in
    accounting - net of tax ............       (15,201)            --             --             --            --
                                           -----------    -----------    -----------    -----------   -----------
  Net income ...........................       265,487        306,594        128,437        255,247       251,493

  Preferred dividends ..................            --             --          1,016          9,703        12,803
                                           -----------    -----------    -----------    -----------   -----------

  Earnings for common stock ............   $   265,487    $   306,594    $   127,421    $   245,544   $   238,690
                                           ===========    ===========    ===========    ===========   ===========

Total Assets ...........................   $ 6,367,054    $ 6,413,549    $ 6,117,624    $ 6,393,299   $ 6,331,142
                                           ===========    ===========    ===========    ===========   ===========

Capital Structure:
  Common stock equity ..................   $ 2,150,690    $ 2,119,768    $ 1,983,174    $ 1,975,755   $ 1,849,324
  Non-redeemable preferred stock .......            --             --             --         85,840       142,051
  Redeemable preferred stock ...........            --             --             --          9,401        29,110
  Long-term debt less current maturities     1,949,074      1,806,908      1,997,400      1,876,540     1,953,162
                                           -----------    -----------    -----------    -----------   -----------
    Total capitalization ...............     4,099,764      3,926,676      3,980,574      3,947,536     3,973,647
  Commercial paper .....................       171,162         82,100         38,300        178,830       130,750
  Current maturities of long-term debt .       125,451        250,266        114,711        164,378       104,068
                                           -----------    -----------    -----------    -----------   -----------
    Total ..............................   $ 4,396,377    $ 4,259,042    $ 4,133,585    $ 4,290,744   $ 4,208,465
                                           ===========    ===========    ===========    ===========   ===========
</TABLE>

See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" in Item 7 for a discussion of certain information in the table
above.

                                       21
<PAGE>
                  ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
                OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

                                  INTRODUCTION

     In this section, we explain the results of operations, general financial
condition, and outlook including:

     *    the changes in our earnings from 2000 to 2001 and from 1999 to 2000;

     *    our capital needs, liquidity and capital resources;

     *    our marketing and trading activities;

     *    our financial outlook;

     *    our critical accounting policies;

     *    major factors that affect our financial outlook; and

     *    our management of market risks.

                            OVERVIEW OF OUR BUSINESS

     We are Arizona's largest electric utility and provide either retail or
wholesale electric service to substantially all of the state, with the major
exceptions of the Tucson metropolitan area and about one-half of the Phoenix
metropolitan area. We also generate and, through Pinnacle West's marketing and
trading division, sell and deliver electricity to wholesale customers in the
western United States. Pinnacle West owns all of our outstanding common stock.

     We are required to transfer our competitive electric assets and services to
one or more corporate affiliates no later than December 31, 2002. Consistent
with that requirement, we have been addressing the legal and regulatory
requirements necessary to complete the transfer of our generation assets to
Pinnacle West Energy before that date. As we discuss in greater detail below
under "Business Outlook - Other Factors Affecting Our Financial Outlook," recent
Arizona regulatory developments have raised uncertainty about the status and
pace of retail electric competition in Arizona, including our transfer of
generation assets to Pinnacle West Energy.

                                BUSINESS SEGMENTS

     We have two principal business segments (determined by products, services
and regulatory environment), which consist of regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
currently includes activities related to electricity transmission and
distribution, as well as electricity generation. Our marketing and trading
segment currently includes activities related to wholesale marketing and
trading.

     These reportable segments reflect a change in the reporting of our segment
information. Before the fourth quarter of 2001, we had two segments (generation
and delivery). The "generation segment" information combined our marketing and
trading activities with our generation of electricity activities. The "delivery
segment" included transmission and distribution activities.

                                       22
<PAGE>
     In the fourth quarter, we filed with the ACC a request for a proposed rule
variance and approval of a purchase power agreement (see Note 3) that inherently
views our business in the new reportable segments described herein. Internal
management reporting has been changed to reflect this alignment. See "Business
Segments" in Note 15 for more information about our business segments.

     The following is a summary of earnings by business segment for 2001, 2000,
and 1999 (dollars in millions):

                                                   2001        2000       1999
                                                   -----       -----      -----
Retail                                             $ 140       $ 230      $ 257
Marketing and trading                                140          77         10
                                                   -----       -----      -----
  Income from continuing operations                  280         307        267
Extraordinary charge - net of
  income taxes                                        --          --       (140)
Cumulative effect of change in
  accounting - net of income taxes                   (15)         --         --
                                                   -----       -----      -----
    Earnings for common stock                      $ 265       $ 307      $ 127
                                                   =====       =====      =====

Throughout this section, we refer to specific "Notes" in the Notes to Financial
Statements that begin on page 48. These Notes add further details to the
discussion.

                                       23
<PAGE>
                              RESULTS OF OPERATIONS

     2001 COMPARED WITH 2000

     Our net income for the year ended December 31, 2001 was $265 million
compared with $307 million for the year ended December 31, 2000. In 2001, we
recognized a $15 million after-tax loss in net income as a cumulative effect of
a change in accounting for derivatives. See Note 16 for further discussion on
accounting for derivatives.

     Income before accounting change for the year ended December 31, 2001 was
$281 million compared with $307 million for the year ended December 31, 2000.
The year-to-year comparison benefited from strong marketing and trading results
and retail customer growth. These factors were partially offset by higher
purchased power and fuel costs, due in part to increased power plant
maintenance; generation reliability measures; continuing retail electricity
price decreases; and a charge related to Enron and its affiliates. The major
factors that increased (decreased) income before accounting change were as
follows (dollars in millions):

                                                                     Increase
                                                                    (Decrease)
                                                                    ----------
Increases(decreases) in electric revenues, net of purchased power
  and fuel expense due to:
    Marketing and trading activities:
      Increase from generation sales other than native load
        due to higher market prices                                    $  25
      Decrease in other realized marketing and trading in
        current period primarily due to less transactions                 (9)
      Change in prior period mark-to-market value for commodity
        contracts delivered in current period                             18 (a)
      Increase in mark-to-market value related to future periods          71 (a)
                                                                       -----
    Net increase in marketing and trading                                105
Higher replacement power costs for plant outages related to higher
  market prices                                                          (70)
Higher purchased power costs related to 2001 generation
  reliability program                                                    (30)
Retail price reductions (see Note 3)                                     (27)
Charges related to purchased power contracts with Enron
  and its affiliates                                                     (13)(b)
Miscellaneous revenues                                                     3
                                                                       -----
Total decrease in revenues, net of purchased power and fuel expense      (32)
Higher operations and maintenance expense related to 2001
  generation reliability program                                         (12)
Higher operations and maintenance expense related primarily to
  employee benefits, plant outage and maintenance, and other costs       (23)
Lower net interest expense primarily due to lower interest rates          15
Higher other net income                                                   10
Miscellaneous items, net                                                   3
                                                                       -----
  Net decrease in income before income taxes                             (39)
Lower income taxes primarily due to lower income                          13
                                                                       -----
  Net decrease in income before accounting change                      $ (26)
                                                                       =====

----------
(a)  Essentially all of our marketing and trading activities are structured
     activities. This means our portfolio of forward sales positions is hedged
     with a portfolio of forward purchases that protects the economic value of
     the sales transactions.

                                       24
<PAGE>
(b)  We recorded charges totaling $13 million before income taxes for exposure
     to Enron and its affiliates in the fourth quarter of 2001.

     Electric operating revenues decreased approximately $170 million because
of:

     *    changes in marketing and trading revenues ($193 million, net decrease)
          due to:
          -    increased revenues related to generation sales other than native
               load as a result of higher average market prices ($32 million);
          -    decreased realized revenues related to other marketing and
               trading in current period primarily due to less transactions
               ($307 million);
          -    increased prior period mark-to-market value for losses
               transferred to realized margin in current period ($11 million);
          -    increased mark-to-market value for future periods primarily as a
               result of more forward sales volumes ($71 million);
     *    decreased revenues related to other wholesale sales and miscellaneous
          revenues as a result of sales volumes ($28 million);
     *    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).

     Purchased power and fuel expenses decreased approximately $138 million
primarily because of:

     *    changes in marketing and trading purchased power and fuel costs ($298
          million, net decrease) due to:
          -    increased fuel costs related to generation sales other than
               native load as a result of higher fuel prices ($7 million);
          -    decreased fuel and purchased power costs related to other
               realized marketing and trading in current period primarily due to
               less transactions ($298 million);
          -    decreased mark-to-market fuel costs related to accounting for
               derivatives ($7 million) (see Note 16);
     *    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 purchase power costs related to 2001 generation reliability
          program ($30 million);
     *    higher costs related to retail sales volumes due to customer growth
          ($78 million); and
     *    charges related to purchased power contracts with Enron and its
          affiliates ($13 million).

     The increase in operations and maintenance expenses of $35 million
primarily related to the 2001 generation summer reliability program (the
addition of generating capability to enhance reliability for the summer of 2001
($12 million)) and increased employee benefit costs, plant outage and
maintenance, and other costs ($23 million).

     Other net income increased $10 million primarily because of insurance
recovery of environmental remediation costs.

     Interest expense decreased by $15 million primarily because of lower
interest rates and increased capitalized interest resulting from higher
construction project balances.

                                       25
<PAGE>
     2000 COMPARED WITH 1999

     Our earnings for the year ended December 31, 2000 were $307 million
compared with $127 million for the year ended December 31, 1999. Our 2000
earnings increased $180 million over 1999 primarily because of a $140 million
after-tax extraordinary charge that we recorded in 1999. This charge reflected a
regulatory disallowance resulting from an ACC-approved Settlement Agreement
related to the implementation of retail electric competition. See "Regulatory
Agreements" below and Notes 1 and 3 for additional information about the 1999
Settlement Agreement and the resulting regulatory disallowance.

     Earnings excluding the extraordinary charge increased $39 million, or 15%,
over 1999 primarily because of increases in wholesale and retail electric sales.
These positive factors more than offset decreases resulting from the completion
of ITC amortization in 1999, reductions in retail electricity prices, and
miscellaneous factors. See "Regulatory Agreements" below and Note 3 for
information on the price reductions. See "Regulatory Agreements" below and Note
4 for additional information about ITC amortization. The major factors that
increased (decreased) earnings were as follows (dollars in millions):

                                                                     Increase
                                                                    (Decrease)
                                                                    ----------
Increases(decreases) in electric revenues, net of purchased power
  and fuel expense due to:
    Marketing and trading activities:
      Increase from generation sales other than native load due to
        higher market prices                                           $  47
      Increase in other realized marketing and trading in current
        period primarily due to more transactions                         52
      Change in prior period mark-to-market value for commodity
        contracts delivered in current period                             (2)(a)
      Increase in mark-to-market value related to future periods          13 (a)
                                                                       -----
    Net increase in marketing and trading                                110
Retail price reductions (see Note 3)                                     (28)
Higher retail sales primarily related to customer growth                  10
Miscellaneous revenues                                                    10
                                                                       -----
Total increase in revenues, net of purchased power and fuel expense      102
Lower operations and maintenance expense related primarily to $19
  million of non-recurring items recorded in 1999 partially offset
  by increased costs related to customer growth                            7
Higher depreciation and amortization expense                              (9)
Miscellaneous items, net                                                   2
                                                                       -----
    Net increase in income before income taxes                           102
Higher income taxes due to higher income in 2000 and higher ITC
  amortization in 1999                                                   (63)
                                                                       -----
    Net increase in income before extraordinary charge and
      accounting change                                                $  39
                                                                       =====

----------
(a)  Essentially all of our marketing and trading activities are structured
     activities. This means our portfolio of forward sales positions is hedged
     with a portfolio of forward purchases that protects the economic value of
     the sales transactions.

                                       26
<PAGE>
     Electric operating revenues increased approximately $1.19 billion because
of:

     *    changes in marketing and trading revenues ($565 million, net increase)
          due to:
          -    increased revenues related to generation sales other than native
               load as a result of higher market prices ($86 million);
          -    increased realized revenues related to other marketing and
               trading in current period primarily due to more transactions and
               higher market prices ($468 million);
          -    decreased prior period mark-to-market value for gains transferred
               to realized margin in current period ($2 million);
          -    increased mark-to-market value for future periods primarily as a
               result of more forward sales volumes ($13 million);
     *    increased revenues related to increased volumes and higher market
          prices for other wholesale sales resulting from retail load hedging
          activities and miscellaneous revenues ($523 million);
     *    increased retail revenues primarily related to higher sales volumes
          due to customer growth ($127 million); and
     *    decreased retail revenues related to reductions in retail electricity
          prices ($28 million).

     Purchased power and fuel expenses increased approximately $1.09 billion
primarily due to:

     *    changes in marketing and trading purchased power and fuel costs ($455
          million, net increase) due to:
          -    increased fuel costs related to generation sales other than
               native load as a result of higher fuel prices ($39 million);
          -    increased fuel and purchased power costs related to other
               realized marketing and trading in current period primarily due to
               more transactions ($416 million);
     *    increased costs related to increased volumes and higher market prices
          for wholesale sales resulting from retail hedging activities ($513
          million); and
     *    higher costs related to retail sales volumes due to customer growth
          and increased fuel and purchased power prices ($117 million).

     The decrease in operations and maintenance expenses of $7 million primarily
related to $19 million of non-recurring items recorded in 1999 partially offset
by increased costs related to customer growth.

     The increase in depreciation and amortization of $9 million primarily
related to higher plant in service balances offset by lower regulatory asset
amortization.

     REGULATORY AGREEMENTS

     Regulatory agreements approved by the ACC affect the results of our
operations. The following discussion focuses on three agreements approved by the
ACC, each of which included retail electricity price reductions:

     *    The 1999 Settlement Agreement to implement retail electric
          competition;

     *    A 1996 agreement that accelerated the amortization of our regulatory
          assets; and

     *    A 1994 settlement that accelerated the amortization of our deferred
          ITCs.

                                       27
<PAGE>
     1999 SETTLEMENT AGREEMENT

     As part of the 1999 Settlement Agreement, we 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%. The first reduction of approximately
$24 million ($14 million after income taxes) included the July 1, 1999 retail
price decrease required by the 1996 regulatory agreement (see below). For
customers having loads three megawatts or greater, standard-offer rates will be
reduced in annual increments that total 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. We 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 income statement.

     Under the 1996 regulatory agreement, we were recovering substantially all
of our regulatory assets through accelerated amortization over an eight-year
period that would have ended June 30, 2004. For more details, see Note 1. The
regulatory assets to be recovered under the 1999 Settlement Agreement are
currently being amortized as follows (dollars in millions):

                                                            1/1 - 6/30
1999         2000         2001         2002        2003        2004        Total
----         ----         ----         ----        ----        ----        -----
$164         $158         $145         $115         $86         $18         $686

     See Note 3 and "Business Outlook - Electric Competition (Retail)" below for
additional information regarding the 1999 Settlement Agreement.

     1996 REGULATORY AGREEMENT

     As part of the 1996 regulatory agreement, we reduced our retail electricity
prices by 3.4% effective July 1, 1996. This reduction decreased electric revenue
by about $49 million annually ($29 million after income taxes). We also agreed
to share future cost savings with our customers during the term of this
agreement, which resulted in the following additional retail price reductions:

     *    $18 million annually ($11 million after income taxes), or 1.2%,
          effective July 1, 1997;

     *    $17 million annually ($10 million after income taxes), or 1.1%,
          effective July 1, 1998; and

     *    $11 million annually ($7 million after income taxes), or 0.7%,
          effective July 1, 1999 (as noted above, this reduction was included in
          the July 1, 1999 price reduction under the 1999 Settlement Agreement).

     1994 RATE SETTLEMENT

     As part of a 1994 rate settlement, we accelerated amortization of
substantially all of our ITCs over a five-year period that ended on December 31,
1999. The amortization of ITCs decreased annual income tax expense by about $28
million. Beginning in 2000, no further benefits were reflected in income tax
expense related to the acceleration of the ITCs (see Note 4).

                                       28
<PAGE>
                         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, 2001 and estimated capital expenditures for the next three
years.

                              CAPITAL EXPENDITURES
                              (dollars in millions)

                                     (actual)           (estimated)
                                      ------    --------------------------
                                       2001      2002      2003      2004
                                      ------    ------    ------    ------
     Delivery                         $  354    $  349    $  271    $  280
     Generation (a)                      117       149        --        --
                                      ------    ------    ------    ------
         Total                        $  471    $  498    $  271    $  280
                                      ======    ======    ======    ======

----------
(a)  Pursuant to the 1999 Settlement Agreement, we are required to transfer our
     competitive electric assets and services no later than December 31, 2002.

     We and the other Palo Verde participants are currently considering issues
related to replacement of the steam generators in Units 1 and 3. Although a
final determination of whether Units 1 and 3 will require steam generator
replacement to operate over their current full licensed lives has not yet been
made, the other participants and us have approved an expenditure in 2002 to
procure long lead-time materials for fabrication of a spare set of steam
generators for either Unit 1 or 3. Our portion of this expenditure is
approximately $7 million and is included in the estimated expenditures above.
This action will provide the other Palo Verde participants and us an option to
replace the steam generators at either Unit 1 or 3 as early as fall 2005 should
we ultimately choose to do so. If the participants decide to proceed with steam
generator replacement at both Units 1 and 3, we have estimated that our portion
of the fabrication and installation costs and associated power uprate
modifications would be approximately $130 million over the next seven years,
which would be funded with internally-generated cash or external financings.

     Generation capital expenditures are comprised of multiple improvements for
our existing fossil and nuclear plants. Examples of the types of projects
included in this category are additions, upgrades and capital replacements of
various power plant equipment such as turbines, boilers, and environmental
equipment. The increase in this category in 2002 is due primarily to Four
Corners and various gas-fired units. The increased work on equipment is due to
higher use of the units and also a stack replacement project for Four Corners
Units 1 and 2. The 2002 generation category also contains approximately $30
million of nuclear fuel expenditures.

     Delivery capital expenditures are comprised of transmission and
distribution (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, we began several major
transmission projects in 2001. These projects are periodic in nature and are

                                       29
<PAGE>
driven by strong regional customer growth. We expect to spend about $150 million
on major transmission projects during the 2002-2004 time frame.

     CAPITAL RESOURCES AND CASH REQUIREMENTS

     We had lines of credit available in the amount of $250 million at December
31, 2001. There was no outstanding balance on our lines of credit at December
31, 2001. We project that these lines of credit will be available over the next
three years. The lines of credit are anticipated to be renewed at their
expiration dates. See Note 5 for further information on our lines of credit.

     We have obtained approximately $500 million in letters of credit primarily
to provide credit support for our variable rate tax-exempt bonds and our Palo
Verde sale-leaseback transactions.

     We do not have ratings triggers in any of our debt agreements. Ratings
triggers are provisions that would result in the acceleration of repayment
obligations based upon a credit rating agency downgrade. Although those rating
triggers appear in certain power marketing and trading agreements, their
financial impacts are not expected to be significant.

     Our first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel, transportation equipment and other
excluded assets). The mortgage bond indenture restricts the payment of common
stock dividends under certain conditions. These conditions did not exist at
December 31, 2001.

     Our capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. We pay for our capital
requirements with cash from operations and, to the extent necessary, external
financing. We pay for our dividends to Pinnacle West with cash from operations.

     During the period from 1999 through 2001, we paid for substantially all of
our capital expenditures with cash from operations. We expect to do so in 2002
through 2004 with cash from operations and our debt issuances.

     See the capital expenditure table above for additional information
regarding actual capital expenditures in 2001 and projected capital expenditures
for the next three years.

     The following table summarizes cash commitments for the year ended December
31, 2001 and estimated commitments for the next three years (dollars in
millions):

                                           (actual)           (estimated)
                                            ------    --------------------------
                                             2001      2002      2003      2004
                                            ------    ------    ------    ------
Long-term debt repayments (see Note 6)      $  384    $  247    $   --    $  205
Operating leases payments (see Note 8)          62        63        61        61
Fuel and purchase power commitments
  (see Note 10)                                374       252       124        80
                                            ------    ------    ------    ------
Total cash commitments                      $  820    $  562    $  185    $  346
                                            ======    ======    ======    ======

     Based on market conditions and call provisions, we may make optional
redemptions of long-term debt from time to time.

     As of December 31, 2001, we 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

                                       30
<PAGE>
as bank borrowings. At the end of 2001, we had about $171 million of commercial
paper outstanding and no long-term bank borrowings.

     Our long-term debt was approximately $2.1 billion at December 31, 2001 and
2000 (see Note 6).

     Although ACC financing orders establish maximum amounts of additional debt
that we may issue, we do not expect these orders to limit our ability to meet
our capital requirements.

     On March 1, 2002, we issued $375 million of 6.50% Notes due 2012. On March
15, 2002, we announced the redemption on April 15, 2002 of approximately $125
million of our First Mortgage Bonds, 8.75% Series due 2024.

                          CRITICAL ACCOUNTING POLICIES

     In preparing the financial statements in accordance with generally accepted
accounting principles (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. Our most critical
accounting policies include the determination of the appropriate accounting for
our derivative instruments, mark-to-market accounting and the impacts of
regulatory accounting on our financial statements. See Note 1 for a discussion
of these critical accounting policies.

                            OTHER ACCOUNTING MATTERS

     We prepare our financial statements in accordance with Statement of
Financial Accounting Standards (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 of the 1999 Settlement Agreement (see "Regulatory
Agreements" above and Note 3), we discontinued the application of SFAS No. 71
for our generation operations. As a result, we tested the generation assets for
impairment and determined that the generation assets were not impaired. Pursuant
to the 1999 Settlement Agreement, we reported a regulatory disallowance ($140
million after income taxes) as an extraordinary charge on the 1999 income
statement. See Note 1 for additional information on regulatory accounting and
Note 3 for additional information on the 1999 Settlement Agreement.

     Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires that
entities recognize all derivatives as either assets or liabilities on the
balance sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or stockholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. Hedge effectiveness is measured based on the relative changes in fair
value between the derivative contract and the hedged commodity over time. Any
change in the fair value resulting from ineffectiveness is recognized
immediately in net income. This new standard may result in additional volatility
in our net income and other comprehensive income.

     As a result of adopting SFAS No. 133 in 2001, we recorded a $15 million
after-tax loss in net income and a $72 million after-tax gain in equity (as a
component of other comprehensive income), both as a cumulative effect of a
change in accounting principle. The loss primarily resulted from

                                       31
<PAGE>
electricity options contracts. The gain resulted from unrealized gains on cash
flow hedges. See Note 16 for further information on accounting for derivatives
under SFAS No. 133, including discussions on new guidance effective on April 1,
2002.

     In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." This Statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes Accounting
Principles Board Opinion No. 17, "Intangible Assets." This standard is effective
for the year beginning January 1, 2002. We have no goodwill recorded in the
balance sheets. The impacts of this new standard are not material to our
financial statements.

     The FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations," in August 2001. The standard requires the estimated present value
of the cost of decommissioning and certain other removal costs to be recorded as
a liability, along with an offsetting plant asset, when a decommissioning or
other removal obligation is incurred. We are currently evaluating the impacts of
the new standard, which is effective for the year beginning January 1, 2003.

     In October 2001, the FASB issued 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. SFAS No. 144 is effective for the year
beginning January 1, 2002. This standard does 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 (PP&E)." This
proposed SOP would create a project timeline framework for capitalizing costs
related to PP&E construction, require that PP&E assets be accounted for at the
component level and require administrative and general cost incurred in support
of capital projects to be expensed in the current period. The AICPA plans to
issue the final SOP in the fourth quarter of 2002. We are currently evaluating
the impacts of the proposed SOP.

     In 1986, we entered into agreements with three separate special purpose
entity (SPE) lessors in order to sell and lease back interests in Palo Verde
Unit 2 (see Note 8). The leases are accounted for as operating leases in
accordance with GAAP. In February 2002, the FASB discussed issues related to
special purpose entities. It is expected that FASB will issue additional
guidance on accounting for SPEs later this year. As a result of future FASB
actions, we may be required to consolidate the SPEs in our financial statements.
If consolidation is required, the assets and liabilities of the SPEs that relate
to the sale-leaseback transactions would be reflected on our balance sheets. The
SPE debt that is not reflected on our balance sheets is approximately $300
million at December 31, 2001. Rating agencies have already considered this debt
when evaluating our credit ratings.

                                BUSINESS OUTLOOK

FINANCIAL OUTLOOK

     For 2001, our reported income before accounting change was $281 million and
included charges totaling $13 million before income taxes that we do not expect
to recur related to our exposure to Enron and its affiliates. Our earnings in
2002 are expected to be negatively affected by the completed transition to
Pinnacle West in 2001 of marketing and trading activities, as well as retail
electricity price decreases. These negative factors are expected to be partially
offset in 2002

                                       32
<PAGE>
by the absence of significant expenses for reliability and power plant outages
that we incurred in 2001 that we do not expect to recur in 2002 and by retail
customer growth, although the pace of growth is expected to be slower than in
the past. These factors are described in more detail below.

     As of December 31, 2001, we completed the transition of marketing and
trading activities to Pinnacle West's marketing and trading division. In 2001,
we recorded the following pretax amounts related to marketing and trading
activities: $749 million of electric operating revenues and $517 million of
purchased power and fuel costs.

     During 2001, in order to meet the highest customer demand in our history,
we incurred significant expenses for our summer reliability program and for
higher replacement power costs related to power plant outages. These efforts
cost approximately $140 million before income taxes, which is not expected to be
repeated in 2002. See "Results of Operations - 2001 Compared with 2000" above.

     We estimate our retail customer growth in 2002 to be 3.2%, which is slower
than the pace of growth in recent years, although still about three times the
national average. Our customer growth in 2001 was 3.7%. We expect the customer
growth rate to be weak in the first two quarters of 2002, then begin a rebound.
Our current estimate for customer growth in 2003 and 2004 is between 3.5% and
4.0% annually.

     The retail rate price decreases are described above in "Results of
Operations - Regulatory Agreements."

     The foregoing discussion of future expectations is forward-looking
information. Actual results may differ materially from expectations. See
"Forward-Looking Statements" below.

OTHER FACTORS AFFECTING OUR FINANCIAL OUTLOOK

     COMPETITION AND INDUSTRY RESTRUCTURING

     ELECTRIC COMPETITION (WHOLESALE)

     The FERC regulates rates for wholesale power sales and transmission
services. Pinnacle West's marketing and trading division sells in the wholesale
market our generation production output that is not needed for our native load
and, in doing so, competes with other utilities, power marketers, and
independent power producers. Wholesale market prices significantly fell during
2001 and remain low for the reasons discussed under "Financial Outlook" above.
We cannot predict whether these lower prices will continue, or whether changes
in various factors that affect demand and capacity, including regulatory
actions, will cause the market prices to rise during 2002 or thereafter.

     ELECTRIC COMPETITION (RETAIL)

     On September 21, 1999, the ACC approved Rules that provide a framework for
the introduction of retail electric competition in Arizona. A Maricopa County,
Arizona, Superior Court later found the Rules unlawful and unconstitutional;
however, the Rules remain in effect pending the outcome of appeals. See "Retail
Electric Competition Rules" in Note 3 for additional information about the Rules
and the outstanding legal challenges to the Rules.

     Although the Rules allow retail customers to have access to competitive
providers of energy and energy services, we are the "provider of last resort"
for standard-offer, full service customers

                                       33
<PAGE>
under rates that have been approved by the ACC. These rates are established
until July 1, 2004. The 1999 Settlement Agreement allows us to seek adjustment
of these rates in the event of emergency conditions or circumstances, such as
the inability to secure financing on reasonable terms, or material changes in
our cost of service for ACC-regulated services resulting from federal, tribal,
state or local laws, regulatory requirements, judicial decisions, actions or
orders. Energy prices in the western U.S. wholesale market vary and, during the
course of the last two years, have been volatile. At various times, prices in
the spot wholesale market have significantly exceeded the amount included in our
current retail rates. In the event of shortfalls due to unforeseen increases in
load demand or generation outages, we may need to purchase additional
supplemental power in the wholesale spot market. Unless we are able to obtain an
adjustment of our rates under the 1999 Settlement Agreement, there can be no
assurance that we would be able to fully recover the costs of this power.

     On September 23, 1999, the ACC approved a comprehensive 1999 Settlement
Agreement among us and various parties related to the implementation of retail
electric competition in Arizona. See "1999 Settlement Agreement" in Note 3 for
additional information about the 1999 Settlement Agreement, including the recent
resolution of legal challenges to the 1999 Settlement Agreement.

     Under the Rules, as modified by the 1999 Settlement Agreement, we are
required to transfer our competitive electric assets and services either to an
unaffiliated party or to a separate corporate affiliate no later than December
31, 2002. Consistent with that requirement, we have been addressing the legal
and regulatory requirements necessary to complete the transfer of our generation
assets to Pinnacle West Energy on or before that date. In anticipation of our
transfer of generation assets, Pinnacle West Energy has completed, and is in the
process of developing and planning, various generation expansion projects so
that we can reliably meet the energy requirements of our Arizona customers.

     Following the transfer of our fossil-fueled generation assets and the
receipt of certain regulatory approvals, Pinnacle West Energy expects to sell
its power at wholesale to Pinnacle West's marketing and trading division, which,
in turn, is expected to sell power to us and to non-affiliated power purchasers.
In a filing with the ACC on October 18, 2001, we requested the ACC to:

     *    grant us a partial variance from an ACC Rule that would obligate us to
          acquire all of our customers' standard-offer generation requirements
          from the competitive market (with at least 50% of those requirements
          coming from a "competitive bidding" process) starting in 2003; and

     *    approve as just and reasonable a long-term purchase power agreement
          between us and Pinnacle West.

     We requested these ACC actions to ensure ongoing reliable service to our
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve our load. See
"Proposed Rule Variance and Purchase Power Agreement" in Note 3 for additional
information about our October 2001 ACC filing.

     On February 8, 2002, the ACC's Chief ALJ issued a procedural order which
consolidated the ACC docket relating to our October 2001 filing with several
other pending ACC dockets, including a "generic" docket request by the ACC
Chairman to "determine if changed circumstances require the [ACC] to take
another look at restructuring in Arizona." Although the order consolidates
several dockets, it states that a hearing on the matter will commence on April
29, 2002. The order went on to state that, contrary to our position, the ALJ was
construing the October 2001 filing as a request by us to amend the 1999 ACC
order that approved the 1999 Settlement Agreement.

                                       34
<PAGE>
     On March 22, 2002, the ACC Staff issued a report to the ACC recommending
that the ACC address the following issues in the generic docket:

     *    The extent and manner of the ACC's involvement in monitoring market
          conditions and/or mitigating the development of market power for
          generation and transmission;

     *    The lack of guidance in the Rules regarding the mechanics of the
          "competitive bidding process" referenced above;

     *    The consideration of alternatives to the transfer of generation assets
          required by the Rules (the ACC Staff stated that such transfers would
          be "unwise" at the present time and recommended that "all transfer and
          separation of utilities' assets be stayed pending the completion of
          the generic docket");

     *    The consideration of transmission constraints that could impact the
          development of the wholesale power market;

     *    The reassessment of adjustor mechanisms for standard-offer rates in
          light of problems with the development of a wholesale power market;
          and

     *    The adequacy of customer "shopping credits" in the context of the
          development of a competitive retail market (a shopping credit is the
          cost a customer does not pay to a utility distribution company if the
          customer obtains generation from another party).

Although not a specific ACC Staff recommendation, the report was also critical
of certain aspects of the proposed purchase power agreement between the Company
and Pinnacle West.

     A modification to the Rules or the 1999 Settlement Agreement as a result of
the consolidated docket could, among other things, adversely affect our ability
to transfer our generation assets to Pinnacle West Energy by December 31, 2002.
We cannot predict the outcome of the consolidated docket or its effect on the
specific requests in our October 2001 filing, the existing Arizona electric
competition rules, or the 1999 Settlement Agreement.

     As a result of the foregoing matters, as well as energy market
developments, including those relating to California's failed deregulation
efforts and to Enron's recent bankruptcy filing, electric utility restructuring
is in a state of flux in the western United States, including Arizona, and
around the country.

     CALIFORNIA ENERGY MARKET ISSUES

     See Note 10 for information regarding California energy market issues.

     FACTORS AFFECTING OPERATING REVENUES

     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.

                                       35
<PAGE>
     In our regulated retail market area, we will provide electricity services
to standard-offer, full-service customers and to energy delivery customers who
have chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in our service territory averaged about 4% a year
for the three years 1999 through 2001; we currently expect customer growth to be
about 3.2% in 2002 and between 3.5% and 4.0% a year in 2003 and 2004. We
currently estimate that retail electricity sales in kilowatt-hours will grow
3.5% to 5.5% a year in 2002 through 2004, before the retail effects of weather
variations. The customer growth and sales growth referred to in this paragraph
apply to energy delivery customers. As industry restructuring evolves in the
regulated market area, we cannot predict the number of our standard-offer
customers that will switch to unbundled service. As previously noted, under the
1999 Settlement Agreement, we have annual retail electricity price reductions of
1.5% through July 1, 2003 (see Note 3).

     OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS

     Purchased power and fuel costs are impacted by our electricity sales
volumes, existing contracts for generation fuel and purchased power, our power
plant performance, prevailing market prices, new generating plants being placed
in service, and our hedging program for managing such costs. See "Generating
Fuel and Purchased Power-Natural Gas Supply" in Part I for additional
information on a pending dispute related to a natural gas-fired transportation
contract with El Paso Natural Gas Company.

     Operations and maintenance expenses are expected to be affected by sales
mix and volumes, power plant operations, inflation, outages and other factors.

     Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property and changes in regulatory
asset amortization. See Note 1 for the regulatory asset amortization that is
being recorded in 1999 through 2004 pursuant to the 1999 Settlement Agreement.
Also, see Note 1 regarding current depreciation rates.

     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 us was 9.32% for 2001 and 9.16%
for 2000. We expect property taxes to increase primarily due to our additions to
existing facilities.

     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 internally-generated cash flow.

     We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. 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.

     Our financial results may be affected by the application of SFAS No. 133.
See "Critical Accounting Policies" above and Note 16 for further information.

     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.

                                       36
<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.

     INTEREST RATE AND EQUITY RISK

     Our major financial market risk exposure is changing interest rates.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our nuclear decommissioning trust fund (see Note 11). Our
policy is to manage interest rates through the use of a combination of
fixed-rate and floating-rate debt. The nuclear decommissioning fund also has
risks associated with changing market values of equity investments. Nuclear
decommissioning costs are recovered in regulated electricity prices.

     The tables below present contractual balances of our long-term debt and
commercial paper at the expected maturity dates as well as the fair value of
those instruments on December 31, 2001 and 2000. The interest rates presented in
the tables below represent the weighted average interest rates for the years
ended December 31, 2001 and 2000.

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                    4.72%    $ 171,162                $      --       8.10%    $  125,451
2003                                    --                       --       6.18%           337
2004                                    --                       --       6.08%       205,185
2005                                    --                       --       7.59%       400,185
2006                                    --                       --       6.77%        83,880
Years thereafter                        --       2.60%      476,860       6.73%       787,894
                                 ---------                ---------                ----------
Total                            $ 171,162                $ 476,860                $1,602,932
                                 ---------                ---------                ----------
Fair value                       $ 171,162                $ 476,860                $1,621,937
                                 =========                =========                ==========
</TABLE>

                                       37
<PAGE>
Expected Maturity/Principal Repayment
December 31, 2000
(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>
2001                    6.64%    $  82,100       7.33%    $ 250,000       7.75%    $      266
2002                                    --                       --       8.13%       125,000
2003                                    --                       --       7.75%           443
2004                                    --                       --       6.17%       205,000
2005                                    --                       --       7.28%       400,000
Years thereafter                        --       4.06%      476,860       7.48%       605,598
                                 ---------                ---------                ----------
Total                            $  82,100                $ 726,860                $1,336,307
                                 ---------                ---------                ----------
Fair value                       $  82,100                $ 726,860                $1,393,251
                                 =========                =========                ==========
</TABLE>

     COMMODITY PRICE RISK

     We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ 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.

     In addition, subject to specified risk parameters established by the
Pinnacle West Board of Directors and monitored by Pinnacle West's ERMC, we
engage in trading activities intended to profit from market price movements. In
accordance with Emerging Issues Task Force (EITF) 98-10 "Accounting For
Contracts Involved in Energy Trading and Risk Management Activities", such
trading positions are marked-to-market. These trading activities are part of our
marketing and trading activities and are reflected in the marketing and trading
revenues and expenses.

     The following schedule shows the changes in mark-to-market of our trading
positions during the years ended December 31, 2001 and 2000 (dollars in
millions):

                                                             2001        2000
                                                           --------    --------
Mark-to-market of net trading positions
  at beginning of year                                     $     12    $     --
Prior period mark-to-market (gains)
  losses realized during the year                                 7          (2)
Change in mark-to-market gains for
  future period activities                                       85          14
Transfer of mark-to-market balance
  to Pinnacle West marketing and
  trading                                                      (104)         --
                                                           --------    --------
Mark-to-market of net trading positions
  at end of year                                           $     --    $     12
                                                           ========    ========

                                       38
<PAGE>
     As of December 31, 2001, a hypothetical adverse price movement of 10% in
the market price of our risk management and trading assets and liabilities that
would have decreased the fair market value of these contracts by approximately
$23 million, compared to a $28 million decrease that would have been realized as
of December 31, 2000. A hypothetical favorable price movement of 10% would have
increased the fair market value of these contracts by approximately $23 million,
compared to a $28 million increase that would have been realized as of December
31, 2000. These contracts are hedges of our forecasted purchases of natural gas.
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.

     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 this and all other counterparties. Despite the fact that
the great majority of our counterparties are rated as investment grade by the
credit rating agencies there is still a possibility that one or more of these
companies could default, resulting in a material impact on earnings for a given
period. Counterparties in the portfolio consist principally of major energy
companies, municipalities, and local distribution companies. We maintain credit
policies that we believe minimize overall credit risk to within acceptable
limits. Determination of the credit quality of our counterparties is based upon
a number of factors, including credit ratings and our evaluation of their
financial condition. In many contracts, we employ collateral requirements and
standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Credit reserves are established
representing our estimated credit losses on our overall exposure to
counterparties. See Note 1 for a discussion of our credit reserve policy.

FORWARD-LOOKING STATEMENTS

     The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements. 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 our October 2001 ACC filing; the outcome of
regulatory and legislative proceedings relating to the restructuring; state and
federal regulatory and legislative decisions and actions, including the price
mitigation plan adopted by the FERC in June 2001; regional economic and market
conditions, including the California energy situation and completion of
generation construction in the region, which could affect customer growth and
the cost of power supplies; the cost of debt and equity capital; weather
variations affecting local and regional customer energy usage; conservation
programs; power plant performance; our ability to compete successfully outside
traditional regulated markets (including the wholesale market); and
technological developments in the electric industry.

     These factors and the other matters discussed above may cause future
results to differ materially from historical results, or from results or
outcomes we currently expect or seek.

                      ITEM 7A. QUANTITATIVE AND QUALITATIVE
                          DISCLOSURES ABOUT MARKET RISK

     See "Market Risks" in Item 7 for a discussion of quantitative and
qualitative disclosures about market risk.

                                       39
<PAGE>
               ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                          INDEX TO FINANCIAL STATEMENTS

Report of Management.......................................................   41
Independent Auditors' Report...............................................   42
Statements of Income for 2001, 2000 and 1999...............................   43
Balance Sheets as of December 31, 2001 and 2000............................   44
Statements of Cash Flows for 2001, 2000 and 1999...........................   46
Statements of Changes in Common Stock Equity for 2001, 2000 and 1999.......   47
Notes to Financial Statements..............................................   48
Financial Statement Schedule for 2001, 2000 and 1999
  Schedule II - Reserve for 2001, 2000 and 1999............................   83

See Note 12 of Notes to Financial Statements for the selected quarterly
financial data required to be presented in this Item.

                                       40
<PAGE>
                              REPORT OF MANAGEMENT

     The responsibility for the integrity of our financial information rests
with management, which has prepared the accompanying financial statements and
related information. This information was prepared in accordance with generally
accepted accounting principles as appropriate in the circumstances, and based on
management's best estimates and judgments. These financial statements have been
audited by independent auditors and their report is included on the following
page.

     Management maintains and relies upon systems of internal control. A
limiting factor in all systems of internal control is that the cost of the
system should not exceed the benefits to be derived. Management believes that
our system provides the appropriate balance between such costs and benefits.

     Periodically the internal control system is reviewed by both our internal
auditors to test for compliance and our independent auditors in conjunction with
their audit of our financial statements. Reports issued by the internal auditors
are released to management, and such reports or summaries thereof are
transmitted to the Audit Committee of the Board of Directors and the independent
auditors on a timely basis. By letter dated February 8, 2002, to the Audit
Committee, our independent auditors confirmed that they are independent
accountants with respect to us within the meaning of the Securities Act and the
requirements of the Independence Standards Board.

     The Audit Committee, composed solely of outside directors, meets
periodically with the internal auditors and independent auditors (as well as
management) to review the work of each. The internal auditors and independent
auditors have free access to the Audit Committee, without management present, to
discuss the results of their audit work.

     Management believes that our systems, policies and procedures provide
reasonable assurance that operations are conducted in conformity with the law
and with management's commitment to a high standard of business conduct.

William J. Post                         Chris N. Froggatt

William J. Post                         Chris N. Froggatt
Chairman and                            Vice President and Controller
Chief Executive Officer

                                       41
<PAGE>
                          INDEPENDENT AUDITORS' REPORT

To the Stockholder of
Arizona Public Service Company
Phoenix, Arizona

     We have audited the accompanying balance sheets of Arizona Public Service
Company as of December 31, 2001 and 2000, and the related statements of income,
changes in common stock equity and cash flows for each of the three years in the
period ended December 31, 2001. Our audits also included the financial statement
schedule listed in the Index at Item 14. These financial statements and the
financial statement schedule are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements and
the financial statement schedule based on our audits.

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

     In our opinion, such financial statements present fairly, in all material
respects, the financial position of Arizona Public Service Company at December
31, 2001 and 2000, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 2001, in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedule, when considered in relation
to the basic financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.

     As discussed in Note 16 of the financial statements, in 2001 Arizona Public
Service Company changed its method of accounting for derivatives and hedging
activities in order to comply with the provisions of Statement of Financial
Accounting Standards No. 133.

DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP
Phoenix, Arizona
February 8, 2002 (March 22, 2002, as to Note 17)

                                       42
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                              STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                              -----------------------------------------
                                                 2001           2000           1999
                                              -----------    -----------    -----------
                                                        (DOLLARS IN THOUSANDS)
<S>                                           <C>            <C>            <C>
Electric Operating Revenues ...............   $ 3,310,792    $ 3,480,252    $ 2,292,798
                                              -----------    -----------    -----------
Purchased Power and Fuel Costs:
  Purchased power .........................     1,348,872      1,547,464        551,645
  Fuel for electric generation ............       391,771        331,274        241,671
                                              -----------    -----------    -----------
    Total .................................     1,740,643      1,878,738        793,316
                                              -----------    -----------    -----------
Operating Revenues less Purchased Power and
  Fuel Costs ..............................     1,570,149      1,601,514      1,499,482
                                              -----------    -----------    -----------
Other Operating Expenses:
  Operations and maintenance excluding
    purchased power and fuel expenses .....       465,561        430,092        437,125
  Depreciation and amortization ...........       420,893        425,479        416,331
  Income taxes (Note 4) ...................       183,640        199,977        165,629
  Other taxes .............................       101,077         99,730         96,579
                                              -----------    -----------    -----------
    Total .................................     1,171,171      1,155,278      1,115,664
                                              -----------    -----------    -----------

Operating Income ..........................       398,978        446,236        383,818
                                              -----------    -----------    -----------
Other Income (Deductions):
  Income taxes (Note 4) ...................           504          4,312         32,614
  Other -- net ............................          (583)       (10,857)       (11,757)
                                              -----------    -----------    -----------
    Total .................................           (79)        (6,545)        20,857
                                              -----------    -----------    -----------
Income Before Interest Deductions .........       398,899        439,691        404,675
                                              -----------    -----------    -----------
Interest Deductions:
  Interest on long-term debt ..............       126,118        134,431        132,676
  Interest on short-term borrowings .......         4,407          7,455          8,272
  Debt discount, premium and expense ......         2,650          2,105          2,084
  Capitalized interest ....................       (14,964)       (10,894)        (6,679)
                                              -----------    -----------    -----------
    Total .................................       118,211        133,097        136,353
                                              -----------    -----------    -----------
Income Before Extraordinary Charge and
  Cumulative Effect Adjustment ............       280,688        306,594        268,322
Extraordinary Charge - net of income taxes
  of $94,115 (Note 1) .....................            --             --       (139,885)
Cumulative Effect of Change in Accounting
  For Derivatives - net of income taxes
  of $9,892 ...............................       (15,201)            --             --
                                              -----------    -----------    -----------
Net Income ................................       265,487        306,594        128,437
Preferred Stock Dividend Requirements .....            --             --          1,016
                                              -----------    -----------    -----------
Earnings for Common Stock .................   $   265,487    $   306,594    $   127,421
                                              ===========    ===========    ===========
</TABLE>

See Notes to Financial Statements.

                                       43
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                                 BALANCE SHEETS
                                     ASSETS

<TABLE>
<CAPTION>
                                                                DECEMBER 31,
                                                         --------------------------
                                                            2001           2000
                                                         -----------    -----------
                                                           (DOLLARS IN THOUSANDS)
<S>                                                      <C>            <C>
Utility Plant (Notes 1, 8 and 9):
  Electric plant in service and held for future use ..   $ 8,105,106    $ 7,805,025
  Less accumulated depreciation and amortization .....     3,374,098      3,187,328
                                                         -----------    -----------
    Total ............................................     4,731,008      4,617,697
  Construction work in progress ......................       321,305        245,749
  Nuclear fuel, net of accumulated amortization of
    $56,836 and $61,836 ..............................        49,282         47,389
                                                         -----------    -----------
    Utility Plant -- net .............................     5,101,595      4,910,835
                                                         -----------    -----------
Investments and Other Assets
  Decommissioning trust accounts (Note 11) ...........       202,036        204,716
  Assets from risk management and trading activities -
    long-term (Note 16) ..............................         2,082         32,955
  Other assets .......................................        76,322         45,841
                                                         -----------    -----------
    Total Investments and Other Assets ...............       280,440        283,512
                                                         -----------    -----------
Current Assets:
  Cash and cash equivalents ..........................        16,821          2,609
  Accounts receivable:
    Service customers ................................       182,749        422,012
    Other ............................................       153,988         48,711
    Allowance for doubtful accounts ..................        (3,349)        (2,380)
  Accrued utility revenues ...........................        76,131         74,566
  Materials and supplies (at average cost) ...........        81,215         71,966
  Fossil fuel (at average cost) ......................        27,023         19,405
  Deferred income taxes (Note 4) .....................            --          5,793
  Assets from risk management and trading activities
    (Note 16) ........................................        10,097         17,506
  Other ..............................................        42,009         38,414
                                                         -----------    -----------
    Total Current Assets .............................       586,684        698,602
                                                         -----------    -----------
Deferred Debits:
  Regulatory assets (Notes 1 and 3) ..................       342,383        469,867
  Unamortized debt issue costs .......................        13,163         12,805
  Other ..............................................        42,789         37,928
                                                         -----------    -----------
    Total Deferred Debits ............................       398,335        520,600
                                                         -----------    -----------

Total Assets .........................................   $ 6,367,054    $ 6,413,549
                                                         ===========    ===========
</TABLE>

See Notes to Financial Statements.

                                       44
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                                 BALANCE SHEETS
                             LIABILITIES AND EQUITY

<TABLE>
<CAPTION>
                                                                     DECEMBER 31,
                                                              --------------------------
                                                                 2001           2000
                                                              -----------    -----------
                                                                (DOLLARS IN THOUSANDS)
<S>                                                           <C>            <C>
Capitalization:
  Common stock ............................................   $   178,162    $   178,162
  Additional paid - in capital ............................     1,246,804      1,246,804
  Retained earnings .......................................       790,289        694,802
  Accumulated other comprehensive loss ....................       (64,565)            --
                                                              -----------    -----------
    Common stock equity ...................................     2,150,690      2,119,768
  Long-term debt less current maturities (Note 6) .........     1,949,074      1,806,908
                                                              -----------    -----------
    Total Capitalization ..................................     4,099,764      3,926,676
                                                              -----------    -----------

Current Liabilities:
  Commercial paper (Note 5) ...............................       171,162         82,100
  Current maturities of long-term debt (Note 6) ...........       125,451        250,266
  Accounts payable ........................................        98,959        267,999
  Accrued taxes ...........................................       107,595        106,515
  Accrued interest ........................................        41,043         39,488
  Customer deposits .......................................        28,664         24,498
  Deferred income taxes (Note 4) ..........................         3,244             --
  Liabilities from risk management and trading activities
       (Note 16) ..........................................        21,840         37,179
  Other ...................................................       117,770        104,947
                                                              -----------    -----------
    Total Current Liabilities .............................       715,728        912,992
                                                              -----------    -----------

Deferred Credits and Other:
  Deferred income taxes (Note 4) ..........................     1,023,079      1,110,437
  Deferred investment tax credit (Note 4) .................         4,306          4,570
  Liabilities from risk management and trading activities -
    long term (Note 16) ...................................        95,159         14,711
  Unamortized gain -- sale of utility plant (Note 8) ......        64,060         68,636
  Customer advances for construction ......................        69,293         40,694
  Other ...................................................       295,665        334,833
                                                              -----------    -----------
    Total Deferred Credits and Other ......................     1,551,562      1,573,881
                                                              -----------    -----------

Commitments and Contingencies (Notes 3, 10, and 11)

Total Liabilities and Equity ..............................   $ 6,367,054    $ 6,413,549
                                                              ===========    ===========
</TABLE>

See Notes to Financial Statements.

                                       45
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                            STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                                       -----------------------------------
                                                         2001         2000         1999
                                                       ---------    ---------    ---------
                                                             (DOLLARS IN THOUSANDS)
<S>                                                    <C>          <C>          <C>
Cash Flows from Operations:
  Net income .......................................   $ 265,487    $ 306,594    $ 128,437
  Items not requiring cash:
    Depreciation and amortization ..................     420,893      425,479      416,331
    Nuclear fuel amortization ......................      28,362       30,083       31,371
    Deferred income taxes - net ....................     (26,252)     (65,457)     (56,127)
    Deferred investment tax credit - net ...........        (264)        (269)     (27,626)
    Mark-to-market gains - trading .................     (91,978)     (11,752)        (975)
    Mark-to-market gains - system ..................      (8,052)          --           --
    Extraordinary Charge - net of income taxes .....          --           --      139,885
    Cumulative effect of change in
      accounting - net of income taxes .............      15,201           --           --
  Changes in certain current assets and liabilities:
    Accounts receivable - net ......................     226,933     (232,493)      (8,363)
    Accrued utility revenues .......................      (1,565)      (1,647)      (5,179)
    Materials, supplies and fossil fuel ............     (16,867)         475       (8,794)
    Other current assets ...........................      (3,595)     (25,035)      (4,190)
    Accounts payable ...............................    (190,141)     101,558       22,992
    Accrued taxes ..................................       1,080       43,657        3,031
    Accrued interest ...............................       1,555        7,189        1,081
    Other current liabilities ......................      16,989      124,473        6,833
  Increase in regulatory assets ....................     (17,516)     (14,138)     (12,262)
  Other - net ......................................     (13,164)      34,954        1,514
                                                       ---------    ---------    ---------
    Net cash provided ..............................     607,106      723,671      627,959
                                                       ---------    ---------    ---------
Cash Flows from Investing:
  Capital expenditures .............................    (467,391)    (464,368)    (322,547)
  Capitalized interest .............................     (14,964)     (10,894)      (6,679)
  Other ............................................     (41,926)     (72,189)      (8,173)
                                                       ---------    ---------    ---------
    Net cash used ..................................    (524,281)    (547,451)    (337,399)
                                                       ---------    ---------    ---------
Cash Flows from Financing:
  Issuance of long-term debt .......................     396,072      300,000      392,952
  Short-term borrowings - net ......................      89,062       43,800     (140,530)
  Common equity infusion from parent ...............          --           --       50,000
  Dividends paid on common stock ...................    (170,000)    (170,000)    (170,000)
  Dividends paid on preferred stock ................          --           --       (1,393)
  Repayment of preferred stock .....................          --           --      (96,499)
  Repayment and reacquisition of long-term debt ....    (383,747)    (354,888)    (323,171)
                                                       ---------    ---------    ---------
    Net cash used ..................................     (68,613)    (181,088)    (288,641)
                                                       ---------    ---------    ---------
Net increase (decrease) in cash and cash equivalents      14,212       (4,868)       1,919
Cash and cash equivalents at beginning of year .....       2,609        7,477        5,558
                                                       ---------    ---------    ---------
Cash and cash equivalents at end of year ...........   $  16,821    $   2,609    $   7,477
                                                       =========    =========    =========
Supplemental disclosure of cash flow information:
Cash paid during the year for:
    Interest (excluding capitalized interest) ......   $ 114,094    $ 123,895    $ 132,995
    Income taxes ...................................   $ 212,989    $ 222,866    $ 189,002
</TABLE>

See Notes to Financial Statements.

                                       46
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                  STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
              For the Years Ended December 31, 1999, 2000 and 2001
                             (dollars in thousands)

<TABLE>
<CAPTION>
                                                                                             Accumulated
                                                                Additional                      Other
                                                   Preferred      Paid-in      Retained     Comprehensive
                                   Common Stock      Stock        Capital      Earnings     Income (Loss)     Total
                                    -----------   -----------   -----------   -----------    -----------    -----------
<S>                                 <C>           <C>           <C>           <C>            <C>            <C>
Balance at December 31, 1998        $   178,162   $    95,241   $ 1,195,625   $   601,968    $        --    $ 2,070,996

Net income                                                                        128,437                       128,437

Redemption of preferred stock                         (95,241)                                                  (95,241)
Preferred stock dividend
  requirements                                                                     (1,016)                       (1,016)
Dividends on common stock                                                        (170,000)                     (170,000)
Common equity infusion from parent                                   50,000                                      50,000
Other                                                                 1,179        (1,181)                           (2)
                                    -----------   -----------   -----------   -----------    -----------    -----------
Balance at December 31, 1999            178,162            --     1,246,804       558,208             --      1,983,174

Net income                                                                        306,594                       306,594

Dividends on common stock                                                        (170,000)                     (170,000)
                                    -----------   -----------   -----------   -----------    -----------    -----------
Balance at December 31, 2000            178,162            --     1,246,804       694,802             --      2,119,768
                                    -----------   -----------   -----------   -----------    -----------    -----------
Net income                                                                        265,487                       265,487
Minimum pension liability,
  net of $634 tax effect                                                                            (966)          (966)
Cumulative effect of
  change in accounting for
  derivatives, net of
  $47,404 tax effect                                                                              72,274         72,274
Unrealized loss on
  derivative instruments,
  net of $54,028 tax effect                                                                      (82,373)       (82,373)
Reclassification of net
  realized gain to income,
  net of $35,091 tax effect                                                                      (53,500)       (53,500)
                                    -----------   -----------   -----------   -----------    -----------    -----------
Comprehensive income
  (loss)                                                                          265,487        (64,565)       200,922
                                    -----------   -----------   -----------   -----------    -----------    -----------
Dividends on common stock                                                        (170,000)                     (170,000)
                                    -----------   -----------   -----------   -----------    -----------    -----------
Balance at December 31, 2001        $   178,162   $        --   $ 1,246,804   $   790,289    $   (64,565)   $ 2,150,690
                                    ===========   ===========   ===========   ===========    ===========    ===========
</TABLE>

See Notes to Financial Statements.

                                       47
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS

     We are Arizona's largest electric utility. We are a wholly-owned subsidiary
of Pinnacle West Capital Corporation. We provide 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
metropolitan Phoenix area. We also generate and, through Pinnacle West's
marketing and trading division, sell and deliver electricity to wholesale
customers in the western United States.

     During 2001, we transferred most of our marketing and trading activities to
Pinnacle West, which approximated $219 million in assets and $149 million in
liabilities. From time to time, we enter into transactions with Pinnacle West or
Pinnacle West's subsidiaries. The following table summarizes the amounts
included in the income statements and balance sheets related to transactions
with affiliated companies (dollars in millions):

                                                        For the year ended
                                                            December 31,
                                                  ------------------------------
                                                   2001        2000        1999
                                                  ------      ------      ------
Electric operating revenues:
  Pinnacle West - marketing and trading           $   50      $   --      $   --
  APSES                                               15          26          --
                                                  ------      ------      ------
Total                                             $   65      $   26      $   --
                                                  ======      ======      ======

Purchased power and fuel costs:
  Pinnacle West - marketing and trading           $   50      $   --      $   --
  Pinnacle West Energy                                14          --          --
                                                  ------      ------      ------
Total                                             $   64      $   --      $   --
                                                  ======      ======      ======

                                                  As of December 31,
                                                  ------------------
                                                   2001        2000
                                                  ------      ------
Accounts receivable - other:
  Pinnacle West - marketing and trading           $   76      $   10
  Pinnacle West                                       24          14
  APSES                                               13           1
  Pinnacle West Energy                                 2          --
                                                  ------      ------
Total                                             $  115      $   25
                                                  ======      ======

Accounts payable:
  Pinnacle West - marketing and trading           $   21      $    1
  Pinnacle West Energy                                 2           1
                                                  ------      ------
Total                                             $   23      $    2
                                                  ======      ======

                                       48
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

     Electric revenues include sales of electricity to affiliated companies at
contract prices. Purchased power includes purchases of electricity from
affiliated companies at contract prices. Intercompany receivables primarily
include the amounts related to the transfer of marketing and trading activities
discussed above and intercompany sales of electricity. Intercompany payables
primarily include amounts related to the purchase of electricity.

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 and 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 current year presentation.

DERIVATIVE INSTRUMENTS

     We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ 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.

     In addition, subject to specified risk parameters established by the
Pinnacle West Board of Directors and monitored by Pinnacle West's ERMC, we
engage in trading activities intended to profit from market price movements. If
a contract was entered into for trading purposes, we account for it in
accordance with EITF 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities." EITF 98-10 requires energy trading contracts to
be measured at fair value as of the balance sheet date with unrealized gains and
losses included in earnings on a current basis (the mark-to-market method). See
"Mark-to-Market Method" below and Note 16 for further information about our
trading contracts.

     We examine contracts at inception to determine the appropriate accounting
treatment. If a contract is not considered energy trading we must determine if
it is a derivative as defined in SFAS No. 133 (see Note 16 for further
information on SFAS No. 133). 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 using accrual accounting (this means that costs and revenues are
recorded when physical delivery occurs). 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. 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
(mark-to-market). If it does qualify for hedge accounting, changes in the fair
value are recognized as either an asset, as a liability or in stockholder's

                                       49
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

equity (as a component of accumulated other comprehensive income) depending on
the nature of the hedge.

     Gains and losses related to derivatives that qualify as cash flow hedges of
expected transactions are recognized in revenue or fuel and purchased power
expense as an offset to the related item being hedged when the underlying hedged
physical transaction impacts earnings (deferral method). See Note 16 for further
discussion on derivative accounting.

MARK-TO-MARKET METHOD

     Under mark-to-market accounting the purchase or sale of energy commodities
are reflected at fair market value, net of reserves, with resulting unrealized
gains and losses recorded as assets and liabilities from risk management and
trading activities in the balance sheets.

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

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

     For options, long-term contracts and other contracts where price quotes are
not available, we use models and other valuation methods. For illiquid or
unquoted market locations, we consider the historical relationship to
readily-available market quotations. The valuation models we employ utilize spot
prices, forward prices, historical market data and other factors to forecast
future prices.

     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 reserves for a number of risks associated with the
valuation of future commitments. These include reserves for liquidity and credit
risks based on the financial condition of counterparties. The liquidity reserve
represents the cost that would be incurred if all unmatched positions were
closed-out or hedged. As we mark positions to a mid-market value this reserve
adjusts the mid-market valuation to the bid or offer, after taking into
consideration offsetting positions, to reflect the true cash flow that would be
realized upon exiting the net position.

     A credit reserve 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.

                                       50
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

     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. However,
essentially all of our marketing and trading activities are structured
activities. This means our portfolio of forward sales positions is substantially
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 Pinnacle West ERMC.

REGULATORY ACCOUNTING

     We are regulated by the ACC and the FERC. The accompanying financial
statements reflect the rate-making policies of these commissions. For regulated
operations, we prepare our financial statements in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS No. 71
requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements.

     During 1997, the EITF of the FASB issued EITF 97-4. EITF 97-4 requires that
SFAS No. 71 be discontinued no later than when 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, which could result in write-downs or
write-offs of physical and/or regulatory assets. Additionally, the EITF
determined that regulatory assets should not be written off if they are to be
recovered from a portion of the entity which continues to apply SFAS No. 71.

     The 1999 Settlement Agreement was approved by the ACC in September 1999
(see Note 3 for a discussion of the agreement). Consequently, we have
discontinued the application of SFAS No. 71 for our generation operations. As a
result, we tested the generation assets for impairment and determined that 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 income statement during the third quarter of
1999. Prior to the 1999 Settlement Agreement, under the 1996 regulatory
agreement (see Note 3), the ACC accelerated the amortization of substantially
all of our 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):

                                                            1/1 - 6/30
1999         2000         2001         2002        2003        2004        Total
----         ----         ----         ----        ----        ----        -----
$164         $158         $145         $115         $86         $18         $686

Regulatory assets are reported as deferred debits on the balance sheets. As of
December 31, 2001 and 2000, they are comprised of the following (dollars in
millions):

                                       51
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

                                                                December 31,
                                                             ------------------
                                                              2001       2000
                                                             -------    -------
Remaining balance recoverable under the 1999 Settlement
  Agreement (a)                                              $   219    $   364
Spent fuel storage (Note 10)                                      43         40
Electric industry restructuring transition costs (Note 3)         34         24
Other                                                             46         42
                                                             -------    -------
  Total regulatory assets                                    $   342    $   470
                                                             =======    =======

----------
(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).

Regulatory liabilities are included in deferred credits on the balance sheets
and as of December 31, 2001 and 2000 are comprised of the following (dollars in
millions):

                                                                December 31,
                                                             ------------------
                                                              2001       2000
                                                             -------    -------
Deferred gains on utility property                           $    20    $    20
Other                                                              7          8
                                                             -------    -------
  Total regulatory liabilities                               $    27    $    28
                                                             =======    =======

     The balance sheets include the amounts listed below for generation assets
not subject to SFAS No. 71 as of December 31, 2001 and 2000 (dollars in
millions):

                                                                December 31,
                                                             ------------------
                                                              2001       2000
                                                             -------    -------
Electric plant in service and held for future use .......    $ 3,878    $ 3,854
Accumulated depreciation and amortization................     (1,990)    (1,902)
Construction work in progress............................        119         86
Nuclear fuel, net of amortization........................         49         47

     As a result of our 1999 Settlement Agreement, we plan to move our
generation assets and activities to Pinnacle West Energy no later than December
31, 2002. Following the transfer, our financial statements would no longer
include generation assets and activities. Our preliminary estimate of the net
assets (the generation assets described above and the related liabilities) that
would be transferred is approximately $850 million based on book values at
December 31, 2001. We have requested that the ACC approve a purchase power
agreement and a proposed rule variance related to our power procurement after
the transfer. This request is currently pending ACC consideration (see Note 3).
The specific impacts of the generation transfer on our revenues and expenses are
not yet determinable pending the outcome of the ACC proceedings. In addition, as
of December 31, 2001, we completed the transition of our marketing and trading
activities to the parent. In 2001, we recorded the following pretax amounts
related to marketing and trading activities: $749 million of electric revenues
and $517 million of purchased power and fuel costs.

                                       52
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

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 our
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 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. For
the years 1999 through 2001 the rates, as prescribed by our regulators, ranged
from a low of 1.49% to a high of 20%. The weighted-average rate was 3.40% for
2001, 3.40% for 2000, and 3.34% for 1999. We depreciate non-utility property and
equipment over the estimated useful lives of the related assets, ranging from 3
to 30 years. We expense the costs of plant outages, major maintenance and
routine maintenance as incurred.

CAPITALIZED INTEREST

     Capitalized interest represents the cost of debt funds used to finance
construction of utility plants. 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 6.26% for 2001, 6.62% for 2000, and 6.65% for 1999.

REVENUES

     We record electric operating revenues on the accrual basis, which includes
estimated amounts for service rendered but unbilled at the end of each
accounting period. We exclude sales taxes on electric revenues from both revenue
and taxes other than income taxes. Electric revenues are recorded gross on the
statements of income, with the exception of unrealized gains and losses recorded
under the mark-to-market method (see discussion above). Unrealized gains and
losses are recorded net in electric revenues. When the gain or loss is realized,
the gross amount is recorded as electric revenue and fuel or purchased power
expense in the statements of income.

                                       53
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

CASH AND CASH EQUIVALENTS

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

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 statements of income.

NUCLEAR FUEL

     We charge nuclear fuel to fuel expense by using the unit-of-production
method. The unit-of-production method is an amortization method that is based on
actual physical usage. We divide the cost of the fuel by the estimated number of
thermal units that we expect to produce with that fuel. We then multiply that
rate by the number of thermal units that we produce within the current period.
This calculation determines the current period nuclear fuel expense.

     We also charge nuclear fuel expense for the permanent disposal of spent
nuclear fuel. The United States Department of Energy (DOE) is responsible for
the permanent disposal of spent nuclear fuel, and it charges us $0.001 per kWh
of nuclear generation. See Note 10 for information about spent nuclear fuel
disposal and Note 11 for information on nuclear decommissioning costs.

REACQUIRED DEBT COSTS

     For debt related to the regulated portion of our business, we amortize
those gains and losses incurred upon early retirement over the remaining life of
the debt. In accordance with the 1999 Settlement Agreement, we are continuing to
accelerate reacquired debt costs over an eight-year period that will end June
30, 2004. The accelerated portion of the regulatory asset amortization is
included in depreciation and amortization expense in the statements of income.

2.   ACCOUNTING MATTERS

     In July 2001, the FASB issued 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." This standard is effective for the year beginning January
1, 2002. We have no goodwill recorded in our balance sheets. The impacts of this
new standard are not material to our financial statements.

     In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations." The standard requires the estimated present value of
the cost of decommissioning and certain other removal costs to be recorded as a
liability, along with an offsetting plant asset, when

                                       54
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

a decommissioning or other removal obligation is incurred. We are currently
evaluating the impacts of the new standard, which is effective for the year
beginning January 1, 2003.

     In October 2001, the FASB issued 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. SFAS No. 144 is effective for the year
beginning January 1, 2002. This standard does 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 (PP&E) construction, require that PP&E 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. The AICPA plans to issue the final SOP in the fourth quarter of 2002.

     In 1986, we entered into agreements with three separate special purpose
entity (SPE) lessors in order to sell and lease back interests in Palo Verde
Unit 2 (see Note 8). The leases are accounted for as operating leases in
accordance with GAAP. In February 2002, the FASB discussed issues related to
special purpose entities. It is expected that FASB will issue additional
guidance on accounting for SPEs later this year. As a result of future FASB
actions, we may be required to consolidate the SPEs in our financial statements.
If consolidation is required, the assets and liabilities of the SPEs that relate
to the sale-leaseback transactions would be reflected on our balance sheets. The
SPE debt that is not reflected on our balance sheets is approximately $300
million at December 31, 2001. Rating agencies have already considered this debt
when evaluating our credit ratings.

3.   REGULATORY MATTERS

ELECTRIC INDUSTRY RESTRUCTURING

STATE

     1999 SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive
1999 Settlement Agreement with various parties, including representatives of
major consumer groups, related to the implementation of retail electric
competition. On September 23, 1999, the ACC voted to approve the 1999 Settlement
Agreement, with some modifications.

     On December 13, 1999, two parties filed lawsuits challenging the ACC's
approval of the 1999 Settlement Agreement. Each party bringing the lawsuits
appealed the ACC's order approving the 1999 Settlement Agreement directly to the
Arizona Court of Appeals, as provided by Arizona law. In one of the appeals, on
December 26, 2000, the Arizona Court of Appeals affirmed the ACC's approval of
the 1999 Settlement Agreement. This decision was not appealed and has become
final. In the other appeal, on April 5, 2001, the Arizona Court of Appeals again
affirmed the ACC's approval of the 1999 Settlement Agreement. The Arizona
Consumers Council, which filed that appeal, petitioned the Arizona Supreme Court
for review of the Court of Appeals' decision. On

                                       55
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

October 5, 2001, the Arizona Supreme Court agreed to hear the appeal on the
single issue of whether the ACC could itself become a party to the 1999
Settlement Agreement by virtue of its approval of the 1999 Settlement Agreement.
On December 14, 2001, the Arizona Supreme Court vacated its own October 5, 2001
order accepting jurisdiction and decided to dismiss the appeal. As a result, the
judicial challenges to the 1999 Settlement Agreement have terminated. Consistent
with our obligations under the 1999 Settlement Agreement, on January 7, 2002, we
and the ACC filed in Maricopa County, Arizona Superior Court a stipulation to
dismiss all of our litigation pending against the ACC. On January 15, 2002, a
Maricopa County Superior Court judge issued an order dismissing such litigation.

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

     *    We have 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% beginning July 1, 1999 through
          July 1, 2003, for a total of 7.5%. The first reduction of
          approximately $24 million ($14 million after income taxes) included
          the July 1, 1999 retail price decrease of approximately $11 million
          ($7 million after income taxes) related to the 1996 regulatory
          agreement. See "1996 Regulatory Agreement" below. Based on the price
          reductions authorized in the 1999 Settlement Agreement, there were
          also retail price decreases of approximately $28 million ($17 million
          after taxes), or 1.5%, effective July 1, 2000, and approximately $27
          million ($16 million after taxes), or 1.5%, effective July 1, 2001.
          For customers having loads three MW or greater, standard-offer rates
          will be reduced in varying annual increments that total 5% in the
          years 1999 through 2002.

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

     *    There 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
          limited circumstances. Neither the ACC nor we 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, or material changes in
          our cost of service for ACC-regulated services resulting from federal,
          tribal, state or local laws, regulatory requirements, judicial
          decisions, actions or orders.

     *    We will be permitted to defer for later recovery prudent and
          reasonable costs of complying with the ACC electric competition 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.

                                       56
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

     *    Our distribution system opened for retail access effective September
          24, 1999. Customers were eligible for retail access in accordance with
          the phase-in adopted by the ACC under the electric competition rules
          (see "Retail Electric Competition Rules" below), including an
          additional 140 MW being made available to eligible non-residential
          customers. We opened our distribution system to retail access for all
          customers on January 1, 2001.

     *    Prior to the 1999 Settlement Agreement, we were recovering
          substantially all of our regulatory assets through July 1, 2004,
          pursuant to the 1996 regulatory agreement. In addition, the 1999
          Settlement Agreement states that we have demonstrated that our
          allowable stranded costs, after mitigation and exclusive of regulatory
          assets, are at least $533 million net present value. We will not be
          allowed to recover $183 million net present value of the above
          amounts. The 1999 Settlement Agreement provides that we will have the
          opportunity to recover $350 million net present value 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.

     *    We will form, or cause to be formed, a separate corporate affiliate or
          affiliates and transfer to such affiliate(s) our competitive electric
          assets and services at book value as of the date of transfer, and will
          complete the transfer no later than December 31, 2002. Accordingly, we
          plan to complete the move of such assets and services to the parent
          company or to Pinnacle West Energy by the end of 2002, as required,
          although the ACC's recent establishment of a "generic" docket to
          consider electric industry restructuring in Arizona and the
          consolidation of that docket with our request for approval of a PPA
          between Pinnacle West and us could affect our ability to transfer
          assets to Pinnacle West Energy. We will be allowed to defer and later
          collect, beginning July 1, 2004, sixty-seven percent of our costs to
          accomplish the required transfer of generation assets to an affiliate.

     As discussed in Note 1 above, we have discontinued the application of SFAS
No. 71 for our generation operations.

     PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. As authorized by the
1999 Settlement Agreement, we intend to move substantially all of our generation
assets to Pinnacle West Energy no later than December 31, 2002. Commencing upon
the transfer of the fossil-fueled generating assets and the receipt of certain
regulatory approvals, Pinnacle West Energy expects to sell its power at
wholesale to Pinnacle West's marketing and trading division, which, in turn, is
expected to sell power to us and to non-affiliated power purchasers. In a filing
with the ACC on October 18, 2001, we requested the ACC to:

     *    grant us a partial variance from an ACC rule that would obligate us to
          acquire all of our customers' standard-offer, full-service generation
          requirements from the competitive market (with at least 50% of those
          requirements coming from a "competitive bidding" process) starting in
          2003; and

                                       57
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

     *    approve as just and reasonable a long-term purchase power agreement
          (PPA) between us and Pinnacle West.

We have requested these ACC actions to ensure ongoing reliable service to our
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve our load. The
following are the major provisions of the PPA:

     *    The PPA would run through 2015, with three optional five-year renewal
          terms, which renewals would occur automatically unless notice is given
          by either us or Pinnacle West.

     *    The PPA would provide for all of our anticipated standard-offer
          generation needs, including any necessary reserves, except for (a)
          those provided by us through renewable resources or other generation
          assets retained by us; (b) amounts that we are obligated by law to
          purchase from "qualified facilities" and other forms of distributed
          generation; and (c) any purchased power agreements that we cannot
          transfer to Pinnacle West Energy.

     *    Pinnacle West would assume contractual responsibility for reliability
          and would supplement any potential shortfall even after full
          utilization of Pinnacle West Energy's dedicated generating resources.

     *    Pinnacle West would supply us standard-offer requirements through a
          combination of (a) our generation assets transferred to Pinnacle West
          Energy; (b) certain of Pinnacle West Energy's new Arizona generation
          projects to be constructed during the 2001-2004 period to reliably
          serve our load requirements; (c) power procured by Pinnacle West under
          certain "dedicated contracts"; and (d) power procured on the open
          market, including a competitively-bid component described below.

     *    Beginning in 2003, Pinnacle West would acquire 270 MW of our
          standard-offer requirements on the open market through a competitive
          bidding process. This competitive bid obligation would be increased by
          an additional 270 MW each year through 2008 (representing
          approximately 23% of estimated 2008 peak load).

     *    Pinnacle West would charge us based on (a) a combination of fixed and
          variable price components for the Pinnacle West Energy assets, subject
          to periodic adjustment, and (b) a pass-through of Pinnacle West's
          costs to procure power from the remaining sources.

     *    The PPA would take effect on the latest of the following events: (a)
          transfer of non-nuclear generating assets from us to Pinnacle West
          Energy; (b) ACC approval of the rule variance and the PPA; and (c) the
          FERC's acceptance of the PPA and the companion agreement between
          Pinnacle West and Pinnacle West Energy.

     We are required to transfer our competitive electric assets and services to
one or more corporate affiliates on or before December 31, 2002. Consistent with
that requirement, we have been

                                       58
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

addressing the legal and regulatory requirements necessary to complete the
transfer of our generation assets to Pinnacle West Energy on or before that
date. In anticipation of our transfer of generation assets, Pinnacle West Energy
has completed, and is in the process of developing and planning, various
generation expansion projects so that we can reliably meet the energy
requirements of our Arizona customers. See Note 1 for information relating to
our pending transfer of generation assets and associated liabilities to Pinnacle
West Energy.

     By letter dated January 14, 2002, the Chairman of the ACC stated that "the
[ACC's] Electric Competition Rules, along with the Settlement Agreements
approved for us and [Tucson Electric Company], establish the framework for the
transition to a retail generation competitive market." The ACC Chairman then
recommended that the ACC establish a new "generic" docket to "determine if
changed circumstances require the [ACC] to take another look at electric
restructuring in Arizona." Matters that would be addressed by the ACC in the new
docket would include:

     *    whether the ACC should continue implementation of the retail electric
          competition Rules adopted by the ACC in 1999 in their current form or
          with modifications;

     *    whether the ACC should "slow the pace of the implementation of the
          [Rules] to provide an opportunity to consider the extent to which
          [Rule] modification and variance is in the public interest, including
          changing the direction to retail electric competition"; and

     *    whether the ACC should "step back from electric industry restructuring
          until the [ACC] is convinced that there exists a viable competitive
          wholesale electric market to support retail electric competition in
          Arizona."

     On January 22, 2002 the ACC's Chief ALJ issued a procedural order by which
a generic docket was opened. On February 8, 2002, the ACC's ALJ issued a
procedural order which consolidated the ACC docket relating to our October 2001
filing with several other pending ACC dockets, including the generic docket.
Although the order consolidates several dockets, it states that a hearing on our
matter will commence on April 29, 2002. The order went on to state that,
contrary to our position, the ALJ was construing the October 2001 filing as a
request by us to amend the ACC order that approved the 1999 Settlement
Agreement.

     On March 22, 2002, the ACC Staff issued a report to the ACC recommending
that the ACC address the following issues in the generic docket:

     *    The extent and manner of the ACC's involvement in monitoring market
          conditions and/or mitigating the development of market power for
          generation and transmission;

     *    The lack of guidance in the Rules regarding the mechanics of the
          "competitive bidding process" referenced above;

     *    The consideration of alternatives to the transfer of generation assets
          required by the Rules (the ACC Staff stated that such transfers would
          be "unwise" at the present time and

                                       59
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

          recommended that "all transfer and separation of utilities' assets be
          stayed pending the completion of the generic docket");

     *    The consideration of transmission constraints that could impact the
          development of the wholesale power market;

     *    The reassessment of adjustor mechanisms for standard-offer rates in
          light of problems with the development of a wholesale power market;
          and

     *    The adequacy of customer "shopping credits" in the context of the
          development of a competitive retail market (a shopping credit is the
          cost a customer does not pay to a utility distribution company if the
          customer obtains generation from another party).

Although not a specific ACC Staff recommendation, the report was also critical
of certain aspects of the proposed purchase power agreement between the Company
and Pinnacle West.

     A modification to the competition Rules or the 1999 Settlement Agreement
could, among other things, adversely affect our ability to transfer our
generation assets to Pinnacle West Energy by December 31, 2002. We cannot
predict the outcome of the consolidated docket or its effect on the specific
requests in our October 2001 filing, the existing Arizona electric competition
rules, or the 1999 Settlement Agreement.

     RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve Rules that provide a framework for the introduction of retail electric
competition in Arizona. Under the 1999 Settlement Agreement, the Rules are to be
interpreted and applied, to the greatest extent possible, in a manner consistent
with the 1999 Settlement Agreement. If the two cannot be reconciled, we must
seek, and the other parties to the 1999 Settlement Agreement must support, a
waiver of the Rules in favor of the 1999 Settlement Agreement. On December 8,
1999, we filed a lawsuit to protect our legal rights regarding the Rules. This
lawsuit has been dismissed.

     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 to
operate in Arizona. We do not believe the ruling affects the 1999 Settlement
Agreement. The 1999 Settlement Agreement was not at issue in the consolidated
cases before the judge. Further, the ACC made findings related to the fair value
of our property in the order approving the 1999 Settlement Agreement. The ACC
and other parties aligned with the ACC have 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. 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 case has
been appealed to the Arizona Supreme Court, where a decision is pending.

                                       60
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

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

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

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

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

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

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

     *    Absent an ACC waiver, prior to January 1, 2001, each affected utility
          (except certain electric cooperatives) must transfer all competitive
          electric assets and services either to an unaffiliated party or to a
          separate corporate affiliate. Under the 1999 Settlement Agreement, we
          received a waiver to allow transfer of our competitive electric assets
          and services to affiliates no later than December 31, 2002. We plan to
          complete the move of such assets by the end of 2002, as required,
          although the ACC's recent establishment of a "generic" docket to
          consider electric industry restructuring in Arizona and the
          consolidation of that docket with our request for approval of a PPA
          between Pinnacle West and us could affect our ability to transfer
          assets to Pinnacle West Energy (see "Proposed Rule Variance and
          Purchase Power Agreement" above).

     PROVIDER OF LAST RESORT OBLIGATION. Although the Rules allow retail
customers to have access to competitive providers of energy and energy services
(see "Retail Electric Competition Rules" below), we are 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 July 1, 2004. The 1999
Settlement Agreement allows us to seek adjustment of these rates in the event of
emergency conditions or circumstances, such as the inability to secure financing
on reasonable terms, or material changes in our cost of service for
ACC-regulated services resulting from federal, tribal, state or local laws,
regulatory requirements, judicial decisions, actions or orders. Energy prices in
the western wholesale market vary and, during the course of the last two years,
have been volatile. At various times, prices in the spot wholesale market have
significantly exceeded the amount included in our current retail rates. In the
event of shortfalls due to unforeseen increases in load demand or generation
outages, we may need to purchase additional supplemental power in the wholesale
spot market. Unless we are able to obtain an adjustment of our rates under the
emergency provisions of the 1999 Settlement Agreement, there can be no assurance
that we would be able to fully recover the costs of this power.

                                       61
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

     1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and us. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases
(approximate) as follows (dollars in millions):

     Annual Electric              Percentage
     Revenue Decrease              Decrease                Effective Date
     ----------------              --------                --------------
           $49                        3.4%                 July 1, 1996
           $18                        1.2%                 July 1, 1997
           $17                        1.1%                 July 1, 1998
           $11                        0.7%                 July 1, 1999 (a)

----------
(a)  Included in the first rate reduction under the 1999 Settlement Agreement
     (see above).

     The regulatory agreement also required that Pinnacle West infuse $200
million of common equity into us in annual payments of $50 million from 1996
through 1999. All of these equity infusions were made by December 31, 1999.

     LEGISLATION. In May 1998, a law was enacted to facilitate implementation of
retail electric competition in Arizona. The law includes the following major
provisions:

     *    Arizona's largest government-operated electric utility (Salt River
          Project) and, at their option, smaller municipal electric systems must
          (i) make at least 20% of their 1995 retail peak demand available to
          electric service providers by December 31, 1998 and for all retail
          customers by December 31, 2000; (ii) decrease rates by at least 10%
          over a ten-year period beginning as early as January 1, 1991; (iii)
          implement procedures and public processes comparable to those already
          applicable to public service corporations for establishing the terms,
          conditions, and pricing of electric services as well as certain other
          decisions affecting retail electric competition;

     *    describes the factors which form the basis of consideration by Salt
          River Project in determining stranded costs; and

     *    metering and meter reading services must be provided on a competitive
          basis during the first two years of competition only for customers
          having demands in excess of one MW (and that are eligible for
          competitive generation services), and thereafter for all customers
          receiving competitive electric generation.

GENERAL

     We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. 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.

                                       62
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

FEDERAL

     In June 2001, 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 plan remains in effect until September 30, 2002. We cannot
accurately predict the overall financial impact of the plan on the various
aspects of our business, including our wholesale and purchased power activities.

4.   INCOME TAXES

INCOME TAXES

     We are included in Pinnacle West's consolidated tax return. However, when
Pinnacle West allocates income taxes to us, it does so based on our taxable
income or loss alone. Because of a 1994 rate settlement agreement, we
accelerated amortization of substantially all of our ITCs over a five-year
period (1995-1999).

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

     We have recorded a regulatory asset related to income taxes on our balance
sheets in accordance with SFAS No. 71. This regulatory asset is for certain
temporary differences, primarily the allowance for equity funds used during
construction. We amortize this amount as the differences reverse. In accordance
with the 1999 Settlement Agreement, we are continuing to accelerate our
amortization of the regulatory asset for income taxes over an eight-year period
that will end June 30, 2004 (see Note 1). We are including this accelerated
amortization in depreciation and amortization expense on the Statements of
Income. The components of income tax expense for income before extraordinary
charge and cumulative effect adjustment are (dollars in thousands):

                                                 Year Ended December 31,
                                          -------------------------------------
                                            2001          2000          1999
                                          ---------     ---------     ---------
Current
  Federal                                 $ 174,251     $ 211,139     $ 175,227
  State                                      35,401        50,252        41,541
                                          ---------     ---------     ---------
Total current                               209,652       261,391       216,768

Deferred                                    (26,252)      (65,457)      (56,127)
ITC amortization                               (264)         (269)      (27,626)
                                          ---------     ---------     ---------
Total expense                             $ 183,136     $ 195,665     $ 133,015
                                          =========     =========     =========

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

                                       63
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

                                                 Year Ended December 31,
                                          -------------------------------------
                                            2001          2000          1999
                                          ---------     ---------     ---------
Federal income tax expense at 35%
  statutory rate                          $ 162,338     $ 175,791     $ 140,444
Increases (reductions) in tax expense
  resulting from:
  ITC amortization                             (264)         (269)      (27,626)
  State income tax net of federal
    income tax benefit                       20,563        20,007        20,699
  Other                                         499           136          (502)
                                          ---------     ---------     ---------
Income tax expense                        $ 183,136     $ 195,665     $ 133,015
                                          =========     =========     =========

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

                                                             December 31,
                                                       -------------------------
                                                          2001           2000
                                                       ----------     ----------
DEFERRED TAX ASSETS
  Deferred gain on Palo Verde Unit 2 sale/leaseback    $   25,374     $   27,056
  Risk management and trading activities                   46,343         15,002
  Other                                                   111,318        126,909
                                                       ----------     ----------
Total deferred tax assets                                 183,035        168,967
                                                       ----------     ----------
DEFERRED TAX LIABILITIES
  Plant-related                                         1,069,207      1,081,637
  Regulatory asset for income taxes                       121,757        172,082
  Risk management and trading activities                   18,394         19,892
                                                       ----------     ----------
Total deferred tax liabilities                          1,209,358      1,273,611
                                                       ----------     ----------
Accumulated deferred income taxes - net                $1,026,323     $1,104,644
                                                       ==========     ==========

5.   LINES OF CREDIT

     We had committed lines of credit with various banks of $250 million at
December 31, 2001 and 2000, which were available either to support the issuance
of commercial paper or to be used for bank borrowings. The commitment fees at
December 31, 2001 and 2000 for these lines of credit were 0.09% per annum. We
had no bank borrowings outstanding under these lines of credit at December 31,
2001 and 2000.

     Our commercial paper borrowings outstanding were $171 million at December
31, 2001 and $82 million at December 31, 2000. The weighted average interest
rate on commercial paper borrowings was 4.72% for the year ended December 31,
2001 and 6.64% for the year ended December 31, 2000. By Arizona statute, our
short-term borrowings cannot exceed 7% of our total capitalization unless
approved by the ACC.

                                       64
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

6.   LONG-TERM DEBT

     Borrowings under our mortgage bond indenture are secured by substantially
all utility plant. We also have unsecured debt. The following table presents the
components of long-term debt outstanding at December 31, 2001 and 2000 (dollars
in thousands):

                                                             December 31,
                               Maturity     Interest    -----------------------
                               Dates (a)      Rates        2001         2000
                               ---------    --------    ----------   ----------

First mortgage bonds              2002        8.125%    $  125,000   $  125,000
                                  2004        6.625%        80,000       80,000
                                  2021        9.5%              --       45,140
                                  2021        9.0%              --       72,370
                                  2023        7.25%         54,150       70,650
                                  2024        8.75%        121,668      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                                                   (5,266)      (5,993)
Pollution control bonds        2024-2034   Adjustable
                                              rate(b)      386,860      476,860
Pollution control bonds           2029        3.30%(c)      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           --
Floating rate notes               2001     Adjustable
                                              rate(d)           --      250,000
Senior notes (e)                  2006        6.75%         83,695       83,695
Capitalized lease obligation   2001-2003      7.75%            417          709
Capitalized lease obligation      2006        5.89%            926           --
                                                        ----------   ----------
Total long-term debt                                     2,074,525    2,057,174
  Less current maturities                                  125,451      250,266
                                                        ----------   ----------
Total long-term debt less
  current maturities                                    $1,949,074   $1,806,908
                                                        ==========   ==========

----------
(a)  This schedule does not reflect the timing of redemptions that may occur
     prior to maturity.
(b)  The weighted-average rate for the year ended December 31, 2001 was 2.55%
     and for December 31, 2000 was 4.06%. Changes in short-term interest rates
     would affect the costs associated with this debt.
(c)  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%.

                                       65
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

(d)  The weighted-average rate for the year ended December 31, 2000 was 7.33%.
     Interest for 2000 was based on LIBOR + 0.72%.
(e)  We currently have outstanding $84 million of first mortgage bonds (senior
     note mortgage bonds) issued to the senior note trustee as collateral for
     the senior notes. The senior note mortgage bonds have the same interest
     rate, interest payment dates, maturity, and redemption provisions as the
     senior notes. Our payments of principal, premium, and/or interest on the
     senior notes satisfy our corresponding payment obligations on the senior
     note mortgage bonds. As long as the senior note mortgage bonds secure the
     senior notes, the senior notes will effectively rank equally with the first
     mortgage bonds. When we repay all of our first mortgage bonds, other than
     those that secure senior notes, the senior note mortgage bonds will no
     longer secure the senior notes and will cease to be outstanding.

     Our bank agreements have financial covenants, including an interest
coverage test and a debt ratio. We anticipate that we will be able to meet the
covenant requirement levels.

     The following is a list of principal payments due on total long-term debt
and sinking fund requirements through 2006:

     *    $125 million in 2002;
     *    $  0 million in 2003;
     *    $205 million in 2004;
     *    $400 million in 2005; and
     *    $ 84 million in 2006.

     Our first mortgage bondholders share a lien on substantially all utility
plant assets (other than nuclear fuel and transportation equipment and other
excluded assets). The mortgage bond indenture restricts the payment of common
stock dividends under certain conditions. These conditions did not exist at
December 31, 2001.

7.   RETIREMENT PLANS AND OTHER BENEFITS

PENSION PLAN

     Through 1999, we sponsored defined benefit pension plans for our employees.
As of January 1, 2000, we are part of a multi-employer plan sponsored by
Pinnacle West. In 2001, we represent 89% of the total cost of this plan. A
defined benefit plan specifies the amount of benefits a plan participant is to
receive using information about the participant. The plan covers nearly all of
our employees. Our employees do not contribute to this plan. Generally, the
benefits under this plan are calculated based on age, years of service, and pay.
Pinnacle West funds the plan by contributing at least the minimum amount
required under Internal Revenue Service regulations but no more than the maximum
tax-deductible amount. The assets in the plan at December 31, 2001 were mostly
domestic and international common stocks and bonds and real estate.

     The following table shows our contributions and pension expense, including
administrative costs, and after consideration of amounts capitalized or billed
to electric plant participants for 2001, 2000, and 1999 (dollars in millions):

                                       66
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

                           2001       2000       1999
                          ------     ------     ------
Contributions             $   44     $   23     $   25
Pension Expense           $    6     $    2     $    4

     The following table shows the components of Pinnacle West's consolidated
net periodic pension cost before consideration of amounts capitalized or billed
to electric plant participants (dollars in thousands):

<TABLE>
<CAPTION>
                                                      2001         2000         1999
                                                    --------     --------     --------
<S>                                                 <C>          <C>          <C>
Service cost - benefits earned during the period    $ 26,640     $ 24,955     $ 24,982
Interest cost on projected benefit obligation         62,920       58,361       52,905
Expected return on plan assets                       (77,340)     (77,231)     (68,335)
Amortization of:
  Transition asset                                    (3,227)      (3,227)      (3,226)
  Prior service cost                                   2,716        2,078        2,078
Net actuarial gain                                        --       (1,633)          --
                                                    --------     --------     --------
Net periodic pension cost                           $ 11,709     $  3,303     $  8,404
                                                    ========     ========     ========
</TABLE>

     The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in Pinnacle West's consolidated balance sheets
(dollars in thousands):

                                                           2001         2000
                                                         ---------    ---------
Funded status - pension plan assets less than
  projected benefit obligation                           $(116,213)   $ (20,730)
Unrecognized net transition asset                          (13,554)     (16,781)
Unrecognized prior service cost                             24,465       18,558
Unrecognized net actuarial (gains)/losses                   94,952      (23,816)
                                                         ---------    ---------
Net pension liability recognized in the balance sheets   $ (10,350)   $ (42,769)
                                                         =========    =========

                                       67
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

     The following table sets forth the change in projected benefit obligation
for Pinnacle West's consolidated defined benefit pension plan for the plan years
2001 and 2000 (dollars in thousands):

                                                           2001         2000
                                                         ---------    ---------
Projected pension benefit obligation at
  beginning of year                                      $ 795,926    $ 742,638
Service cost                                                26,640       24,955
Interest cost                                               62,920       58,361
Benefit payments                                           (31,647)     (30,568)
Actuarial losses                                            18,625          540
Plan amendments                                              8,622           --
                                                         ---------    ---------
Projected pension benefit obligation at end of year      $ 881,086    $ 795,926
                                                         =========    =========

     The following table sets forth Pinnacle West's consolidated defined benefit
pension plan's change in the fair value of plan assets for the plan years 2001
and 2000 (dollars in thousands):

                                                           2001         2000
                                                         ---------    ---------
Fair value of pension plan assets at beginning of year   $ 775,196    $ 779,913
Actual gain/(loss) on plan assets                          (22,876)       1,851
Employer contributions                                      44,200       24,000
Benefit payments                                           (31,647)     (30,568)
                                                         ---------    ---------
Fair value of pension plan assets at end of year         $ 764,873    $ 775,196
                                                         =========    =========

Pinnacle West made the assumptions below to calculate the pension liability:

                                                           2001         2000
                                                         ---------    ---------
Discount rate                                               7.50%       7.75%
Rate of increase in compensation levels                     4.00%       4.25%
Expected long-term rate of return on assets                10.00%      10.00%

                                       68
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

EMPLOYEE SAVINGS PLAN BENEFITS

     Through 1999, we sponsored defined contribution savings plans for our
employees. As of January 1, 2000, we are part of a multi-employer plan sponsored
by Pinnacle West. In 2001, we represent 83% of the total cost of this plan. In a
defined contribution plan, the benefits a participant will receive result from
regular contributions they make to a participant account. Under this plan,
Pinnacle West makes matching contributions in Pinnacle West stock to participant
accounts. At December 31, 2001 approximately 30% of total plan assets were in
Pinnacle West stock. We recorded expenses for this plan of approximately $4
million for 2001, $3 million for 2000, and $4 million for 1999.

POSTRETIREMENT PLAN

     Through 1999, we sponsored postretirement medical and life insurance plans
for our employees. As of January 1, 2000, we are part of a multi-employer plan
sponsored by Pinnacle West. In 2001, we represent 93% of the total cost of this
plan. 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 to cover a portion of the plan costs.
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 following table shows our contributions and postretirement benefit
expense after consideration of amounts capitalized or billed to electric plant
participants for 2001, 2000, and 1999 (dollars in millions):

                                    2001       2000       1999
                                   ------     ------     ------
Contributions                      $   11     $    5     $   10
Postretirement benefit expense     $    6     $    2     $    6

     The following table shows the components of Pinnacle West's consolidated
net periodic postretirement benefit costs before consideration of amounts
capitalized or billed to electric plant participants (dollars in thousands):

                                       69
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                      2001         2000         1999
                                                    --------     --------     --------
<S>                                                 <C>          <C>          <C>
Service cost - benefits earned during the period    $  9,438     $  8,613     $  8,939
Interest cost on accumulated benefit obligation       21,585       19,315       17,366
Expected return on plan assets                       (21,985)     (22,381)     (18,454)
Amortization of:
  Transition obligation                                7,698        7,698        7,698
  Net actuarial gains                                 (4,066)      (7,983)      (5,117)
                                                    --------     --------     --------
Net periodic postretirement benefit cost            $ 12,670     $  5,262     $ 10,432
                                                    ========     ========     ========
</TABLE>

     The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in Pinnacle West's consolidated balance sheets
(dollars in thousands):

                                                           2001          2000
                                                         ---------    ---------
Funded status - postretirement plan assets less
  than projected benefit obligation                      $ (80,544)   $ (14,851)
Unrecognized net obligation at transition                   84,748       92,446
Unrecognized net actuarial gains                            (8,606)     (81,280)
                                                         ---------    ---------
Net postretirement amount recognized in the balance
  sheets                                                 $  (4,402)   $  (3,685)
                                                         =========    =========

     The following table sets forth Pinnacle West's consolidated postretirement
benefit plan's change in accumulated benefit obligation for the plan years 2001
and 2000 (dollars in thousands):

                                                           2001         2000
                                                         ---------    ---------
Accumulated postretirement benefit obligation
  at beginning of year                                   $ 264,006    $ 231,989
Service cost                                                 9,438        8,613
Interest cost                                               21,585       19,315
Benefit payments                                           (10,194)      (8,905)
Actuarial losses                                            33,520       12,994
                                                         ---------    ---------
Accumulated postretirement benefit obligation
  at end of year                                         $ 318,355    $ 264,006
                                                         =========    =========

                                       70
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

     The following table sets forth Pinnacle West's consolidated postretirement
benefit plan's change in the fair value of plan assets for the plan years 2001
and 2000 (dollars in thousands):

                                                           2001         2000
                                                         ---------    ---------
Fair value of postretirement plan assets at
  beginning of year                                      $ 249,154    $ 257,538
Actual loss on plan assets                                 (12,550)      (4,436)
Employer contributions                                      11,400        4,958
Benefit payments                                           (10,194)      (8,906)
                                                         ---------    ---------
Fair value of postretirement plan assets at
  the end of year                                        $ 237,810    $ 249,154
                                                         =========    =========

     Pinnacle West made the assumptions below to calculate the postretirement
liability:

                                                            2001         2000
                                                         ---------    ---------
Discount rate                                               7.50%        7.75%
Expected long-term rate of return on assets - after tax     8.86%        8.77%
Initial health care cost trend rate - under age 65          7.00%        7.00%
Initial health care cost trend rate - age 65 and over       7.00%        6.00%
Ultimate health care cost trend rate                        5.00%        5.00%
Year ultimate health care trend rate is reached             2006         2002

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

                                                      1% increase    1% decrease
                                                      -----------    -----------
Effect on 2001 cost of postretirement benefits
  other than pensions                                    $   6          $  (5)
Effect on the accumulated postretirement benefit
  obligation at December 31, 2001                        $  54          $ (43)

8.   LEASES

     In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain
common facilities in three separate sale leaseback transactions. We account for
these leases as operating leases. The gain of approximately $140 million was
deferred and is being amortized to operations 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, an amount equal to
the annual lease payments is included in rent expense. A regulatory asset is
recognized for the difference between lease payments and rent expense calculated
on a straight-line basis. See Note 2 for a discussion of special purpose
entities, including the special purpose entities involved in the Palo Verde
sale-leaseback transactions.

     The average amounts to be paid for the Palo Verde Unit 2 leases are
approximately $49 million per year for the years 2002-2015.

                                       71
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

     In accordance with the 1999 Settlement Agreement, we are continuing to
accelerate amortization of the regulatory asset for leases over an eight-year
period that will end June 30, 2004 (see Note 1). All regulatory asset
amortization is included in depreciation and amortization expense in the
statements of income. The balance of this regulatory asset at December 31, 2001
was $24 million.

     In December 2000, we purchased Units 1, 2, and 3 of West Phoenix Power
Plant, which was previously leased under a capitalized lease obligation.

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

     Total lease expense was $52 million in 2001, $53 million in 2000, and $49
million in 1999.

     Estimated future minimum lease commitments, are approximately $61 million
for each of the years 2002 to 2006 and $507 million thereafter.

9.   JOINTLY-OWNED FACILITIES

     We share ownership of some of our generating and transmission facilities
with other companies. The following table shows our interest in those
jointly-owned facilities recorded on the balance sheets at December 31, 2001.
Our share of operating and maintaining these facilities is included in the
income statement in operations and maintenance expense. Each participant is
entitled to its share of power generated.

<TABLE>
<CAPTION>
                                           PERCENT                                CONSTRUCTION
                                          OWNED BY     PLANT IN     ACCUMULATED     WORK IN
                                           COMPANY      SERVICE    DEPRECIATION     PROGRESS
                                           -------      -------    ------------     --------
                                                        (dollars in thousands)
<S>                                        <C>        <C>           <C>              <C>
Generating Facilities:
  Palo Verde Nuclear Generating Station
    Units 1 and 3                           29.1%     $1,822,369    $(862,880)       $10,984
  Palo Verde Nuclear Generating Station
    Unit 2 (see Note 8)                     17.0%        571,217     (278,234)        46,284
  Four Corners Steam Generating Station
    Units 4 and 5                           15.0%        150,298      (78,983)           503
  Navajo Steam Generating Station
    Units 1, 2, and 3                       14.0%        235,409     (104,189)         1,044
  Cholla Steam Generating Station
    Common Facilities (a)                   62.8%(b)      74,356      (41,555)         1,093
Transmission Facilities:
  ANPP 500KV System                         35.8%(b)      67,911      (24,293)           405
  Navajo Southern System                    31.4%(b)      27,053      (16,833)           202
  Palo Verde-Yuma 500KV System              23.9%(b)       9,685       (4,029)             8
  Four Corners Switchyards                  27.5%(b)       3,071       (1,945)            --
  Phoenix-Mead System                       17.1%(b)      36,418       (2,766)            --
  Palo Verde - Estrella 500KV System        50.0%(b)          --           --          2,215
</TABLE>

                                       72
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

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

10.  COMMITMENTS AND CONTINGENCIES

ENRON

     We recorded charges totaling $13 million before income taxes for exposure
to Enron and its affiliates in the fourth quarter of 2001. This amount is
comprised of a $7 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.

POWER SERVICE AGREEMENT

     By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised us that it believes we have overcharged Citizens by over $50 million
under a power service agreement. We believe that our charges under the agreement
were fully in accordance with the terms of the agreement. In addition, in
testimony filed with the ACC on March 13, 2002, Citizens acknowledged that,
based on its review, "if Citizens filed a complaint with FERC, it probably would
lose the central issue in the contract interpretation dispute." We terminated
the power service agreement with Citizens effective July 15, 2001. In
replacement of the power service agreement, Pinnacle West and Citizens entered
into a power sale agreement under which Pinnacle West will supply Citizens with
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.

PALO VERDE NUCLEAR GENERATING STATION

     Nuclear power plant operators are required to enter into spent fuel
disposal contracts with DOE, and 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 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 DOE's delay, a number of utilities filed damages
actions against 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. A
congressional decision on this issue is expected sometime during mid-summer
2002. We cannot currently predict what further steps will be taken in this area.

     We have existing fuel storage pools at Palo Verde and are in the process of
completing construction of a new facility for on-site dry storage of spent fuel.
With the existing storage pools and the addition of the new facility, we believe

                                       73
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

that spent fuel storage or disposal methods will be available for use by Palo
Verde to allow our continued operation through the term of the operating license
for each Palo Verde unit.

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

     We currently estimate that we will incur $407 million (in 2001 dollars)
over the life of Palo Verde for our share of the costs related to the on-site
interim storage of spent nuclear fuel. As of December 31, 2001, we had recorded
a liability and regulatory asset of $43 million for on-site interim 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 and the balance by
an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the accumulated funds, we could be
assessed retrospective premium adjustments. The maximum assessment per reactor
under the program for each nuclear incident is approximately $88 million,
subject to an annual limit of $10 million per incident. Based upon our interest
in the three Palo Verde units, our 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. We have also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.

FUEL AND PURCHASED POWER COMMITMENTS

     We are a party to various fuel and purchased power contracts with terms
expiring from 2002 through 2021 that include required purchase provisions. We
estimate our contract requirements to be approximately $252 million in 2002,
$124 million in 2003, $80 million in 2004, $65 million in 2005 and $68 million
in 2006. However, this amount may vary significantly pursuant to certain
provisions in such contracts that permit us to decrease our required purchases
under certain circumstances. Any purchased power contracts after 2003 will all
be recorded on Pinnacle West through their marketing and trading division.

COAL MINE RECLAMATION OBLIGATIONS

     We must reimburse certain coal providers for amounts incurred for coal mine
reclamation. We estimate our share of the total obligation to be about $103
million. The portion of the coal mine reclamation obligation related to coal
already burned is about $59 million at December 31, 2001 and is included in
deferred credits-other in the balance sheets.

                                       74
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

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

CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST

     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.

     We are closely monitoring developments in the California energy market and
the potential impact of these developments on us. We have evaluated, among other
things, SCE's role as a Palo Verde and Four Corners participant; our
transactions with the PX and the ISO; contractual relationships with SCE and
PG&E; and marketing and trading exposures. Based on our evaluations, we do not
believe the foregoing matters will have a material adverse effect on our
financial position and liquidity. 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 or the regional energy market in general.

     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 California ISO and PX provide necessary historical data. The FERC
also ordered an evidentiary proceeding to discuss and evaluate possible refunds
for the Pacific Northwest. The ALJ at the FERC in charge of that evidentiary
proceeding made an initial finding that no refunds were appropriate. The Pacific
Northwest issues will now be addressed by the FERC Commissioners. Although the
FERC has not yet made a final ruling in the Pacific Northwest matter or
calculated the specific refund amounts due in California, we do not expect that
the resolution of these issues, as to the amounts alleged in the proceedings,
will have a material adverse impact on our financial position, results of
operations or liquidity.

     On March 19, 2002, the State of California filed a complaint with the FERC
alleging that wholesale sellers of power and energy, including Pinnacle West,
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." The complaint indicates that Pinnacle West sold
approximately $106 million of power to the California Department of Water
Resources from January 17, 2001 to October 31, 2001 and does not allege any
amount above "just and reasonable levels." Pinnacle West believes that the
claims as they relate to Pinnacle West are without merit.

                                       75
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

CONSTRUCTION PROGRAM

     Total capital expenditures in 2002 are estimated at $498 million.

LITIGATION

     We are party to various claims, legal actions, and complaints arising in
the ordinary course of business. In our opinion, the ultimate resolution of
these matters will not have a material adverse effect on our financial
statements or liquidity.

11.  NUCLEAR DECOMMISSIONING COSTS

     We recorded $11 million for nuclear decommissioning expense in each of the
years 2001, 2000, and 1999. We estimate it will cost about $1.8 billion ($506
million in 2001 dollars) to decommission our 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. We charge decommissioning costs to expense
over each unit's operating license term and include them in the accumulated
depreciation balance until each unit is retired. Nuclear decommissioning costs
are recovered in rates.

     Our 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. We are required to update the
study every three years.

     To fund the costs we expect to incur to decommission the plant, we
established external decommissioning trusts in accordance with NRC regulations.
We invest the trust funds primarily in fixed income securities and domestic
stock and classify 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 are reported in investments and other
assets on the balance sheets at December 31, 2001 and 2000 (dollars in
millions):

                                                     2001        2000
                                                    ------      ------
          Trust fund assets - at cost
            Fixed income securities                 $  103      $   94
            Domestic stock                              61          52
                                                    ------      ------
          Total                                     $  164      $  146
                                                    ======      ======
          Trust fund assets - fair value
            Fixed income securities                 $  106      $   97
            Domestic stock                              96         100
                                                    ------      ------
          Total                                     $  202      $  197
                                                    ======      ======

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

                                       76
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

12.  SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

     Quarterly financial information for 2001 and 2000 is as follows:

                             (dollars in thousands)

                                                   2001
                             ---------------------------------------------------
QUARTER ENDED                March 31     June 30     September 30   December 31
                             ---------   ----------   ------------   -----------
Electric operating revenues  $ 764,940   $1,061,471    $1,048,634     $ 435,747
Operating income (a)         $  97,034   $   95,238    $  135,139     $  71,567
Income before accounting
  change                     $  64,606   $   69,639    $  107,556     $  38,887

Cumulative effect of change
  in accounting - net of
  income tax                   (2,755)          --       (12,446)           --
                             ---------   ----------    ----------     ---------
Net income                   $  61,851   $   69,639    $   95,110     $  38,887
                             =========   ==========    ==========     =========

                             (dollars in thousands)

                                                   2000
                             ---------------------------------------------------
QUARTER ENDED                March 31     June 30     September 30   December 31
                             ---------   ----------   ------------   -----------
Electric operating revenues  $ 445,981   $  719,394    $1,565,622     $ 749,255
Operating income (a)         $  64,849   $  131,034    $  159,589     $  90,764
Net income                   $  32,775   $   95,851    $  124,231     $  53,737

----------
(a)  Our utility business is 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.

13.  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, 2001 and
2000 due to their short maturities.

     We hold investments in debt and equity securities for purposes other than
trading. The December 31, 2001 and 2000 fair values of such investments, which
we determine by using quoted market values, approximate their carrying amount.

     On December 31, 2001, the carrying value of our long-term debt (excluding a
capitalized lease obligation) was $2.08 billion, with an estimated fair value of
$2.10 billion. The carrying value of our long-term debt (excluding a capitalized
lease obligation) was $2.06 billion on December 31, 2000, with an estimated fair
value of $2.11 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.

                                       77
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

14.  STOCK-BASED COMPENSATION

     Pinnacle West offers two stock incentive plans for officers and key
employees of our company.

     One of the plans (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 other plan (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 plan also provides for the
granting of any combination of shares of restricted stock, stock appreciation
rights or dividend equivalents.

     The awards outstanding under the incentive plans at December 31, 2001 are
1,832,725 non-qualified stock options, 237,833 shares of restricted stock, and
no incentive stock options, stock appreciation rights or dividend equivalents.

     SFAS No. 123, "Accounting for Stock-Based Compensation" encourages, but
does not require, that a company record compensation expense based on the fair
value of options granted (the fair value method). We continue to recognize
expense based on Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees."

     If we had recorded compensation expense based on the fair value method, our
net income would have been reduced to the following pro forma amounts (dollars
in thousands):

                                              2001          2000          1999
                                            --------      --------      --------
Net income
  As reported                               $265,487      $306,594      $128,437
  Pro forma (fair value method)             $263,594      $305,610      $127,658

     In order to present 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:

                                              2001          2000          1999
                                            --------      --------      --------
Risk-free interest rate                       4.08%         5.81%         5.68%
Dividend yield                                3.70%         3.48%         3.33%
Volatility                                   27.66%        32.00%        20.50%
Expected life (months)                          60            60            60

                                       78
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

15.  BUSINESS SEGMENTS

     We have two principal business segments (determined by products, services
and regulatory environment) which consist of regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
currently includes activities related to electricity transmission and
distribution, as well as electricity generation. Our marketing and trading
business segment currently includes activities related to wholesale marketing
and trading.

     These reportable segments reflect a change in the reporting of our segment
information. Before the fourth quarter of 2001, we had two segments (generation
and delivery). The "generation segment" information combined our marketing and
trading activities with our generation of electricity activities. The "delivery
segment" included transmission and distribution activities.

     In the fourth quarter of 2001, we filed with the ACC a proposed rule
variance and purchase power agreement with the ACC (see Note 3) that inherently
views our business in the new reportable segments described herein. Internal
management reporting has been changed to reflect this alignment. The
corresponding information for earlier periods has been restated. Financial data
for the business segments is provided as follows (dollars in millions):

               Business Segments for Year Ended December 31, 2001

                                                          Marketing
                                                             and
                                              Retail       Trading       Total
                                              -------      -------      -------
Operating revenues                            $ 2,562      $   749      $ 3,311
Purchased power and fuel costs                  1,224          517        1,741
Other operating expenses                          568           --          568
                                              -------      -------      -------
  Operating margin                                770          232        1,002
Depreciation and amortization                     421           --          421
Interest and other expenses                       118           --          118
                                              -------      -------      -------
  Pretax margin                                   231          232          463
Income taxes                                       91           92          183
                                              -------      -------      -------
Income before accounting change                   140          140          280

Cumulative effect of change in
  accounting for derivatives - net of
  income taxes of $10                             (15)          --          (15)
                                              -------      -------      -------
Net income                                    $   125      $   140      $   265
                                              =======      =======      =======
Total assets                                  $ 6,228      $   139      $ 6,367
                                              =======      =======      =======
Capital expenditures                          $   471      $    --      $   471
                                              =======      =======      =======

                                       79
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

               Business Segments for Year Ended December 31, 2000

                                                          Marketing
                                                             and
                                              Retail       Trading       Total
                                              -------      -------      -------
Operating revenues                            $ 2,538      $   942      $ 3,480
Purchased power and fuel costs                  1,063          815        1,878
Other operating expenses                          541           --          541
                                              -------      -------      -------
  Operating margin                                934          127        1,061
Depreciation and amortization                     425           --          425
Interest and other expenses                       133           --          133
                                              -------      -------      -------
  Pretax margin                                   376          127          503
Income taxes                                      146           50          196
                                              -------      -------      -------
Net income                                    $   230      $    77      $   307
                                              =======      =======      =======
Total assets                                  $ 6,096      $   318      $ 6,414
                                              =======      =======      =======
Capital expenditures                          $   472      $    --      $   472
                                              =======      =======      =======

               Business Segments for Year Ended December 31, 1999

                                                          Marketing
                                                             and
                                              Retail       Trading       Total
                                              -------      -------      -------
Operating revenues                            $ 1,916   $      377      $ 2,293
Purchased power and fuel costs                    433          360          793
Operating expenses                                547           --          547
                                              -------      -------      -------
  Operating margin                                936           17          953
Depreciation and amortization                     416           --          416
Interest and preferred stock
  dividend requirements                           137           --          137
                                              -------      -------      -------
  Pretax margin                                   383           17          400
Income taxes                                      126            7          133
                                              -------      -------      -------
Income before extraordinary charge                257           10          267
Extraordinary charge - net of
  income taxes of $94                            (140)          --         (140)
                                              -------      -------      -------
Earnings for common stock                     $   117      $    10      $   127
                                              =======      =======      =======
Total assets                                  $ 6,056      $    62      $ 6,118
                                              =======      =======      =======
Capital expenditures                          $   332      $    --      $   332
                                              =======      =======      =======

16.  DERIVATIVE INSTRUMENTS

     We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal and emissions allowances.
We employ 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
allowance and credits. The changes in market value of such contracts have a high

                                       80
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

correlation to price changes in the hedged commodity. In addition, subject to
specified risk parameters established by the Pinnacle West Board of Directors
and monitored by the Pinnacle West ERMC, we engage in trading activities
intended to profit from market price movements.

     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 this and all other counterparties. Despite the fact that
the great majority of our counterparties are rated as investment grade by the
credit rating agencies there is still a possibility that one or more of these
companies could default, resulting in a material impact on earnings for a given
period. Counterparties in the portfolio consist principally of major energy
companies, municipalities, and local distribution companies. We maintain credit
policies that we believe minimize overall credit risk to within acceptable
limits. Determination of the credit quality of our counterparties is based upon
a number of factors, including credit ratings and our evaluation of their
financial condition. In many contracts, we employ collateral requirements and
standardized agreements that allow for the netting of positive and negative
exposures associated with a single counterparty. Credit reserves are established
representing our estimated credit losses on our overall exposure to
counterparties. See Note 1 for a discussion of our credit reserve policy.

     Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires that
entities recognize all derivatives as either assets or liabilities on the
balance sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. Hedge effectiveness is measured based on the relative changes in fair
value between the derivative contract and the hedged item over time. Any change
in the fair value resulting from ineffectiveness is recognized immediately in
net income. This new standard may result in additional volatility in our net
income and comprehensive income.

     As a result of adopting SFAS No. 133, we recognized $118 million of
derivative assets and $16 million of derivative liabilities in our balance
sheets as of January 1, 2001. Also as of January 1, 2001, we recorded a $3
million after-tax loss in net income and a $64 million after-tax gain in equity
(as a component of other comprehensive income) both as a cumulative effect of a
change in accounting principle. The gain resulted from unrealized gains on cash
flow hedges.

     In June 2001, the FASB issued new guidance related to electricity
contracts. The effective date of this new guidance was July 1, 2001. As of July
1, 2001, we recorded an additional $12 million after-tax loss in net income and
an additional $8 million after-tax gain in equity (as a component of other
comprehensive income), as a result of adopting the new guidance related to
electricity contracts. The loss resulted primarily from electricity options
contracts. The gain resulted from unrealized gains on cash flow hedges. The
impact of the new guidance is reflected in net income and other comprehensive
income as a cumulative effect of change in accounting principle.

     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

                                       81
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

date for the revised guidance is April 1, 2002. We are currently evaluating the
new guidance to determine what impact, if any, it will have on our financial
statements.

     The change in derivative fair value included in the statements of income
for the year ending December 31, 2001 is comprised of the following (dollars in
thousands):

                                               December 31,
                                                  2001
                                               ------------
Ineffective portion of derivatives
  qualifying for hedge accounting (a)            $ (8,371)
Discontinuance of cash flow hedges for
  forecasted transactions that will not
  occur                                            (9,525)
Reclassification of mark-to-market
  losses to realized                               25,948
                                                 --------
Total                                            $  8,052
                                                 ========

----------
(a)  Time value component of options excluded from assessment of hedge
     effectiveness.

     As of December 31, 2001, the maximum length of time over which we are
hedging our exposure to the variability in future cash flows for forecasted
transactions is thirty-six months. During the twelve months ended December 31,
2002, we estimate that a net loss of $23 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 transaction.

     Net gains and losses on instruments utilized for trading activities are
recognized in marketing and trading revenues on a current basis (the
mark-to-market method). Trading positions are measured at fair value as of the
balance sheet date. The unrealized trading gains recognized in marketing and
trading revenues were $85 million for the year ended December 31,2001 and $14
million for the year ended December 31, 2000.

17.  SUBSEQUENT EVENTS

     On March 1, 2002, we issued $375 million of 6.50% Notes due 2012. On March
15, 2002, we announced the redemption on April 15, 2002 of approximately $125
million of our First Mortgage Bonds, 8.75% Series due 2024.

     On March 19, 2002, the State of California filed a complaint with the FERC
alleging that wholesale sellers of power and energy, including Pinnacle West,
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." The complaint indicates that Pinnacle West sold
approximately $106 million of power to the California Department of Water
Resources from January 17, 2001 to October 31, 2001 and does not allege any
amount above "just and reasonable levels." Pinnacle West believes that the
claims as they relate to Pinnacle West are without merit.

     See Note 3 for information relating to the March 22, 2002 ACC Staff report
addressing issues in the generic docket.

                                       82
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

                         ARIZONA PUBLIC SERVICE COMPANY
                    SCHEDULE II - RESERVE FOR UNCOLLECTIBLES
                             (DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
         COLUMN A                 COLUMN B             COLUMN C            COLUMN D       COLUMN E
         --------                 --------      ----------------------     --------       --------
                                                      ADDITIONS
                                                ----------------------
                                 BALANCE AT     CHARGED TO    CHARGED                    BALANCE AT
                                  BEGINNING      COST AND     TO OTHER                     END OF
        DESCRIPTION               OF PERIOD      EXPENSES     ACCOUNTS    DEDUCTIONS       PERIOD
        -----------              -----------    -----------   --------    -----------    -----------
<S>                              <C>            <C>                       <C>            <C>
 RESERVE FOR UNCOLLECTIBLES

Year ended December 31, 2001        $2,380         $7,609        --          $6,640         $3,349
Year ended December 31, 2000        $1,538         $5,438        --           4,596         $2,380
Year ended December 31, 1999        $1,725         $4,778        --           4,965         $1,538
</TABLE>

                                       83
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS

            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

     Not applicable.

                         ITEM 11. EXECUTIVE COMPENSATION

     Not applicable.

                         ITEM 12. SECURITY OWNERSHIP OF
                    CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
                         AND RELATED STOCKHOLDER MATTERS

     Not applicable.

             ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Not applicable.

                                       84
<PAGE>
                                     PART IV

          ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT
                       SCHEDULES, AND REPORTS ON FORM 8-K

FINANCIAL STATEMENTS

     See the Index to Financial Statements in Part II, Item 8.

EXHIBITS FILED

EXHIBIT NO.                        DESCRIPTION
-----------                        -----------

12.1      --    Computation of Ratio of Earnings to Fixed Charges

23.1      --    Consent of Deloitte & Touche LLP

     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:
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
3.1             Bylaws, amended as of               3.1 to 1995 Form 10-K               1-4473             3-29-96
                February 20, 1996                   Report

3.2             Resolution of Board of              3.2 to 1994 Form 10-K               1-4473             3-30-95
                Directors temporarily               Report
                suspending Bylaws in part

3.3             Articles of Incorporation,          4.2 to Form S-3                     1-4473             9-29-93
                restated as of May 25, 1988         Registration Nos.
                                                    33-33910 and 33-55248 by
                                                    means of September 24,
                                                    1993 Form 8-K Report

4.1             Mortgage and Deed of Trust          4.1 to September 1992               1-4473             11-9-92
                Relating to the Company's           Form 10-Q Report
                First Mortgage Bonds,
                together with forty-eight
                indentures supplemental
                thereto

4.2             Forty-ninth Supplemental            4.1 to 1992 Form 10-K               1-4473             3-30-93
                Indenture                           Report
</TABLE>

                                       85
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
4.3             Fiftieth Supplemental               4.2 to 1993 Form 10-K               1-4473             3-30-94
                Indenture                           Report

4.4             Fifty-first Supplemental            4.1 to August 1, 1993               1-4473             9-27-93
                Indenture                           Form 8-K Report

4.5             Fifty-second Supplemental           4.1 to September 30, 1993           1-4473             11-15-93
                Indenture                           Form 10-Q Report

4.6             Fifty-third Supplemental            4.5 to Registration                 1-4473             3-1-94
                Indenture                           Statement No. 33-61228
                                                    by means of February 23,
                                                    1994 Form 8-K Report

4.7             Fifty-fourth Supplemental           4.1 to 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

4.8             Fifty-fifth Supplemental            4.8 to 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

4.9             Agreement, dated March 21,          4.1 to 1993 Form 10-K               1-4473             3-30-94
                1994, relating to the filing        Report
                of instruments defining the
                rights of holders of long-term
                debt not in excess of 10% of
                the Company's total assets

4.10            Indenture dated as of January       4.6 to Registration                 1-4473             1-11-95
                1, 1995 among the Company           Statement Nos. 33-61228
                and The Bank of New York,           and 33-55473 by means of
                as Trustee                          January 1, 1995 Form 8-K
                                                    Report

4.11            First Supplemental Indenture        4.4 to 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
</TABLE>

                                       86
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
4.12            Indenture dated as of               4.5 to Registration                 1-4473             11-22-96
                November 15, 1996 among             Statements Nos. 33-61228,
                the Company and The Bank            33-55473, 33-64455 and
                of New York, as Trustee             333-15379 by means of
                                                    November 19, 1996
                                                    Form 8-K Report

4.13            First Supplemental Indenture        4.6 to 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

4.14            Second Supplemental Inden-          4.10 to Registration                1-4473             4-9-97
                ture dated as of April 1, 1997      Statement Nos. 33-55473,
                                                    33-64455 and 333-15379
                                                    by means of April 7, 1997
                                                    Form 8-K Report

4.15            Indenture dated as of January       4.10 to Registration                1-4473             1-16-98
                15, 1998 among the Company          Statement Nos. 333-15379
                and The Chase Manhattan             and 333-27551 by means
                Bank, as Trustee                    of January 13, 1998
                                                    Form 8-K Report

4.16            First Supplemental Indenture        4.3 to 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

4.17            Second Supplemental                 4.3 to Registration                 1-4473             2-22-99
                Indenture dated as of               Statement Nos. 333-27551
                February 15, 1999                   and 333-58445 by means of
                                                    February 18, 1999
                                                    Form 8-K Report

4.18            Third Supplemental Indenture        4.5 to Registration                 1-4473             11-5-99
                dated as of November 1, 1999        Statement No. 333-58445
                                                    by means of November 2,
                                                    1999 Form 8-K Report
</TABLE>

                                       87
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
4.19            Fourth Supplemental Inden-          4.1 to Registration                 1-4473             8-4-00
                ture dated as of August 1,          Statement Nos. 333-58445
                2000                                and 333-94277 by means
                                                    of August 2, 2000 Form
                                                    8-K Report

4.20            Fifth Supplemental Inden-           4.1 to September 2001               1-4473             11-6-01
                ture dated as of October 1,         Form 10-Q
                2001

4.21            Sixth Supplemental Inden-           4.1 to Registration                 1-4473             2-28-02
                ture dated as of March 1,           Statement Nos.
                2002                                333-63994 and
                                                    333-83398 by means
                                                    of February 26, 2002
                                                    Form 8-K Report

10.1            Two separate                        10.2 to September 1991              1-4473             11-14-91
                Decommissioning Trust               Form 10-Q
                Agreements (relating to
                PVNGS Units 1 and 3,
                respectively), each dated
                July 1, 1991, between the
                Company and Mellon Bank,
                N.A., as Decommissioning
                Trustee

10.2            Amendment No. 1 to                  10.1 to 1994 Form 10-K              1-4473             3-30-95
                Decommissioning Trust               Report
                Agreement (PVNGS Unit 1)
                dated as of December 1,
                1994

10.3            Amendment No. 2 to                  10.4 to 1996 Form 10-K              1-4473             3-28-97
                Decommissioning Trust               Report
                Agreement (PVNGS
                Unit 1) dated as of
                July 1, 1991

10.4            Amendment No. 1 to                  10.2 to 1994 Form 10-K              1-4473             3-30-95
                Decommissioning Trust               Report
                Agreement (PVNGS
                Unit 3) dated as of
                December 1, 1994
</TABLE>

                                       88
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.5            Amendment No. 2 to                  10.6 to 1996 Form 10-K              1-4473             3-28-97
                Decommissioning Trust               Report
                Agreement (PVNGS
                Unit 3) dated as of
                July 1, 1991

10.6            Amended and Restated                10.1 to Pinnacle West               1-8962             3-26-92
                Decommissioning Trust               1991 Form 10-K Report
                Agreement (PVNGS Unit 2)
                dated as of January 31, 1992,
                among the Company, Mellon
                Bank, N.A., as Decommissioning
                Trustee, and State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston,
                as Owner Trustee under
                two separate Trust Agreements,
                each with a separate Equity
                Participant, and as Lessor
                under two separate Facility
                Leases, each relating to
                an undivided interest in
                PVNGS Unit 2

10.7            First Amendment to Amended          10.2 to 1992 Form 10-K              1-4473             3-30-93
                and Restated                        Report
                Decommissioning Trust
                Agreement (PVNGS
                Unit 2), dated as of
                November 1, 1992

10.8            Amendment No. 2 to                  10.3 to 1994 Form 10-K              1-4473             3-30-95
                Amended and Restated                Report
                Decommissioning Trust
                Agreement (PVNGS
                Unit 2) dated as of
                November 1, 1994

10.9            Amendment No. 3 to                  10.1 to June 1996 Form              1-4473             8-9-96
                Amended and Restated                10-Q Report
                Decommissioning Trust
                Agreement (PVNGS
                Unit 2) dated as of
                January 31, 1992
</TABLE>

                                       89
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.10           Amendment No. 4 to                  10.5 to 1996 Form 10-K              1-4473             3-28-97
                Amended and Restated                Report
                Decommissioning Trust
                Agreement (PVNGS
                Unit 2) dated as of
                January 31, 1992

10.11           Asset Purchase and Power            10.1 to June 1991 Form              1-4473             8-8-91
                Exchange Agreement dated            10-Q Report
                September 21, 1990 between
                the Company and PacifiCorp,
                as amended as of October 11,
                1990 and as of July 18, 1991

10.12           Long-Term Power Trans-              10.2 to June 1991 Form              1-4473             8-8-91
                actions Agreement dated             10-Q Report
                September 21, 1990
                between the Company and
                PacifiCorp, as amended as
                of October 11, 1990 and
                as of July 8, 1991

10.13           Contract, dated July 21, 1984,      10.31 to Pinnacle West's            2-96386            3-13-85
                with DOE providing for the          Form S-14 Registration
                disposal of nuclear fuel            Statement
                and/or high-level radioactive
                waste, ANPP

10.14           Amendment No. 1 dated               10.3 to 1995 Form 10-K              1-4473             3-29-96
                April 5, 1995 to the Long-          Report
                Term Power Transactions
                Agreement and Asset Purchase
                and Power Exchange Agree-
                ment between PacifiCorp and
                the Company

10.15           Restated Transmission               10.4 to 1995 Form 10-K              1-4473             3-29-96
                Agreement between                   Report
                PacifiCorp and the Company
                dated April 5, 1995
</TABLE>

                                       90
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.16           Contract among PacifiCorp,          10.5 to 1995 Form 10-K              1-4473             3-29-96
                the Company and United              Report
                States Department of Energy
                Western Area Power
                Administration, Salt Lake
                Area Integrated Projects
                for Firm Transmission
                Service dated May 5, 1995

10.17           Reciprocal Transmission             10.6 to 1995 Form 10-K              1-4473             3-29-96
                Service Agreement between           Report
                the Company and PacifiCorp
                dated as of March 2, 1994

10.18           Indenture of Lease with             5.01 to Form S-7                    2-59644            9-1-77
                Navajo Tribe of Indians,            Registration Statement
                Four Corners Plant

10.19           Supplemental and Additional         5.02 to 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

10.20           Amendment and Supplement            10.36 to Registration               1-8962             7-25-85
                No. 1 to Supplemental and           Statement on Form 8-B of
                Additional Indenture of             Pinnacle West
                Lease, Four Corners, dated
                April 25,1985

10.21           Application and Grant of            5.04 to Form S-7                    2-59644            9-1-77
                multi-party rights-of-way           Registration Statement
                and easements, Four
                Corners Plant Site

10.22           Application and Amendment           10.37 to Registration               1-8962             7-25-85
                No. 1 to Grant of multi-party       Statement on Form 8-B of
                rights-of-way and easements,        Pinnacle West
                Four Corners Power Plant
                Site, dated April 25, 1985
</TABLE>

                                       91
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.23           Four Corners Project                10.7 to Pinnacle West               1-8962             3-14-01
                Co-Tenancy Agreement                2000 Form 10-K Report
                Amendment No. 6

10.24           Application and Grant of            5.05 to Form S-7                    2-59644            9-1-77
                Arizona Public Service              Registration Statement
                Company rights-of-way
                and easements, Four
                Corners Plant Site

10.25           Application and Amendment           10.38 to Registration               1-8962             7-25-85
                No. 1 to Grant of Arizona           Statement on Form 8-B of
                Public Service Company              Pinnacle West
                rights-of-way and easements,
                Four Corners Power Plant
                Site, dated April 25, 1985

10.26           Indenture of Lease, Navajo          5(g) to Form S-7                    2-36505            3-23-70
                Units 1, 2, and 3                   Registration Statement

10.27           Application and Grant of            5(h) to Form S-7                    2-36505            3-23-70
                rights-of-way and ease-             Registration Statement
                ments, Navajo Plant

10.28           Water Service Contract              5(l) to Form S-7                    2-39442            3-16-71
                Assignment with the United          Registration Statement
                States Department of
                Interior, Bureau of
                Reclamation, Navajo Plant

10.29           Arizona Nuclear Power               10.1 to 1988 Form 10-K              1-4473             3-8-89
                Project Participation Agree-        Report
                ment, dated August 23, 1973,
                among the Company, Salt
                River Project Agricultural
                Improvement and Power
                District, Southern California
                Edison Company, Public
                Service Company of New
                Mexico, El Paso Electric
                Company, Southern
                California Public Power
                Authority, and Department
                of Water and Power of the
                City of Los Angeles, and
                amendments 1-12 thereto
</TABLE>

                                       92
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.30           Amendment No. 13 dated as           10.1 to March 1991 Form             1-4473             5-15-91
                of April 22, 1991, to Arizona       10-Q Report
                Nuclear Power Project Partici-
                pation Agreement, dated
                August 23, 1973, among
                the Company, Salt River
                Project Agricultural Improve-
                ment 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

10.31           Amendment No. 14, to                10.4 to the Pinnacle West           1-8962             8-14-00
                Arizona Nuclear Power               June 30, 2000 Form 10-Q
                Project Participation               Report
                Agreement, dated August
                23, 1973, among the
                Company, Salt River
                Project Agricultural Improve-
                ment 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

10.32(c)        Facility Lease, dated as of         4.3 to Form S-3                     33-9480            10-24-86
                August 1, 1986, between             Registration Statement
                State Street Bank and Trust
                Company, as successor to
                The First National Bank of
                Boston, in its capacity as
                Owner Trustee, as Lessor,
                and the Company, as Lessee
</TABLE>

                                       93
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.33(c)        Amendment No. 1, dated as           10.5 to September 1986              1-4473             12-4-86
                of November 1, 1986, to             Form 10-Q Report by
                Facility Lease, dated as of         means of Amendment No.
                August 1, 1986, between             1 on December 3, 1986
                State Street Bank and Trust         Form 8
                Company, as successor to
                The First National Bank of
                Boston, in its capacity as
                Owner Trustee, as Lessor,
                and the Company, as Lessee

10.34(c)        Amendment No. 2 dated as            10.3 to 1988 Form 10-K              1-4473             3-8-89
                of 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

10.35(c)        Amendment No. 3, dated as           10.3 to 1992 Form 10-K              1-4473             3-30-93
                of March 17, 1993, to               Report
                Facility Lease, dated as
                of August 1, 1986, between
                State Street Bank and Trust
                Company, as successor to
                The First National Bank of
                Boston, as Lessor, and the
                Company, as Lessee

10.36           Facility Lease, dated as of         10.1 to 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 the Company, as Lessee
</TABLE>

                                       94
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.37           Amendment No. 1, dated as of        4.13 to Form S-3                    1-4473             8-24-87
                August 1, 1987, to Facility         Registration Statement
                Lease, dated as of December         No. 33-9480 by means of
                15, 1986, between State Street      August 1, 1987 Form 8-K
                Bank and Trust Company, as          Report
                successor to The First
                National Bank of Boston, as
                Lessor, and the Company, as
                Lessee

10.38           Amendment No. 2, dated as           10.4 to 1992 Form 10-K              1-4473             3-30-93
                of March 17, 1993, to               Report
                Facility Lease, dated as
                of December 15, 1986,
                between State Street Bank
                and Trust Company, as
                successor to The First
                National Bank of Boston,
                as Lessor, and the Company,
                as Lessee

10.39(a)        Directors' Deferred                 10.1 to June 1986 Form              1-4473             8-13-86
                Compensation Plan, as               10-Q Report
                restated, effective January 1,
                1986

10.40(a)        Second Amendment to the             10.2 to 1993 Form 10-K              1-4473             3-30-94
                Arizona Public Service              Report
                Company Directors'
                Deferred Compensation
                Plan, effective as of
                January 1, 1993

10.41(a)        Third Amendment to the              10.1 to September 1994              1-4473             11-10-94
                Arizona Public Service              Form 10-Q
                Company Directors'
                Deferred Compensation
                Plan effective as of
                May 1, 1993

10.42(a)        Fourth Amendment dated              10.8 to Pinnacle West's             1-8962             3-30-00
                December 28, 1999 to the            1999 Form 10-K
                Arizona Public Service
                Company Directors
                Deferred Compensation
                Plan
</TABLE>

                                       95
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.43(a)        Arizona Public Service              10.4 to 1988 Form 10-K              1-4473             3-8-89
                Company Deferred                    Report
                Compensation Plan, as
                restated, effective
                January 1, 1984, and the
                second and third
                amendments thereto, dated
                December 22, 1986, and
                December 23, 1987,
                respectively

10.44(a)        Third Amendment to the              10.3 to 1993 Form 10-K              1-4473             3-30-94
                Arizona Public Service              Report
                Company Deferred
                Compensation Plan, effective
                as of January 1, 1993

10.45(a)        Fourth Amendment to the             10.2 to September 1994              1-4473             11-10-94
                Arizona Public Service              Form 10-Q Report
                Company Deferred
                Compensation Plan effective
                as of May 1, 1993

10.46(a)        Fifth Amendment to the              10.3 to 1997 Form 10-K              1-4473             3-28-97
                Arizona Public Service              Report
                Company Deferred
                Compensation Plan

10.47(a)        Sixth Amendment to                  10.8 to Pinnacle West               1-8962             3-14-01
                Arizona Public Service              2000 Form 10-K Report
                Company Deferred
                Compensation Plan

10.48(a)        Pinnacle West Capital               10.10 to 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
</TABLE>

                                       96
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.49(a)        First Amendment effective as        10.6 to Pinnacle West's             1-8962             3-30-00
                of January 1, 1999, to the          1999 Form 10-K Report
                Pinnacle West Capital
                Corporation, Arizona Public
                Service Company, SunCor
                Development Company and
                El Dorado Investment
                Company Deferred Compen-
                sation Plan

10.50(a)        Second Amendment effective          10.10 to Pinnacle West's            1-8962             3-30-00
                as of January 1, 2000, to the       1999 Form 10-K Report
                Pinnacle West Capital
                Corporation, Arizona Public
                Service Company, SunCor
                Development Company and
                El Dorado Investment
                Company Deferred Compen-
                sation Plan

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

10.52(a)        First Amendment to the              10.7 to Pinnacle West's             1-8962             3-27-02
                Pinnacle West Capital               2001 Form 10-K Report
                Corporation Supplemental
                Excess Benefit Retirement
                Plan

10.53(a)        Second Amendment to the             10.8 to Pinnacle West's             1-8962             3-27-02
                Pinnacle West Capital               2001 Form 10-K Report
                Corporation Supplemental
                Excess Benefit Retirement
                Plan

10.54(a)        Pinnacle West Capital               10.7 to 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

10.55(a)        Pinnacle West Capital               99.2 to Pinnacle West's             1-8962             7-3-00
                Corporation and Arizona             Registration Statement on
                Public Service Company              Form S-8 No. 333-40796
                Directors' Retirement Plan,
                as amended and restated
                on June 21, 2000
</TABLE>

                                       97
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.56(a)        Arizona Public Service              10.1 to September 1997              1-4473             11-12-97
                Company Director                    Form 10-K Report
                Equity Plan

10.57(a)        Letter Agreement dated              10.6 to 1994 Form 10-K              1-4473             3-30-95
                December 21, 1993, between          Report
                the Company and William L.
                Stewart

10.58(a)        Letter Agreement dated              10.8 to 1996 Form 10-K              1-4473             3-28-97
                August 16, 1996 between             Report
                the Company and
                William L. Stewart

10.59(a)        Letter Agreement between            10.2 to September 1997              1-4473             11-12-97
                the Company and                     Form 10-Q Report
                William L. Stewart

10.60(a)        Letter Agreement dated              10.9 to Pinnacle West's             1-8962             3-30-00
                December 13, 1999 between           1999 Form 10-K Report
                the Company and
                William L. Stewart

10.61(a)        Letter Agreement dated as           10.8 to 1995 Form 10-K              1-4473             3-29-96
                of January 1, 1996 between          Report
                the Company and Robert G.
                Matlock & Associates, Inc.
                for consulting services

10.62(a)        Letter Agreement dated              10.17 to Pinnacle West's            1-8962             3-30-00
                October 3, 1997 between             1999 Form 10-K Report
                the Company and James M.
                Levine
</TABLE>

                                       98
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.63(a)(d)     Key Executive Employment            10.1 to Pinnacle West's             1-8962             8-16-99
                and Severance Agreement             June 1999 Form 10-Q
                between Pinnacle West and           Report
                certain executive officers of
                Pinnacle West and its
                subsidiaries

10.64(a)        Pinnacle West Capital               10.1 to 1992 Form 10-K              1-4473             3-30-93
                Corporation Stock Option            Report
                and Incentive Plan

10.65(a)        First Amendment dated               10.11 to Pinnacle West's            1-8962             3-30-00
                December 7, 1999 to the             1999 Form 10-K Report
                Pinnacle West Capital
                Corporation Stock Option
                and Incentive Plan

10.66(a)        Pinnacle West Capital               A to the Proxy Statement            1-8962             4-16-94
                Corporation 1994 Long-              for the Plan Report
                Term Incentive Plan                 Pinnacle West 1994
                effective as of                     Annual Meeting of
                March 23, 1994                      Shareholders

10.67(a)        First Amendment dated               10.12 to Pinnacle West's            1-8962             3-30-00
                December 7, 1999, to the            1999 Form 10-K Report
                Pinnacle West Capital
                Corporation 1994 Long-
                Term Incentive Plan

10.68(a)        Trust for the Pinnacle West         10.14 to Pinnacle West's            1-8962             3-30-00
                Capital Corporation, Arizona        1999 Form 10-K Report
                Public Service Company
                and SunCor Development
                Company Deferred
                Compensation Plans
                dated August 1, 1996

10.69(a)        First Amendment dated               10.15 to Pinnacle West's            1-8962             3-30-00
                December 7, 1999, to the            1999 Form 10-K Report
                Trust for the Pinnacle West
                Capital Corporation, Arizona
                Public Service Company and
                SunCor Development
                Company Deferred
                Compensation Plans
</TABLE>

                                       99
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.70(a)        2002 Management Variable            10.4 to Pinnacle West's             1-8962             3-27-02
                Incentive Plan (APS)                1999 Form 10-K Report

10.71(a)        2002 Senior Management              10.5 to Pinnacle West's             1-8962             3-27-02
                Variable Incentive Plan (APS)       1999 Form 10-K Report

10.72(a)        2002 Officer Variable               10.6 to Pinnacle West's             1-8962             3-27-02
                Incentive Plan (APS)                1999 Form 10-K Report

10.73           Agreement No. 13904 (Option         10.3 to 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

10.74           Agreement for the Sale and          10.4 to 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

10.75           Territorial Agreement               10.1 to March 1998                  1-4473             5-15-98
                between the Company                 Form 10-Q Report
                and Salt River Project

10.76           Power Coordination                  10.2 to March 1998                  1-4473             5-15-98
                Agreement between                   Form 10-Q Report
                the Company and Salt
                River Project

10.77           Memorandum of Agreement             10.3 to March 1998                  1-4473             5-15-98
                between the Company and             Form 10-Q Report
                Salt River Project
</TABLE>

                                      100
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
10.78           Addendum to Memorandum              10.2 to May 19, 1998                1-4473             6-26-98
                of Agreement between the            Form 8-K Report
                Company and Salt River
                Project dated as of May
                19, 1998

99.1            Collateral Trust Indenture          4.2 to 1992 Form 10-K               1-4473             3-30-93
                among PVNGS II Funding              Report
                Corp., Inc., the Company and
                Chemical Bank, as Trustee

99.2            Supplemental Indenture to           4.3 to 1992 Form 10-K               1-4473             3-30-93
                Collateral Trust Indenture          Report
                among PVNGS II Funding
                Corp., Inc., the Company and
                Chemical Bank, as Trustee

99.3(c)         Participation Agreement,            28.1 to September 1992              1-4473             11-9-92
                dated as of August 1, 1986,         Form 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, the Company, and
                the Equity Participant named
                therein
</TABLE>

                                      101
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
99.4(c)         Amendment No. 1 dated as            10.8 to September 1986              1-4473             12-4-86
                of November 1, 1986, to             Form 10-Q Report by
                Participation Agreement,            means of Amendment No.
                dated as of August 1,1986,          1, on December 3, 1986
                among PVNGS Funding                 Form 8
                Corp., Inc., Bank of America
                National Trust and Savings
                Association, State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston, in
                its individual capacity and as
                Owner Trustee, Chemical
                Bank, in its individual
                capacity and as Indenture
                Trustee, the Company, and
                the Equity Participant named
                therein

99.5(c)         Amendment No. 2, dated as           28.4 to 1992 Form 10-K              1-4473             3-30-93
                of 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, the
                Company, and the Equity
                Participant named therein
</TABLE>

                                      102
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
99.6(c)         Trust Indenture, Mortgage,          4.5 to Form S-3                     33-9480            10-24-86
                Security Agreement and              Registration 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

99.7(c)         Supplemental Indenture No.          10.6 to September 1986              1-4473             12-4-86
                1, dated as of November 1,          Form 10-Q Report by
                1986 to Trust Indenture,            means of Amendment No.
                Mortgage, Security Agree-           1 on December 3, 1986
                ment and Assignment of              Form 8
                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

99.8(c)         Supplemental Indenture No. 2        4.4 to 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 Indenture Trustee

99.9(c)         Assignment, Assumption and          28.3 to Form S-3                    33-9480            10-24-86
                Further Agreement, dated as         Registration Statement
                of August 1, 1986, between
                the Company and State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Owner Trustee
</TABLE>

                                      103
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
99.10(c)        Amendment No. 1, dated              10.10 to September 1986             1-4473             12-4-86
                as of November 1, 1986, to          Form 10-Q Report by
                Assignment, Assumption and          means of Amendment No.
                Further Agreement, dated as         1 on December 3, 1986
                of August 1, 1986, between          Form 8
                the Company and State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Owner Trustee

99.11(c)        Amendment No. 2, dated              28.6 to 1992 Form 10-K              1-4473             3-30-93
                as of March 17, 1993, to            Report
                Assignment, Assumption and
                Further Agreement, dated as
                of August 1, 1986, between
                the Company and State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Owner Trustee

99.12           Participation Agreement,            28.2 to September 1992              1-4473             11-9-92
                dated as of December 15,            Form 10-Q Report
                1986, among PVNGS
                Funding Corp., Inc., State
                Street Bank and Trust
                Company, as successor
                to The First National Bank
                of Boston, in its individual
                capacity and as Owner
                Trustee, Chemical Bank,
                in its individual capacity
                and as Indenture Trustee
                under a Trust Indenture,
                the Company, and the
                Owner Participant named
                therein
</TABLE>

                                      104
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
99.13           Amendment No. 1, dated              28.20 to Form S-3                   1-4473             8-10-87
                as of August 1, 1987, to            Registration Statement
                Participation Agreement,            No. 33-9480 by means of a
                dated as of December 15,            November 6, 1986 Form
                1986, among PVNGS                   8-K Report
                Funding Corp., Inc. as
                Funding Corporation, State
                Street Bank and Trust
                Company, as successor to
                The First National Bank of
                Boston, as Owner Trustee,
                Chemical Bank, as Indenture
                Trustee, the Company, and
                the Owner Participant named
                therein

99.14           Amendment No. 2, dated              28.5 to 1992 Form 10-K              1-4473             3-30-93
                as of March 17, 1993, to            Report
                Participation Agreement,
                dated as of December 15,
                1986, among PVNGS Fund-
                ing Corp., Inc., PVNGS II
                Funding Corp., Inc., State
                Street Bank and Trust
                Company, as successor to
                The First National Bank of
                Boston, in its individual
                capacity and as Owner
                Trustee, Chemical Bank, in
                its individual capacity and
                as Indenture Trustee, the
                Company, and the Owner
                Participant named therein

99.15           Trust Indenture, Mortgage,          10.2 to November 18, 1986           1-4473             1-20-87
                Security Agreement and              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>

                                      105
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
99.16           Supplemental Indenture No.          4.13 to Form S-3                    1-4473             8-24-87
                1, dated as of August 1, 1987,      Registration Statement
                to Trust Indenture, Mortgage,       No. 33-9480 by means of
                Security Agreement and              August 1, 1987 Form 8-K
                Assignment of 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 Owner
                Trustee, and Chemical Bank,
                as Indenture Trustee

99.17           Supplemental Indenture              4.5 to 1992 Form 10-K               1-4473             3-30-93
                No. 2 to Trust Indenture,           Report
                Mortgage, Security Agree-
                ment and Assignment of
                Facility Lease, dated as of
                December 15, 1986,
                between State Street Bank
                and Trust Company, as
                successor to The First
                National Bank of Boston,
                as Owner Trustee, and
                Chemical Bank, as Indenture
                Trustee

99.18           Assignment, Assumption and          10.5 to November 18, 1986           1-4473             1-20-87
                Further Agreement, dated as         Form 8-K Report
                of December 15, 1986,
                between the Company and
                State Street Bank and Trust
                Company, as successor to The
                First National Bank of
                Boston, as Owner Trustee
</TABLE>

                                      106
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
99.19           Amendment No. 1, dated              28.7 to 1992 Form 10-K              1-4473             3-30-93
                as of March 17, 1993, to            Report
                Assignment, Assumption
                and Further Agreement,
                dated as of December 15,
                1986, between the Company
                and State Street Bank and
                Trust Company, as successor
                to The First National Bank
                of Boston, as Owner Trustee

99.20(c)        Indemnity Agreement dated           28.3 to 1992 Form 10-K              1-4473             3-30-93
                as of March 17, 1993 by the         Report
                Company

99.21           Extension Letter, dated as of       28.20 to Form S-3                   1-4473             8-10-87
                August 13, 1987, from the           Registration Statement
                signatories of the                  No. 33-9480 by means of a
                Participation Agreement to          November 6, 1986 Form
                Chemical Bank                       8-K Report

99.22           Arizona Corporation                 28.1 to 1991 Form 10-K              1-4473             3-19-92
                Commission Order dated              Report
                December 6, 1991

99.23           Arizona Corporation                 10.1 to June Form 10-Q              1-4473             8-12-94
                Commission Order dated              Report
                June 1, 1994

99.24           Rate Reduction Agreement            10.1 to December 4, 1995            1-4473             12-14-95
                dated December 4, 1995              Form 8-K Report
                between the Company and
                the ACC Staff

99.25           Arizona Corporation                 10.1 to March 1996                  1-4473             5-14-96
                Commission Order                    Form 10-Q Report
                dated April 24, 1996

99.26           Arizona Corporation                 99.1 to 1996 Form 10-K              1-4473             3-28-97
                Commission Order,                   Report
                Decision No. 59943,
                dated December 26, 1996,
                including the Rules regard-
                ing the introduction of retail
                competition in Arizona
</TABLE>

                                      107
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                         ORIGINALLY FILED AS EXHIBIT:      FILE NO.(b)      DATE EFFECTIVE
-----------     -----------                         ----------------------------      -----------      --------------
<S>             <C>                                 <C>                               <C>              <C>
99.27           Retail Electric Competition         10.1 to June 1998                   1-4473             8-14-98
                Rules                               Form 10-Q Report

99.28           Arizona Corporation                 10.1 to September 1999              1-4473             11-15-99
                Commission Order,                   10-Q Report
                Decision No. 61973, dated
                October 6, 1999, approving
                our Settlement Agreement

99.29           Arizona Corporation                 10.2 to September 1999              1-4473             11-15-99
                Commission Order,                   10-Q Report
                Decision No. 61969, dated
                September 29, 1999, includ-
                ing the Retail Electric
                Competition Rules

99.30           Addendum to Settlement              10.1 to Pinnacle West               1-8962             11-14-00
                Agreement                           September 2000 10-Q

99.31           October 18, 2001                    99.6 to Pinnacle West               1-8962             10-19-01
                filing with the ACC                 October 18, 2001
                                                    8-K Report
</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 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 officers and key
     employees of the Company. 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.

                                       108
<PAGE>
REPORTS ON FORM 8-K

     During the quarter ended December 31, 2001 and the period ended March 27,
2002, the Company filed the following Reports on Form 8-K:

     Report dated October 2, 2001 comprised of Exhibits to the Company's
Registration Statements (Registration Nos. 333-58445 and 333-94277) relating to
the Company's offering of $400 million of Notes.

     Report dated October 18, 2001 regarding (i) the Arizona Supreme Court's
decision to review a lower court decision affirming the 1999 Settlement
Agreement; and (ii) the Company's October 18, 2001 filing with the ACC
requesting ACC approval of a rule variance and a purchase power agreement with
the Company.

     Report dated December 14, 2001 regarding the (i) Arizona Supreme Court
dismissal of an appeal related to the 1999 Settlement Agreement and (ii) new ACC
generic docket relating to electric restructuring in Arizona.

     Report dated February 8, 2002 regarding the consolidation of pending ACC
dockets.

     Report dated February 26, 2002 comprised of Exhibits to the Company's
Registration Statements (Registration Nos. 333-63994 and 333-83398) relating to
the Company's offering of $375 million of Notes.

                                      109
<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.


                                       ARIZONA PUBLIC SERVICE COMPANY
Date: March 27, 2002                   (Registrant)


                                       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         March 27, 2002
---------------------------------     Officer and Director
    (William J. Post, Chairman
  of the Board of Directors and
     Chief Executive Officer)


          Jack E. Davis               Principal Accounting        March 27, 2002
---------------------------------     Officer, President
    (Jack E. Davis, President)        and Director


        Michael V. Palmeri            Principal Financial         March 27, 2002
---------------------------------     Officer
       (Michael V. Palmeri,
     Vice President, Finance)


       Edward N. Basha, Jr.           Director                    March 27, 2002
---------------------------------
      (Edward N. Basha, Jr.)


       Michael L. Gallagher           Director                    March 27, 2002
---------------------------------
      (Michael L. Gallagher)


           Pamela Grant               Director                    March 27, 2002
---------------------------------
          (Pamela Grant)

                                      110
<PAGE>
      Roy A. Herberger, Jr.           Director                    March 27, 2002
---------------------------------
     (Roy A. Herberger, Jr.)


         Martha O. Hesse              Director                    March 27, 2002
---------------------------------
        (Martha O. Hesse)


     William S. Jamieson, Jr.         Director                    March 27, 2002
---------------------------------
    (William S. Jamieson, Jr.)


        Humberto S. Lopez             Director                    March 27, 2002
---------------------------------
       (Humberto S. Lopez)


        Robert G. Matlock             Director                    March 27, 2002
---------------------------------
       (Robert G. Matlock)


         Kathryn L. Munro             Director                    March 27, 2002
---------------------------------
        (Kathryn L. Munro)


        Bruce J. Nordstrom            Director                    March 27, 2002
---------------------------------
       (Bruce J. Nordstrom)


        William L. Stewart            President and               March 27, 2002
---------------------------------     Director
       (William L. Stewart)

                                       111
<PAGE>
                                                   Commission File Number 1-4473
================================================================================










                       SECURITIES AND EXCHANGE COMMISSION

                             WASHINGTON, D.C. 20549

                            -------------------------

                                   EXHIBITS TO

                                    FORM 10-K

                ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 2001

                            -------------------------

                         Arizona Public Service Company
               (Exact name of registrant as specified in charter)












================================================================================
<PAGE>
                                INDEX TO EXHIBITS

Exhibit No.       Description
-----------       -----------

12.1    --        Computation of Ratio of Earnings to Fixed Charges

23.1    --        Consent of Deloitte & Touche LLP


----------
For a description of the Exhibits incorporated in this filing by reference, see
Part IV, Item 14.