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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, 2000

                                       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                     (602) 250-1000
(Address of principal executive 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 13, 2001, there were issued and outstanding 71,264,947 shares
of the registrant's common stock, $2.50 par value, all of which were held
beneficially and of record by Pinnacle West Capital Corporation.

     THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I1(a)
AND (b) AND IS THEREFORE FILING THIS DOCUMENT WITH THE REDUCED DISCLOSURE
FORMAT.

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                                TABLE OF CONTENTS

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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 Security
              Holder Matters................................................  20
     Item 6.  Selected Financial Data.......................................  21
     Item 7.  Financial Review..............................................  22
     Item 7A. Quantitative and Qualitative Disclosures about Market Risk....  32
     Item 8.  Financial Statements and Supplementary Data...................  33
     Item 9.  Changes in and Disagreements with Accountants on Accounting
              and Financial Disclosure......................................  69

PART III
     Item 10. Directors and Executive Officers of the Registrant............  69
     Item 11. Executive Compensation........................................  69
     Item 12. Security Ownership of Certain Beneficial Owners and
              Management....................................................  69
     Item 13. Certain Relationships and Related Transactions................  69

PART IV
     Item 14. Exhibits, Financial Statements, Financial Statement Schedules,
              and Reports on Form 8-K.......................................  70

SIGNATURES..................................................................  94

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                                    GLOSSARY


ACC -- Arizona Corporation Commission

ACC Staff -- Staff of the Arizona Corporation Commission

AFUDC -- Allowance for Funds Used During Construction

AISA -- Arizona Independent Scheduling Administrator

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

APS -- Arizona Public Service Company

Cholla -- Cholla Power Plant

Cholla 4 -- Unit 4 of the Cholla Power Plant

Citizens - Citizens Communication Company

Company -- Arizona Public Service Company

CPUC -- California Public Utility Commission

DIG -- Derivatives Implementation Group

DOE -- United States Department of Energy

EITF -- Emerging Issues Task Force

EPA -- United States Environmental Protection Agency

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

1992 Energy Act -- National Energy Policy Act of 1992

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, an Arizona corporation, the
                 Company's parent

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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

SEC -- United States Securities and Exchange Commission

SFAS -- Statement of Financial Accounting Standards

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                                     PART I

                                ITEM 1. BUSINESS

     GENERAL

     We were incorporated in 1920 under the laws of Arizona and are Arizona's
largest electric utility, with more than 850,000 customers. We provide wholesale
or retail electric service to the entire state of Arizona, with the exception of
Tucson and about one-half of the Phoenix area. We also generate and, directly or
through Pinnacle West's power marketing division, sell and deliver electricity
to wholesale customers in the western United States. During 2000, no single
purchaser or user of energy accounted for more than 3.5% of total electric
revenues.

     At December 31, 2000, we employed about 5,300 people, which includes
employees assigned to joint projects where we are project manager. Our principal
executive offices are located at 400 North Fifth Street, Phoenix, Arizona 85004
(telephone 602-250-1000).

     See Note 16 of Notes to Financial Statements in Item 8 for a discussion of
our business segments.

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; the outcome of regulatory and
legislative proceedings relating to the restructuring; regional economic and
market conditions, including the California energy situation, 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; 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 "Financial Review - Business Outlook -
Competition and Industry Restructuring" in Item 7 and Note 3 of Notes to
Financial Statements in Item 8 for a discussion of electric industry
restructuring in Arizona, including our 1999 Settlement Agreement, the ACC
retail electric competition rules, and the legal challenges to both the 1999
Settlement Agreement and 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 customers under rates that have been approved by the ACC.
These rates are fixed until July 1, 2004. The 1999 Settlement

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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 year, have been
volatile. At various times, prices in the spot wholesale market have
significantly exceeded the amount included in our current retail rates. We
expect these market conditions to continue in 2001. We believe that our current
generation portfolio has been adequately supplemented with power purchased
through contracts and hedging techniques that limit exposure to the volatile
spot wholesale power market. However, 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.

     As discussed in "Financial Review - Electric Competition (Retail)" in Item
7 and in Note 3 of Notes to Financial Statements in Item 8, the 1999 Settlement
Agreement authorizes us to transfer our competitive generation assets and
services to one or more corporate affiliates no later than December 31, 2002. We
intend to move our generation assets to Pinnacle West Energy within that
timeframe. Following its receipt of these generation assets, Pinnacle West
Energy expects to sell its power at wholesale to Pinnacle West's power marketing
division (Power Marketing). Power Marketing, in turn, is expected to sell power
to us and to non-affiliated power purchasers. We expect to meet fifty percent of
our energy needs under a power purchase agreement with Power Marketing. As
required by the Rules, we will acquire the remaining fifty percent of our energy
needs through a competitive bid process in which Power Marketing may
participate. We believe that these arrangements will allow us to manage our
exposure to the wholesale power market during the period within which our rates
are fixed, as discussed in the preceding paragraph.

     In addition to the introduction of competition pursuant to the 1999
Settlement Agreement and the Rules, 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
preferential low-priced 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

     We compete with other utilities, power marketers, and independent power
producers in the sale of electric capacity and energy in the wholesale market.
We expect competition in the wholesale market will remain vigorous. The FERC
regulates rates for wholesale power sales and transmission services. During
2000, approximately 46% of our electric operating revenues resulted from such
sales and services. We transferred the wholesale power marketing function to
Pinnacle West during 2000.

     The 1992 Energy Act and the FERC's rulemaking activities have established
the regulatory framework to open the wholesale energy market to competition. The
1992 Energy Act permits utilities to develop independent electric generating
plants for sales to wholesale customers, and authorizes the FERC to order
transmission access for third parties to transmission facilities owned by
another entity. The 1992 Energy Act does not, however, permit the FERC to
require transmission access to retail customers. Open-access transmission for
wholesale customers provides energy suppliers, including us, with opportunities
to sell and deliver electricity at market-based prices.

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     On December 20, 1999, the FERC issued its Order No. 2000 regarding Regional
Transmission Organizations (RTO). In its order, the FERC stressed the voluntary
nature of RTO participation by utilities and 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. As required by the FERC order, we, along with several
neighboring transmission owners located in the southwestern United States, filed
a report with the FERC on October 16, 2000 that detailed the progress in
establishing an RTO that would be responsible for ensuring transmission
reliability and nondiscriminatory access to the regional transmission grid. We
expect that Desert STAR, the non-profit corporation named in the filing, will
make additional filings with the FERC in the near future to establish itself as
an RTO for the region.

     See "Financial Review - Business Outlook - California Energy Market Issues"
in Item 7 for a discussion of the energy situation in California.

     The ACC retail electric competition rules require the formation and
implementation of an Arizona Independent Scheduling Administrator Association.
The AISA is anticipated to be a temporary organization until the formation and
implementation of an independent system operator or RTO. We, as an "Affected
Utility" under the Rules, participated in the creation of the AISA. Recently,
the board of AISA approved a set of operating protocols that have been filed
with the FERC. The operating protocols were partially rejected and the remainder
are currently under review.

     See "Financial Review - Business Outlook - Competition and Industry
Restructuring" in Item 7 and Note 3 of Notes to Financial Statements in Item 8
for additional information about the ACC Rules and the legal challenges to the
Rules.

     REGULATORY ASSETS

     Our major regulatory assets are deferred income taxes and rate
synchronization cost deferrals. As a result of our 1999 Settlement Agreement, we
discontinued the application of SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation," 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. Prior to the 1999 Settlement Agreement,
under a 1996 regulatory agreement, 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 being amortized pursuant to a revised amortization
schedule. See Notes 1, 3, and 9 of Notes to Financial Statements in Item 8 for
additional information.

                                       5
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GENERATING FUEL AND PURCHASED POWER

     2000 ENERGY MIX

     Our sources of energy during 2000 were: purchased power - 46.0%
(approximately 88% of which was for wholesale power operations); coal - 27.9%;
nuclear - 19.8%; gas - 6.0%; and other (including oil, hydro and solar) - 0.3%.

     COAL SUPPLY

     CHOLLA We purchase most of Cholla's coal requirements from a coal supplier
who 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 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 We purchase all of Four Corners' coal requirements from a coal
supplier with a long-term lease of coal reserves owned by the Navajo Nation.
Four Corners is under contract for coal through 2004, with options to extend the
contract through the plant site lease expiration in 2017. The Four Corners lease
waives, until July 2001, the requirement that we and our fuel supplier pay
certain taxes to the Navajo Nation. The coal supplier currently pays a
possessory interest tax to the Navajo Nation, which is reimbursed by the Four
Corners participants. The coal supplier, the Navajo Nation, and the Four Corners
participants agreed to investigate alternative contractual arrangements and
business relationships before the expiration of tax waivers in an effort to
permit the electricity generated at Four Corners to be priced competitively. We
anticipate that the Navajo Nation will levy additional taxes upon the expiration
of the tax waivers; however, we cannot currently predict the outcome of this
matter or the amount of any additional taxes.

     NAVAJO GENERATING STATION 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.

                                       6
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     See "Properties - Accredited Capacity" in Item 2 for information about our
ownership interest in Cholla, Four Corners, and the Navajo Generating Station.
See Note 12 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 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. We continue to analyze the market to determine the most favorable
source and method of meeting our natural gas requirements.

     NUCLEAR FUEL SUPPLY

     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 made contractual arrangements to obtain
quantities of uranium concentrates anticipated to be sufficient 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:

     *    77% of requirements in 2003;
     *    77% of requirements in 2004;
     *    44% of requirements in 2005 through 2007; and
     *    16% of requirements in 2008 and beyond.

     The Palo Verde participants have contracts and options for uranium
conversion services that could be utilized to meet approximately:

     *    75% of requirements in 2001; and
     *    80% of requirements in 2002.

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

     We are currently pursuing several offers to procure the uranium, conversion
services and the enrichment services components of nuclear fuel to meet all of
Palo Verde's requirements through 2008.

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     SPENT NUCLEAR FUEL AND WASTE DISPOSAL Pursuant to the Nuclear Waste Act,
the DOE must accept and dispose of all spent nuclear fuel and other high-level
radioactive wastes generated by domestic power reactors. The NRC requires
operators of nuclear power reactors to enter into spent fuel disposal contracts
with the DOE. Under the Nuclear Waste Act, the DOE was to develop a permanent
repository for the storage and disposal of spent nuclear fuel by 1998. The DOE
has announced that such a permanent 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 precluding the DOE from
excusing its own delay, but refused to order the DOE to begin accepting spent
nuclear fuel. Based on this decision, a number of utilities filed damages
lawsuits against DOE in the Court of Federal Claims. In decisions that became
final in December 2000, the United States Court of Appeals for the Federal
Circuit held that utilities do not have to exhaust the DOE administrative claims
before filing lawsuits for damages against the DOE in the Court of Federal
Claims.

     Bills have been introduced in prior sessions of the U.S. Congress
contemplating the construction of a central interim storage facility, but no
bill has been enacted into law. We cannot currently predict what steps will be
taken in this area by the current Congress and the Administration.

     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).
According to DOE spokespersons, the fund may now be at a level less than needed
to achieve a 2010 operational date for a permanent repository. No funding will
be available for a central interim facility until one is authorized by Congress.

     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 12
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 also 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.

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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
322 MW from January through May 2000, and starting June 2000, it changed to 329
MW. In 2000, we received approximately 1,422,000 MWh of energy under the
contract and paid about $76.7 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 this
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, PacifiCorp and APS each has 480 MW per hour of
capacity and a related amount of energy available to it under the agreement for
our respective seasons. In 2000, we received approximately 396,000 MWh of energy
under the capacity exchange. We must also make additional offers of energy to
PacifiCorp each year through October 31, 2020. Pursuant to this requirement,
during 2000, PacifiCorp received offers of 865,800 MWh and purchased about
218,000 MWh.

CONSTRUCTION PROGRAM

     During the years 1998 through 2000, we incurred approximately $1.2 billion
in capital expenditures. Our capital expenditures for the years 2001 through
2003 are expected to be primarily for expanding transmission and distribution
capabilities to meet growing customer needs, upgrading existing utility
property, and for environmental purposes. Our capital expenditures, including
expenditures for environmental control facilities, for the years 2001 through
2003 have been estimated as follows:

                              (DOLLARS IN MILLIONS)

               BY YEAR                              BY MAJOR FACILITIES
-------------------------------------      -------------------------------------
2001                           $  455      Production                     $  226
2002                              401      Transmission and Distribution     924
2003                              294                                     ------
                               ------      Total                          $1,150
Total                          $1,150                                     ======
                               ======

     The amounts for 2001 through 2003 exclude capitalized interest costs and
include capitalized property taxes and about $30-$35 million annually (except
2003) for nuclear fuel. We conduct a continuing review of our construction
program. See "Financial Review - Capital Needs and Resources" in Item 7 for
additional information.

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"

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requirement by using redeemed or retired bonds, net property additions, or
property retirements. For 2000, the replacement fund requirement amounted to
approximately $149 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 so redeemed.

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.

     With respect to "acid rain," the Clean Air Act establishes 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 within 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 requires 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 includes the application of best
available

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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 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 Court further held that the EPA could not consider the cost
of reducing harmful emissions when setting air quality standards. However, the
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.

                                       11
<PAGE>
     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 the cost of any necessary remediation of
the substances. 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. We are in the process of conducting an
investigation to determine the extent and scope of contamination at the plant
site. 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 at one time 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 remediation 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.

     PURPORTED NAVAJO ENVIRONMENTAL REGULATION

     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 Acts). Pursuant to the Acts, the
Navajo Nation Environmental Protection Agency is authorized to promulgate
regulations covering air quality, drinking water, and pesticide activities,
including those that occur at Four Corners and the Navajo Generating Station. 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 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 Acts to the operations of Four Corners and the Navajo
          Generating Station; and

                                       12
<PAGE>
     *    the Navajo Nation and its agencies and courts lack adjudicatory
          jurisdiction to determine the enforceability of the 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 promulgated regulations specifying those
provisions of the Clean Air Act for which it is appropriate to treat Indian
tribes in the same manner as states. The EPA indicated that it believes that the
Clean Air Act generally would supersede pre-existing binding agreements that may
limit the scope of tribal authority over reservations. On April 10, 1998, we
filed a Petition for Review in the United States Court of Appeals for the
District of Columbia. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES
ENVIRONMENTAL PROTECTION AGENCY, No. 98-1196. On February 19, 1999, the EPA
promulgated regulations setting forth the EPA's approach to issuing Federal
operating permits to covered stationary sources on Indian reservations. On April
15, 1999, we filed a Petition for Review in the United States Court of Appeals
for the District of Columbia. ARIZONA PUBLIC SERVICE COMPANY V. UNITED STATES
ENVIRONMENTAL PROTECTION AGENCY, No. 99-1146. After the litigation was filed,
the EPA indicated it had not determined whether the Clean Air Act would
supersede pre-existing binding agreements involving Four Corners and the Navajo
Generating Station. On May 5, 2000, the United States Court of Appeals for the
District of Columbia upheld the EPA's regulations on treatment of Indian tribes
in the same manner as states. However, the Court determined that the impact of
this ruling on the pre-existing binding agreements involving Four Corners and
the Navajo Generating Station was not ripe for adjudication because the EPA had
not made a determination that the Clean Air Act superseded those agreements. On
June 29, 2000, at the request of the Court, we filed a motion to dismiss Four
Corners from this petition on the grounds that the impact of the regulations on
pre-existing binding agreements was not "ripe" for judicial resolution based on
the EPA's issuance of an official notice indicating that it had not yet
determined whether the pre-existing binding agreements with Four Corners and
Navajo Generating Station were abrogated by the Clean Air Act. The Court
ultimately dismissed Four Corners on these grounds.

     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 Tribe 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 in recent years.

     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.

                                       13
<PAGE>
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 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. The Arizona Supreme Court
issued a decision confirming that certain groundwater rights may be available to
the federal government and Indian tribes. We and other parties petitioned the
U.S. Supreme Court for review of this decision and the petition was denied. In
addition, the Arizona Supreme Court issued a decision affirming the lower
court's criteria for solving groundwater claims. We and other parties filed
motions for reconsideration on one aspect of that decision. Those motions have
been denied by the Arizona Supreme Court. Litigation on both of these issues
will continue in the trial court. No trial date concerning APS' water rights
claims has been set in this matter.

     We have also filed claims to water in the Little Colorado River Watershed
in Arizona in an action pending in the Apache County 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. The parties are in the
process of settlement negotiations with respect to this matter. 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.

                                       14
<PAGE>
                               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
                                                                   ----------

                                                                    1,712,000
Gas or Oil:
  Two steam units at Ocotillo and two steam units at Saguaro....      435,000(1)
  Eleven combustion turbine units...............................      493,000
  Three combined cycle units....................................      255,000
                                                                   ----------

                                                                    1,183,000
Nuclear:
  29.1% owned or leased Units 1, 2, and 3 at Palo Verde.........    1,086,300
                                                                   ----------

Hydro and Solar.................................................        6,000
                                                                   ----------

  Total                                                             3,987,300
                                                                   ==========

----------
(1)  West Phoenix steam units (108,300 kW) are currently mothballed, but are
     expected to be back in service by summer 2001.

RESERVE MARGIN

     Our 2000 peak one-hour demand on its electric system was recorded on July
25, 2000 at 5,478,500 kW, compared to the 1999 peak of 4,934,700 kW recorded on
August 24. Taking into account additional capacity then available to us under
long-term purchase power contracts as well as our own generating capacity, our
capability of meeting system demand on July 25, 2000, amounted to 4,774,600 kW,
for an installed reserve margin of (15.3%). 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 2000 peak amounted to 3,501,600 kW, for a margin of (27.5%).
Firm purchases, including short-term seasonal purchases, totaling 2,238,000 kW
were in place at the time of the peak ensuring the ability to meet the load
requirement, with an actual reserve margin of 6.4%.

                                       15
<PAGE>
     See "Business - 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.

     See "Generating Fuel and Purchased Power - Coal Supply" in Item 1 for a
discussion of changes in the amount of royalty payments and expiration of tax
waivers under the Navajo Generating Station and Four Corners leases.

PALO VERDE NUCLEAR GENERATING STATION

     PALO VERDE LEASES

     See Note 9 of Notes to Financial Statements in Item 8 for a discussion of
three sale and 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 an external sinking fund 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 ACC jurisdictional rates. ACC retail electric competition
rules provide that decommissioning costs would be recovered through a
non-bypassable "system benefits" charge, which would allow us to maintain our
external sinking fund mechanism. See Note 13 of Notes to Financial Statements in
Item 8 for additional information about our nuclear decommissioning costs. See
"Financial Review - Business Outlook - Competition and Industry Restructuring"
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.

                                       16
<PAGE>
     PALO VERDE LIABILITY AND INSURANCE MATTERS

     See "Palo Verde Nuclear Generating Station" in Note 12 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 "Financial Review ___ Capital
Needs and Resources" in Item 7 for a discussion of our construction plans.

     See Notes 5, 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,  our Service  Territory map contained in this Form 10-K is a map of
the State of Arizona  showing the Company's  service  area,  the location of its
major  power  plants and  principal  transmission  lines,  and the  location  of
transmission  lines  operated by the Company for others.  The 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. The
Company's  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

     In June 1999, the Navajo Nation served Salt River Project with a lawsuit
naming Salt River Project, several Peabody Coal Company entities, Southern
California Edison Company and other defendants, and citing various claims in
connection with the renegotiations of the coal royalty and lease agreements
under which Peabody mines coal for Navajo Generating Station and the Mohave
Generating Station. THE NAVAJO NATION V. PEABODY HOLDING COMPANY, INC., ET AL.,
UNITED STATES DISTRICT COURT FOR THE DISTRICT OF COLUMBIA, CA-99-0469-EGS. We
are a 14% owner of the Navajo Generating Station, which Salt River Project
operates. The suit alleges, among other things, that the defendants obtained a
favorable coal royalty rate by improperly influencing the outcome of a federal
administrative process under which the royalty rate was to be adjusted. The suit
seeks $600 million in damages, treble damages, punitive damages of not less than
$1 billion, and the ejection of defendants "from all possessory interests and
Navajo Tribal lands" arising out of the [primary coal lease]. Salt River Project
has advised us that it denies all charges and will vigorously defend itself.
Because the litigation is in preliminary stages, we cannot currently predict the
outcome of this matter.

     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.

We are a party to a power service agreement with Citizens Communications Company
under which we supply Citizens with power. By letter dated March 7, 2001,
Citizens advised us that it believes we have overcharged Citizens by over $50
million under the agreement since the summer of 2000. We believe that our
charges to Citizens under the agreement are fully in accordance with the terms
of the agreement and we will vigorously defend any contrary claims raised by
Citizens.

                       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 SECURITY HOLDER MATTERS

     The Company's 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 the Company's common stock.

     The chart below sets forth the dividends declared on the Company's common
stock for each of the four quarters for 2000 and 1999.

                             COMMON STOCK DIVIDENDS
                             (DOLLARS IN THOUSANDS)

       QUARTER                                  2000                 1999
       -------                                 -------              -------
     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 5 of Notes to
Financial Statements in Item 8 for restrictions on retained earnings available
for the payment of common stock dividends.

                                       20
<PAGE>
                         ITEM 6. SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
                                                    2000           1999          1998          1997          1996
                                                 -----------    -----------   -----------   -----------   -----------
                                                                        (Dollars in Thousands)
<S>                                              <C>            <C>           <C>           <C>           <C>
Electric operating revenues ..................   $ 3,480,252    $ 2,292,798   $ 2,006,398   $ 1,878,553   $ 1,718,272
Fuel and purchased power .....................     1,880,729        795,494       545,297       443,571       329,489
Operating expenses ...........................     1,148,628      1,108,380     1,090,290     1,063,157     1,023,575
                                                 -----------    -----------   -----------   -----------   -----------
  Operating income ...........................       450,895        388,924       370,811       371,825       365,208
Other income/(expense) .......................        (6,412)        20,990        20,448        21,586        35,217
Interest deductions -- net ...................       137,889        141,592       136,012       141,918       156,954
                                                 -----------    -----------   -----------   -----------   -----------
  Income before extraordinary charge .........       306,594        268,322       255,247       251,493       243,471
  Extraordinary charge - net of tax ..........            --        139,885            --            --            --
                                                 -----------    -----------   -----------   -----------   -----------
  Net income .................................       306,594        128,437       255,247       251,493       243,471
  Preferred dividends ........................            --          1,016         9,703        12,803        17,092
                                                 -----------    -----------   -----------   -----------   -----------

  Earnings for common stock ..................   $   306,594    $   127,421   $   245,544   $   238,690   $   226,379
                                                 ===========    ===========   ===========   ===========   ===========

Total Assets .................................   $ 6,399,715    $ 6,117,624   $ 6,393,299   $ 6,331,142   $ 6,423,222
                                                 ===========    ===========   ===========   ===========   ===========

Capital Structure:
  Common stock equity ........................   $ 2,119,768    $ 1,983,174   $ 1,975,755   $ 1,849,324   $ 1,729,390
  Non-redeemable preferred stock .............            --             --        85,840       142,051       165,673
  Redeemable preferred stock .................            --             --         9,401        29,110        53,000
  Long-term debt less current maturities......     1,806,908      1,997,400     1,876,540     1,953,162     2,029,482
                                                 -----------    -----------   -----------   -----------   -----------
    Total capitalization .....................     3,926,676      3,980,574     3,947,536     3,973,647     3,977,545
  Commercial paper ...........................        82,100         38,300       178,830       130,750        16,900
  Current maturities of long-term debt........       250,266        114,711       164,378       104,068       153,780
                                                 -----------    -----------   -----------   -----------   -----------
    Total ....................................   $ 4,259,042    $ 4,133,585   $ 4,290,744   $ 4,208,465   $ 4,148,225
                                                 ===========    ===========   ===========   ===========   ===========
</TABLE>

     See "Financial Review" in Item 7 for a discussion of certain information in
the foregoing table.

                                       21
<PAGE>
                            ITEM 7. FINANCIAL REVIEW

INTRODUCTION

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

     *    the changes in our earnings from 1999 to 2000 and from 1998 to 1999;

     *    the effects of regulatory agreements on our results and outlook;

     *    our capital needs and resources;

     *    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 retail and wholesale
electric service to the entire state with the exception of Tucson and about
one-half of the Phoenix area. We also generate and, directly or through Pinnacle
West's power marketing division, sell and deliver electricity to wholesale
customers in the western United States. Pinnacle West owns all of our
outstanding common stock.

     Throughout this Financial Review, we refer to specific "Notes" in the Notes
to Financial Statements that begin on page 42. These Notes add further details
to the discussion.

RESULTS OF OPERATIONS

     2000 COMPARED WITH 1999

     Our 2000 earnings were $307 million compared with $127 million in 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 investment tax credit (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 10 for additional information about ITC amortization.

     In 2000, electric operating revenues increased $1.2 billion primarily
because of:

                                       22
<PAGE>
     *    increased wholesale revenues ($1.1 billion);

     *    increases in the number of retail electricity customers and the
          average amount of electricity used by customers ($98 million); and

     *    weather impacts ($33 million).

     As mentioned above, these positive factors were partially offset by the
effects of reductions in retail electricity prices ($28 million).

     The increase in wholesale revenues resulted primarily from higher prices
and increased activity in western United States wholesale power markets. These
revenues were accompanied by increases in purchased power and fuel expense of
$1.0 billion.

     Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased prices.

     The increase in operations and maintenance expenses, which primarily
related to customer growth, was substantially offset by $19 million of
non-recurring items recorded in 1999.

     1999 COMPARED WITH 1998

     Our 1999 earnings were $127 million compared with $246 million in 1998. Our
1999 earnings decreased $119 million from 1998 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 $21 million, or 9%,
over 1998 primarily because of increases in retail electricity revenues and
lower financing costs. These positive factors more than offset the effects of
retail electricity price reductions and higher utility operations and
maintenance expense. See "Regulatory Agreements" below and Note 3 for additional
information about the price reductions.

     In 1999, electric operating revenues increased $286 million primarily
because of:

     *    increased wholesale revenues ($219 million);

     *    increases in retail electricity customers and the average amount of
          electricity used by customers ($81 million); and

     *    miscellaneous factors ($8 million).

     As mentioned above, these positive factors were partially offset by the
effects of reductions in retail prices ($22 million).

                                       23
<PAGE>
     The increase in wholesale revenues resulted from higher prices and
increased activity in western United States wholesale markets. The revenues were
accompanied by an increase in purchased power expenses. Although these
activities contributed positively to earnings in both periods, the contribution
in 1999 was lower than in 1998.

     Operations and maintenance expenses increased $18 million primarily because
of $19 million of non-recurring items recorded in 1999, including a provision
for certain environmental costs. Other increases primarily related to customer
growth were partially offset by lower employee benefit costs.

     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.

     1999 SETTLEMENT AGREEMENT

     As part of the 1999 Settlement Agreement, we agreed to reduce retail
electricity prices for standard, full offer 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 now
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

                                       24
<PAGE>
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 annual 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 10).

CAPITAL NEEDS AND RESOURCES

     CAPITAL RESOURCES AND CASH REQUIREMENTS

     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.

     During the period from 1998 through 2000, we paid for substantially all of
our capital expenditures with cash from operations. We expect to do so in 2001
through 2003, as well.

     Our capital expenditures in 2000 were $472 million. Our projected capital
expenditures for the next three years are: $455 million in 2001; $401 million in
2002; and $294 million in 2003. These amounts include about $30 - $35 million
each year for nuclear fuel. In general, most of our projected capital
expenditures are for:

     *    expanding transmission and distribution capabilities to serve growing
          customer needs;

     *    upgrading existing utility property; and

     *    environmental purposes.

                                       25
<PAGE>
     During 2000, we redeemed approximately $357 million of long-term debt,
including premiums, with cash from operations and from the issuance of long- and
short-term debt. Our long-term debt redemption requirements for the next three
years are approximately: $380 million in 2001; $125 million in 2002; and zero in
2003. We made optional redemptions of about $13 million of long-term debt in
February 2001. Based on market conditions and optional call provisions, we may
make optional redemptions of long-term debt from time to time.

     As of December 31, 2000, 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 as bank borrowings. At the end of 2000, we had
about $82 million of commercial paper and no long-term bank borrowings
outstanding.

     Our long-term debt was $2.1 billion at December 31, 2000 and 1999.

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

ACCOUNTING MATTERS

     We adopted a new standard on accounting for derivatives in 2001. As a
result, in January 2001 we recognized a $3 million after-tax loss in net income
as a cumulative effect of a change in accounting principles and a $64 million
after-tax gain in equity (as a component of other comprehensive income). The
gain resulted from unrealized gains on cash flow hedges. There are still several
unresolved issues related to the application of certain provisions of this new
standard as it relates to the electric utility industry. The ultimate resolution
of these issues by the Financial Accounting Standards Board (FASB) could result
in a material impact to our financial statements and increased volatility in
future net income and comprehensive income. See Note 2 for further information.
Also, see Note 2 for a description of a proposed standard on accounting for
certain liabilities related to closure or removal of long-lived assets.

     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.

BUSINESS OUTLOOK

     This section describes several major factors affecting our financial
outlook.

                                       26
<PAGE>
     COMPETITION AND INDUSTRY RESTRUCTURING

     ELECTRIC COMPETITION (WHOLESALE)

     The National Energy Policy Act of 1992 (1992 Energy Act) and the FERC's
subsequent rulemaking activities have established the regulatory framework to
open the wholesale electricity market to competition. The 1992 Energy Act
amended provisions of the Public Utility Holding Company Act of 1935 and the
Federal Power Act to remove certain barriers to a competitive wholesale market.
The 1992 Energy Act permits utilities to participate in the development of
independent electric generating plants for electricity sales to wholesale
customers, and also permits the FERC to order transmission access for third
parties to transmission facilities owned by another entity. The 1992 Energy Act
does not, however, permit the FERC to issue an order requiring transmission
access to retail customers. Open-access transmission for wholesale customers as
defined by the FERC's final rules provides energy suppliers, including us, with
opportunities to sell and deliver electricity at market-based prices.

     ELECTRIC COMPETITION (RETAIL)

     On September 21, 1999, the Arizona Corporation Commission (ACC) voted to
approve the rules that provide a framework for the introduction of retail
electric competition in Arizona (the Rules). Among other things, the Rules
require most utilities, including us, to transfer all competitive generation
assets and services either to an unaffiliated party or to a separate corporate
affiliate. The Rules require the transfer to take place by January 1, 2001,
absent a waiver. We received a waiver in the 1999 Settlement Agreement to allow
the transfer of our competitive generation assets and services to affiliates 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 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 customers under rates that have been approved by the ACC.
These rates are fixed 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 year, have been volatile. At various times
prices in the spot wholesale market have significantly exceeded the amount
included in our current retail rates. We expect these market conditions to
continue in 2001. We believe we have adequately supplemented our current
generation portfolio with power purchased through contracts and hedging
techniques that limit exposure to the volatile spot wholesale power market.
However, 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.

     As discussed in Note 3 of Notes to Financial Statements in Item 8, the 1999
Settlement authorizes us to transfer our competitive generation assets and
services to one or more corporate affiliates no later than December 31, 2002. We
intend to move our generation assets to Pinnacle West Energy within that
timeframe. Following its receipt of these generation assets,

                                       27
<PAGE>
Pinnacle West Energy expects to sell its power at wholesale to Pinnacle West's
power marketing division (Power Marketing). Power Marketing, in turn, is
expected to sell power to us and to non-affiliated power purchasers. We expect
to meet fifty percent of our energy needs under a power purchase agreement with
Power Marketing. As required by the Rules, we will acquire the remaining fifty
percent of our energy needs through a competitive bid process in which Power
Marketing may participate. We believe that these arrangements will allow us to
manage our exposure to the wholesale power market during the period within which
our rates are fixed, as discussed in the preceding paragraph.

     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. Several rural electric
cooperatives and the Arizona Consumers Council, a private non-profit public
interest group (represented by the Arizona Center for Law in the Public
Interest, also a private non-profit public interest organization) have filed
court challenges to the Rules. Although these actions do not directly challenge
the divestiture provisions of the Rules, they do raise fundamental
constitutional issues concerning the ability of the ACC to permit the forces of
competition to determine retail electric prices.

     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 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 Court of Appeals, as a
result of which the ruling is automatically stayed pending further judicial
review.

     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 our 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. A decision is still pending on the other appeal,
which raises a number of different issues.

     Neither party challenging the 1999 Settlement Agreement has raised issues
regarding the 1999 Settlement Agreement that could not be remedied by the ACC if
the Arizona Court of Appeals remands the 1999 Settlement Agreement to the ACC.
However, it is impossible to predict with certainty exactly what the ACC would
do in the event the order approving the 1999 Settlement Agreement were
invalidated, either in whole or in part. Even aside from the pending litigation,
the ACC retains continuing jurisdiction over all orders issued by it and can
attempt to "rescind, alter or amend" such order under appropriate circumstances
and upon notice and hearing.

     In May 1998, a law was enacted by the Arizona legislature to facilitate
implementation of retail electric competition in the state. Additionally,
legislation related to electric competition has been proposed in the United
States Congress. See Note 3 for additional information about the Rules, the 1999
Settlement Agreement, the ongoing litigation related to each, and for
legislative developments.

                                       28
<PAGE>
     As a result of the foregoing matters, as well as energy market
developments, particularly in California (see "California Energy Market Issues"
below), electric utility restructuring is in a state of flux in the western
United States and around the country.

     CALIFORNIA ENERGY MARKET ISSUES

     Southern California Edison (SCE) and PG&E Corp. (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
California Power Exchange (PX) and California Independent System Operator (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 power marketing exposures. Based upon the financial transactions to
date, we do not believe the foregoing matters will have a material adverse
effect on our financial position or 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.

     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.

     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 3.8% a year for
the three years 1998 through 2000; we currently expect customer growth to
average 3.5% to 4% a year for 2001 through 2003. We currently estimate that
retail electricity sales in kilowatt-hours will grow 3.5% to 4.5% a year in 2001
through 2003, 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.

     Wholesale activities will be affected by electricity prices and costs of
available fuel and purchased power in the western United States, as well as
competitive market conditions and regulatory and legislative changes in various
state and federal jurisdictions. These factors have significantly affected our
wholesale power activities and their resultant earnings contributions over the
last several years. We cannot predict future contributions from wholesale
activities.

     OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS

     Fuel and purchased power costs are impacted by our electricity sales
volumes, existing contracts for generation fuel and purchased power, our power
plant performance, prevailing market prices, and our hedging program for
managing such costs.

                                       29
<PAGE>
     Operations and maintenance expenses are expected to be affected by sales
mix and volumes, inflation, 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. 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.

     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.

     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.

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 13). 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, 2000 and December 31, 1999. The interest rates
presented in the tables below represent the weighted average interest rates for
the years ended December 31, 2000 and December 31, 1999.

                                       30
<PAGE>
Expected Maturity/Principal Repayment
December 31, 2000
(dollars in thousands)

                      Short-Term        Variable Long-Term     Fixed Long-Term
                  ------------------    ------------------    ------------------
                 Interest              Interest              Interest
                  Rates     Amount      Rates     Amount      Rates     Amount
                  -----   ----------    -----   ----------    -----   ----------
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
                          ==========            ==========            ==========

Expected Maturity/Principal Repayment
December 31, 1999
(dollars in thousands)

                      Short-Term        Variable Long-Term     Fixed Long-Term
                  ------------------    ------------------    ------------------
                 Interest              Interest              Interest
                  Rates     Amount      Rates     Amount      Rates     Amount
                  -----   ----------    -----   ----------    -----   ----------
2000               5.33%  $   38,300            $              5.79%  $  114,711
2001                 --           --     6.85%     250,000     7.48%       2,488
2002                 --           --                           8.13%     125,000

2003                 --           --     5.50%      50,000
2004                 --           --                           6.17%     205,000
Years thereafter     --           --     3.15%     476,860     7.87%     895,148
                          ----------            ----------            ----------
Total                     $   38,300            $  776,860            $1,342,347
                          ==========            ==========            ==========
Fair value                $   38,300            $  776,860            $1,312,423
                          ==========            ==========            ==========

     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/credits. In addition, subject to specified risk parameters, 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

                                       31
<PAGE>
are marked to market. These trading activities are part of our wholesale
activities and are reflected in the wholesale revenues and expenses.

     As of December 31, 2000, a hypothetical adverse price movement of 10% in
the market price of our commodity derivative portfolio would have decreased the
fair market value of these contracts by approximately $29 million, compared to a
$6 million decrease that would have been realized as of December 31, 1999. The
increase in this exposure over 1999 is a result of the increased volume of
hedged positions and increased prices in this portfolio. This analysis does not
include the favorable impact this same hypothetical price move would have had on
certain underlying physical exposures being hedged with the commodity derivative
portfolio.

     We are exposed to losses in the event of non-performance or non-payment by
counterparties. We use a risk management process to assess and monitor the
financial exposure of counterparties. Despite the fact that the great majority
of trading counterparties are rated as investment grade by the credit rating
agencies, there is still a possibility that one or more of these companies could
default, resulting in a material impact on earnings for a given period.

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; the outcome of the regulatory
proceedings relating to the restructuring; regional economic and market
conditions, including the California energy situation, 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; 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.

                                       32
<PAGE>
               ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                        INDEX TO FINANCIAL STATEMENTS AND
                          FINANCIAL STATEMENT SCHEDULE

Report of Management........................................................  34
Independent Auditors' Report................................................  35
Statements of Income for 2000, 1999 and 1998................................  37
Balance Sheets as of December 31, 2000 and 1999.............................  38
Statements of Cash Flows for 2000, 1999 and 1998............................  40
Statements of Retained Earnings for 2000, 1999 and 1998.....................  41
Notes to Financial Statements...............................................  42


See Note 14 of Notes to Financial Statements for the selected quarterly
financial data required to be presented in this Item.

                                       33
<PAGE>
                              REPORT OF MANAGEMENT

     The primary 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 and our independent auditors to test for compliance. 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.

     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                 Pinnacle West Capital Corporation

                                       34
<PAGE>
                          INDEPENDENT AUDITORS' REPORT

To the Board of Directors of
Arizona Public Service Company
Phoenix, Arizona

     We have audited the accompanying balance sheets of Arizona Public Service
Company as of December 31, 2000 and 1999 and the related statements of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 2000. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements 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, 2000 and 1999 and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 2000 in conformity with
accounting principles generally accepted in the United States of America.


Deloitte & Touche LLP

Deloitte & Touche LLP
Phoenix, Arizona
February 9, 2001

                                       35
<PAGE>


















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                                       36
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                              STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                           Year Ended December 31,
                                                  -------------------------------------------
                                                     2000            1999            1998
                                                  -----------     -----------     -----------
                                                            (Dollars in Thousands)
<S>                                               <C>             <C>             <C>
Electric Operating Revenues ..................    $ 3,480,252     $ 2,292,798     $ 2,006,398
                                                  -----------     -----------     -----------
Fuel Expenses:
  Fuel for electric generation ...............        333,265         243,849         231,967
  Purchased power ............................      1,547,464         551,645         313,330
                                                  -----------     -----------     -----------
        Total.................................      1,880,729         795,494         545,297
                                                  -----------     -----------     -----------

Operating Revenues Less Fuel Expenses ........      1,599,523       1,497,304       1,461,101
                                                  -----------     -----------     -----------
Other Operating Expenses:
  Operations and maintenance excluding
    fuel expenses ............................        430,696         437,729         419,433
  Depreciation and amortization (Note 1)......        388,660         382,057         376,574
  Income taxes (Note 10) .....................        229,542         192,015         192,207
  Other taxes ................................         99,730          96,579         102,076
                                                  -----------     -----------     -----------
        Total.................................      1,148,628       1,108,380       1,090,290
                                                  -----------     -----------     -----------

Operating Income .............................        450,895         388,924         370,811
                                                  -----------     -----------     -----------
Other Income (Deductions):
  Income taxes (Note 10) .....................          4,225          32,527          32,751
  Other -- net ...............................        (10,637)        (11,537)        (12,303)
                                                  -----------     -----------     -----------
        Total.................................         (6,412)         20,990          20,448
                                                  -----------     -----------     -----------

Income Before Interest Deductions ............        444,483         409,914         391,259
                                                  -----------     -----------     -----------

Interest Deductions:
  Interest on long-term debt .................        134,431         132,676         137,214
  Interest on short-term borrowings ..........          7,455           8,272           7,481
  Debt discount, premium and expense .........          6,897           7,323           7,580
  Capitalized interest .......................        (10,894)         (6,679)        (16,263)
                                                  -----------     -----------     -----------
        Total.................................        137,889         141,592         136,012
                                                  -----------     -----------     -----------
Income Before Extraordinary Charge ...........        306,594         268,322         255,247
Extraordinary Charge - net of income taxes
  of $94,115 (Note 1) ........................             --         139,885              --
                                                  -----------     -----------     -----------
Net Income ...................................        306,594         128,437         255,247
Preferred Stock Dividend Requirements ........             --           1,016           9,703
                                                  -----------     -----------     -----------

Earnings for Common Stock ....................    $   306,594     $   127,421     $   245,544
                                                  ===========     ===========     ===========
</TABLE>

See Notes to Financial Statements.

                                       37
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                                 BALANCE SHEETS
                                     ASSETS

<TABLE>
<CAPTION>
                                                                        December 31,
                                                               -----------------------------
                                                                  2000              1999
                                                               -----------       -----------
                                                                 (Dollars in Thousands)
<S>                                                            <C>               <C>
Utility Plant (Notes 5, 8 and 9):
  Electric plant in service and held for future use......      $ 7,805,025       $ 7,545,575
  Less accumulated depreciation and amortization ........        3,187,328         3,026,041
                                                               -----------       -----------
        Total ...........................................        4,617,697         4,519,534
  Construction work in progress .........................          245,749           184,764
  Nuclear fuel, net of amortization of $61,256
    and $66,357 .........................................           47,389            49,114
                                                               -----------       -----------
        Utility Plant -- net.............................        4,910,835         4,753,412
                                                               -----------       -----------

Investments and Other Assets (Note 13) ..................          269,678           208,457
                                                               -----------       -----------
Current Assets:
  Cash and cash equivalents .............................            2,609             7,477
  Accounts receivable:
    Service customers ...................................          422,012           201,704
    Other ...............................................           48,711            35,684
    Allowance for doubtful accounts .....................           (2,380)           (1,538)
  Accrued utility revenues ..............................           74,566            72,919
  Materials and supplies (at average cost) ..............           71,966            69,977
  Fossil fuel (at average cost) .........................           19,405            21,869
  Deferred income taxes (Note 10) .......................            5,793             8,163
  Other .................................................           55,920            30,885
                                                               -----------       -----------
        Total Current Assets ............................          698,602           447,140
                                                               -----------       -----------
Deferred Debits:
  Regulatory assets (Note 1) ............................          469,867           613,729
  Unamortized debt issue costs ..........................           12,805            15,172
  Other .................................................           37,928            79,714
                                                               -----------       -----------
        Total Deferred Debits ...........................          520,600           708,615
                                                               -----------       -----------
        Total ...........................................      $ 6,399,715       $ 6,117,624
                                                               ===========       ===========
</TABLE>

See Notes to Financial Statements.

                                       38
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                                 BALANCE SHEETS
                                   LIABILITIES

<TABLE>
<CAPTION>
                                                                           December 31,
                                                                   ---------------------------
                                                                      2000             1999
                                                                   ----------       ----------
                                                                     (Dollars in Thousands)
<S>                                                                <C>              <C>
Capitalization (Notes 4 and 5):
  Common stock .............................................       $  178,162       $  178,162
  Additional paid - in capital .............................        1,246,804        1,246,804
  Retained earnings ........................................          694,802          558,208
                                                                   ----------       ----------
        Common stock equity ................................        2,119,768        1,983,174
  Long-term debt less current maturities ...................        1,806,908        1,997,400
                                                                   ----------       ----------
        Total Capitalization ...............................        3,926,676        3,980,574
                                                                   ----------       ----------
Current Liabilities:
  Commercial paper (Note 6) ................................           82,100           38,300
  Current maturities of long-term debt (Note 5) ............          250,266          114,711
  Accounts payable .........................................          267,999          170,662
  Accrued taxes ............................................          106,515           62,858
  Accrued interest .........................................           39,488           32,299
  Customer deposits ........................................           24,498           24,682
  Other ....................................................          142,126           26,248
                                                                   ----------       ----------
        Total Current Liabilities ..........................          912,992          469,760
                                                                   ----------       ----------
Deferred Credits and Other:
  Deferred income taxes (Note 10) ..........................        1,110,437        1,178,085
  Deferred investment tax credit (Note 10) .................            4,570            4,839
  Unamortized gain -- sale of utility plant (Note 9)........           68,636           73,212
  Customer advances for construction .......................           40,694           38,150
  Other ....................................................          335,710          373,004
                                                                   ----------       ----------
        Total Deferred Credits and Other ...................        1,560,047        1,667,290
                                                                   ----------       ----------
Commitments and Contingencies (Notes 3, 12, 13)

        Total ..............................................       $6,399,715       $6,117,624
                                                                   ==========       ==========
</TABLE>

See Notes to Financial Statements.

                                       39
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                            STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                             Year Ended December 31,
                                                                  -----------------------------------------
                                                                    2000            1999            1998
                                                                  ---------       ---------       ---------
                                                                            (Dollars in Thousands)
<S>                                                    <C>          <C>          <C>
Cash Flows from Operations:
 Net income ................................................      $ 306,594       $ 128,437       $ 255,247
 Items not requiring cash:
  Depreciation and amortization ............................        388,660         382,057         376,574
  Nuclear fuel amortization ................................         30,083          31,371          32,856
  Deferred income taxes - net ..............................        (35,805)        (29,654)        (26,374)
  Deferred investment tax credit - net .....................           (269)        (27,626)        (27,628)
  Extraordinary Charge - net of income taxes ...............             --         139,885              --
 Changes in certain current assets and liabilities:
  Accounts receivable - net ................................       (232,493)         (8,363)        (56,490)
  Accrued utility revenues .................................         (1,647)         (5,179)         (9,181)
  Materials, supplies and fossil fuel ......................            475          (8,794)         (2,797)
  Other current assets .....................................        (25,035)         (4,190)         (2,166)
  Accounts payable .........................................        101,558          22,992          33,731
  Accrued taxes ............................................         43,657           3,031         (26,059)
  Accrued interest .........................................          7,189           1,081            (442)
  Other current liabilities ................................        115,694           7,833          (4,654)
 Other - net ...............................................         11,176          (4,922)        (29,641)
                                                                  ---------       ---------       ---------
        Net cash provided ..................................        709,837         627,959         512,976
                                                                  ---------       ---------       ---------
Cash Flows from Investing:
 Capital expenditures ......................................       (464,368)       (322,547)       (319,142)
 Capitalized interest ......................................        (10,894)         (6,679)        (16,263)
 Other .....................................................        (58,355)         (8,173)         (8,593)
                                                                  ---------       ---------       ---------
        Net cash used ......................................       (533,617)       (337,399)       (343,998)
                                                                  ---------       ---------       ---------
Cash Flows from Financing:
 Issuance of long-term debt ................................        300,000         392,952         126,245
 Short-term borrowings - net ...............................         43,800        (140,530)         48,080
 Common equity infusion from parent ........................             --          50,000          50,000
 Dividends paid on common stock ............................       (170,000)       (170,000)       (170,000)
 Dividends paid on preferred stock .........................             --          (1,393)        (10,279)
 Repayment of preferred stock ..............................             --         (96,499)        (75,517)
 Repayment and reacquisition of long-term debt .............       (354,888)       (323,171)       (144,501)
                                                                  ---------       ---------       ---------
        Net cash used ......................................       (181,088)       (288,641)       (175,972)
                                                                  ---------       ---------       ---------
Net increase (decrease) in cash and cash equivalents........         (4,868)          1,919          (6,994)
Cash and cash equivalents at beginning of year .............          7,477           5,558          12,552
                                                                  ---------       ---------       ---------
Cash and cash equivalents at end of year ...................      $   2,609       $   7,477       $   5,558
                                                                  =========       =========       =========
Supplemental Disclosure of Cash Flow Information:
 Cash paid during the year for:
   Interest (excluding capitalized interest) ...............      $ 123,895       $ 132,995       $ 128,627
   Income taxes ............................................      $ 222,866       $ 189,002       $ 235,475
</TABLE>

See Notes to Financial Statements.

                                       40
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                         STATEMENTS OF RETAINED EARNINGS

<TABLE>
<CAPTION>
                                                                     Year Ended December 31,
                                                           --------------------------------------
                                                             2000           1999           1998
                                                           --------       --------       --------
                                                                  (Dollars in Thousands)
<S>                                                        <C>            <C>            <C>
Retained earnings at beginning of year .............       $558,208       $601,968       $528,798
Add: Net income ....................................        306,594        128,437        255,247
                                                           --------       --------       --------
        Total ......................................        864,802        730,405        784,045
                                                           --------       --------       --------
Deduct:
  Dividends:
    Common stock (Notes 4 and 5) ...................        170,000        170,000        170,000
    Preferred stock (at required rates) (Note 4)....             --          1,016          9,703
  Other ............................................             --          1,181          2,374
                                                           --------       --------       --------
        Total deductions ...........................        170,000        172,197        182,077
                                                           --------       --------       --------

Retained earnings at end of year ...................       $694,802       $558,208       $601,968
                                                           ========       ========       ========
</TABLE>

See Notes to Financial Statements.

                                       41
<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 provide retail and wholesale
electric service to the entire state with the exception of Tucson and about
one-half of the Phoenix area. We also generate and, directly or through Pinnacle
West's power marketing division, sell and deliver electricity to wholesale
customers in the western United States.

ACCOUNTING RECORDS

     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 the use of
estimates by management. Actual results could differ from those estimates.

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.
Accordingly, 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 pre-tax ($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 now being amortized as follows:

                                       42
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS


                              (dollars in millions)

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

     The majority of our remaining regulatory assets relate to deferred income
taxes (see Note 10) and rate synchronization cost deferrals (see "Rate
Synchronization Cost Deferrals" in this Note).

     The balance sheets include the amounts listed below for generation assets
not subject to SFAS No. 71 (for additional generation information see Note16):

                             (dollars in thousands)

                                                     December 31,   December 31,
                                                        2000           1999
                                                     -----------    -----------
Electric plant in service and held for future use    $ 3,856,600    $ 3,817,919
Accumulated depreciation and amortization ........    (1,693,079)    (1,664,782)
Construction work in progress ....................        86,329         67,306
Nuclear fuel, net of amortization ................        47,389         49,114

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 proposed accounting
standard that impacts accounting for removal costs.

     We record depreciation on utility property on a straight-line basis. For
the years 1998 through 2000 the rates, as prescribed by our regulators, ranged
from a low of 3.33% to a high of 20%. The weighted-average rate was 3.40% for
2000, 3.34% for 1999, and 3.32% for 1998. We depreciate non-utility property and
equipment over the estimated useful lives of the related assets, ranging from 3
to 30 years.

                                       43
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS


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 6.62% for 2000, 6.65% for 1999, and 6.88% for 1998.

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.

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 on 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 expects 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 12 for information about spent nuclear fuel
disposal and Note 13 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.

                                       44
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS


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/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, we engage in trading activities intended to profit
from market price movements.

     Gains and losses related to derivatives that qualify as 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 closes (deferral method).

     Net gains and losses on derivatives utilized for trading are recognized in
wholesale revenues on a current basis (the mark to market method). Trading
positions are measured at fair value as of the balance sheet date. The net gain
was $9 million for 2000 and $1 million for 1999.

CASH AND CASH EQUIVALENTS

     We consider temporary cash investments and marketable securities, with
original maturities of less than 90 days, to be cash equivalents for purposes of
reporting cash flows.

2. ACCOUNTING MATTERS

     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 sheet and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholder's 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, as defined by SFAS No. 133, 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 sheet
as of January 1, 2001. We recorded a $3 million after-tax loss in net income as
a cumulative effect of change in accounting principles and a $64 million
after-tax gain in equity (as a component of other comprehensive income). The
gain resulted from unrealized gains on cash flow hedges.

     In December 2000, the FASB's Derivatives Implementation Group (DIG)
discussed whether contracts in the electric industry that have some of the
characteristics of purchased and written options

                                       45
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS


should qualify for the "normal purchases and sales" scope exception. The DIG did
not reach a conclusion on this issue. We account for electricity contracts with
characteristics of options as normal purchases and sales if it is probable that
the contract will not be settled in cash and will result in the physical
delivery of electricity. The DIG also discussed but did not conclude on whether
electricity contracts subject to "bookout" should qualify for the normal
exception. A bookout occurs when one party appears more than once in a contract
path for the sale and purchase of energy. In that instance, the counterparties
may agree that they will not schedule or deliver physical energy that originates
and ends with the same counterparty, but rather will settle in cash the amounts
due to or from each counterparty. We account for transactions that bookout as
gross settlement with physical delivery (and eligible for the normal scope
exception) if title transfers, gross cash payment is made, and the transaction
retains both performance and credit risk. The contracts we are referring to here
are not trading contracts, which we already measure at fair value (mark to
market) as discussed in Note 1.

     Our accounting is reflective of the non-storability of our product and the
lack of predictability of the demand for electricity at any point in time. If
the FASB or DIG ultimately provide contrary guidance, we may be required to mark
certain contracts to their fair market values each reporting period, which could
have a material impact on our financial statements and add significant net
income and comprehensive income volatility that would not be reflective of the
nature of our business. If these agreements are required to be treated as
derivative instruments, a cumulative effect of a change in accounting principles
would be applied in the quarter following final resolution of the issues.

     In 1999 we adopted 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 the
gains and losses included in earnings and separately disclosed in the financial
statements or footnotes. The effects of adopting EITF 98-10 were not material to
our 1999 financial statements.

     In February 1996, the FASB issued an exposure draft, "Accounting for
Certain Liabilities Related to Closure or Removal of Long-Lived Assets." This
proposed standard would require 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. The FASB issued a revised exposure draft in February
2000 and we are evaluating the impacts.

3. REGULATORY MATTERS

ELECTRIC INDUSTRY RESTRUCTURING

STATE

     1999 SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive
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

                                       46
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                          NOTES TO FINANCIAL STATEMENTS


bringing the lawsuits appealed the ACC's order approving our 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. A decision is
still pending on the other appeal, which raises a number of different issues.

     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 megawatts (MW) in a series of annual
     retail electric 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 reduction authorized in the 1999 Settlement
     Agreement, there was a retail price decrease of approximately $28 million
     ($17 million after taxes), or 1.5%, effective July 1, 2000. 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 current 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.

*    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

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


     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 (CTC) that will remain in effect through December 31, 2004, at which
     time it will terminate. Any over/under-recovery due to sales volume
     variances will be credited/debited against the costs subject to recovery
     under the adjustment clause described above.

*    We will form a separate corporate affiliate or affiliates and transfer to
     such affiliate(s) our generating assets and competitive services at book
     value as of the date of transfer, which transfer shall take place 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. 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.

*    When the 1999 Settlement Agreement approved by the ACC is no longer subject
     to judicial review, we will move to dismiss all of our litigation pending
     against the ACC as of the date we entered into the 1999 Settlement
     Agreement. To protect our rights, we have several lawsuits pending on ACC
     orders relating to stranded cost recovery and the adoption and amendment of
     the ACC's electric competition rules, which would be voluntarily dismissed
     at the appropriate time under this provision.

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

     RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve the 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 is pending, along with several other lawsuits on ACC orders
relating to stranded cost recovery, the adoption or amendment of the Rules, and
the certification of competitive electric service providers.

     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 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

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


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 Court
of Appeals, as a result of which the ruling is automatically stayed pending
further judicial review.

     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 was available to all of our
          retail customers.

     *    Electric service providers that get Certificates of Convenience and
          Necessity 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
          non-competitive 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
          generation 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 generation and other
          competitive assets and services to affiliates no later than December
          31, 2002. See "1999 Settlement Agreement" above for a discussion of
          the planned timing of the transfer.

     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 the parent company 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:

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


     *    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.

FEDERAL

     The 1992 Energy Act and recent rulemakings by FERC have promoted increased
competition in the wholesale energy markets. We do not expect these rules to
have a material impact on our financial statements.

     Several electric utility industry restructuring bills will undoubtedly be
introduced during the current congressional session. Several of these bills are
written to allow consumers to choose their electricity suppliers beginning in
2001 and beyond. These bills and other bills are expected to be introduced, and
ongoing discussions at the federal level suggest a wide range of opinion that
will need to be narrowed before any comprehensive restructuring of the electric
utility industry can occur.

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


4. COMMON AND PREFERRED STOCKS

     On March 1, 1999, we redeemed all of our preferred stock. Common stock
balances at December 31, 2000 and 1999 are shown below:

<TABLE>
<CAPTION>
                                          Number
                                         of Shares             Par          Par Value
                                        Outstanding           Value        Outstanding
                                 -------------------------     Per      --------------------
                  Authorized        2000          1999        Share       2000        1999
                  -----------    -----------   -----------    -----     --------    --------
                                                                       (dollars in thousands)
<S>               <C>            <C>           <C>            <C>       <C>         <C>
Common Stock....  100,000,000     71,264,947    71,264,947    $2.50     $178,162    $178,162
                                 ===========   ===========              ========    ========
</TABLE>

Preferred Stock:

Redeemable preferred stock transactions during each of the three years in the
period ended December 31, 2000 are as follows:

<TABLE>
<CAPTION>
                                    Number of Shares                      Par Value
                                      Outstanding                        Outstanding
                             ------------------------------    --------------------------------
                                                                    (dollars in thousands)
Description                    2000       1999       1998        2000        1999        1998
-----------                  --------   --------   --------    --------    --------    --------
<S>                          <C>        <C>        <C>         <C>         <C>         <C>
Balance, January 1........         --     94,011    291,098    $     --    $  9,401    $ 29,110
  Retirements:
    $10.00 Series U.......         --    (94,011)  (197,087)         --      (9,401)    (19,709)
    $7.875 Series V.......                    --         --                      --          --
                             --------   --------   --------    --------    --------    --------
Balance, December 31......         --         --     94,011    $     --    $     --    $  9,401
                             ========   ========   ========    ========    ========    ========
</TABLE>

5. 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, 2000 and December 31,
1999:

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


                             (dollars in thousands)

<TABLE>
<CAPTION>
                                                                           December 31,
                                                                      -----------------------
                                    Maturity         Interest
                                    Dates (a)          Rates             2000         1999
                                    ---------          -----          ----------   ----------
<S>                                 <C>          <C>                  <C>          <C>
First mortgage bonds                   2000              5.75%        $       --   $  100,000
                                       2002             8.125%           125,000      125,000
                                       2004             6.625%            80,000       80,000
                                       2020             10.25%                --      100,550
                                       2021               9.5%            45,140       45,140
                                       2021                 9%            72,370       72,370
                                       2023              7.25%            70,650       70,650
                                       2024              8.75%           121,668      121,668
                                       2025                 8%            33,075       47,075
                                       2028               5.5%            25,000       25,000
                                       2028             5.875%           154,000      154,000
Unamortized discount and premium                                          (5,993)      (5,860)

Pollution control bonds              2024-2034   Adjustable rate(b)      476,860      476,860
Funds held in trust account for
  certain pollution control bonds                                             --       (1,236)
Collateralized loan                    2000      5.375%-6.125%                --       10,000
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           --

Floating rate notes                    2001      Adjustable rate(c)      250,000      250,000
Senior notes (d)                       2006              6.75%            83,695       83,695

Debentures                             2025                10%                --       75,000

Bank loans                             2003      Adjustable rate(e)           --       50,000
Capitalized lease obligation           2000              7.48%(f)             --        7,199
Capitalized lease obligation        2001-2003            7.75%               709           --
                                                                      ----------   ----------
Total long-term debt                                                   2,057,174    2,112,111
Less current maturities                                                  250,266      114,711
                                                                      ----------   ----------
Total long-term debt less current
maturities                                                            $1,806,908   $1,997,400
                                                                      ==========   ==========
</TABLE>

----------
(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, 2000 was 4.06%
     and for December 31, 1999 was 3.15%. Changes in short-term interest rates
     would affect the costs associated with this debt.

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


(c)  The weighted-average rate for the year ended December 31, 2000 was 7.33%
     and for December 31, 1999 was 6.8525%.
(d)  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.
(e)  The weighted-average rate for the year ended December 31, 2000 was 6.53%
     and for December 31, 1999 was 5.5%. Changes in short-term interest rates
     would affect the costs associated with this debt. At December 31, 2000, we
     had no long-term bank borrowings outstanding.
(f)  Represents the present value of future lease payments (discounted at an
     interest rate of 7.48%) on a combined cycle plant that was sold and leased
     back. The capital lease was paid off early and the related asset was
     purchased in December 2000 (See Note 9).

     The following is a list of principal payments due on total long-term debt
and sinking fund requirements through 2005:

                              (dollars in millions)

                         Year                      Amount
                        ------                     ------
                         2001                      $  250
                         2002                         125
                         2003                          --
                         2004                         205
                         2005                         400

     First mortgage bondholders share a lien on substantially all utility plant
assets (other than nuclear fuel and transportation equipment). The mortgage bond
indenture restricts the payment of common stock dividends under certain
conditions. These conditions did not exist at December 31, 2000.

6. LINES OF CREDIT

     We had committed lines of credit with various banks of $250 million at
December 31, 2000 and $350 million at December 31, 1999, which were available
either to support the issuance of commercial paper or to be used for bank
borrowings. The commitment fees at December 31, 2000 and 1999 for these lines of
credit ranged from 0.09% to 0.125% per annum. We have no long-term bank
borrowings at December 31, 2000 and $50 million outstanding at December 31,
1999.

     Our commercial paper borrowings outstanding were $82 million at December
31, 2000 and $38 million at December 31, 1999. The weighted average interest
rate on commercial paper borrowings was 6.64% for the year ended December 31,
2000 and 5.33% for the year ended

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


December 31, 1999. By Arizona statute, our short-term borrowings cannot exceed
7% of our total capitalization unless approved by the ACC.

7. 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, 2000 and
1999 due to their short maturities.

     We hold investments in debt and equity securities for purposes other than
trading. The December 31, 2000 and 1999 fair values of such investments, which
we determine by using quoted market values, approximate their carrying amount.

     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. On December 31, 1999, the carrying value of our long-term debt
(excluding a capitalized lease obligation) was $2.10 billion, with an estimated
fair value of $2.08 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.

8. 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 at December 31, 2000. Our share of operating and
maintaining these facilities is included in the income statement in operations
and maintenance expense.

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


<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%     $1,824,480     $814,693        $ 7,414
  Palo Verde Nuclear Generating Station
    Unit 2 (see Note 9)                      17.0%        571,573      265,571         29,593
  Four Corners Steam Generating Station
    Units 4 and 5                            15.0%        152,717       75,797             --
  Navajo Steam Generating Station
    Units 1, 2, and 3                        14.0%        231,509       99,623          4,899
  Cholla Steam Generating Station
    Common Facilities (a)                    62.8%(b)      73,382       40,023            686
Transmission Facilities:
  ANPP 500KV System                          35.8%(b)      67,987       22,813             --
  Navajo Southern System                     31.4%(b)      27,290       17,804             55
  Palo Verde-Yuma 500KV System               23.9%(b)       9,712        3,844              1
  Four Corners Switchyards                   27.5%(b)       3,071        1,925             --
  Phoenix-Mead System                        17.1%(b)      36,418        2,681             --
  Palo Verde - Estrella 500KV System         50.0%(b)          --           --            610
</TABLE>

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

9. 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.

     The average amounts to be paid for the Palo Verde Unit 2 leases are
approximately $49 million per year for the years 2001-2015.

     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). The accelerated amortization is
included in depreciation and amortization expense on

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


the Statements of Income. The balance of this regulatory asset at December 31,
2000 was $33 million.

     In December 2000, we purchased Units 1, 2, and 3 of West Phoenix Power
Plant. These units were previously reflected as a capital lease.

     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 $53 million in 2000, $49 million in 1999, and $52
million in 1998.

     Estimated future minimum lease commitments, are approximately $64 million
for each of the years 2001 to 2005 and $613 million thereafter.

10. 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
Sheet 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 continuing operations are:

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


                             (dollars in thousands)

                                                  Year Ended December 31,
                                            -----------------------------------
                                              2000         1999         1998
                                            ---------    ---------    ---------
Current
  Federal                                   $ 211,139    $ 175,227    $ 170,806
  State                                        50,252       41,541       42,652
                                            ---------    ---------    ---------
Total current                                 261,391      216,768      213,458

Deferred                                      (35,805)     (29,654)     (26,374)
ITC amortization                                 (269)     (27,626)     (27,628)
                                            ---------    ---------    ---------
Total expense                               $ 225,317    $ 159,488    $ 159,456
                                            =========    =========    =========

     The following chart compares pretax income at the 35% federal income tax
rate to income tax expense:

                             (dollars in thousands)

                                                  Year Ended December 31,
                                            -----------------------------------
                                              2000         1999         1998
                                            ---------    ---------    ---------
Federal income tax expense at 35%
statutory rate                              $ 186,169    $ 149,710    $ 145,146
Increases (reductions) in tax expense
resulting from:
  Tax under book depreciation                  12,328       14,575       17,848
  ITC amortization                               (269)     (27,626)     (27,628)
  State income tax net of federal income
  tax benefit                                  23,714       24,135       23,024
  Other                                         3,375       (1,306)       1,066
                                            ---------    ---------    ---------
Income tax expense                          $ 225,317    $ 159,488    $ 159,456
                                            =========    =========    =========

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


The components of the net deferred income tax liability were as follows:

                             (dollars in thousands)

                                                        Year Ended December 31,
                                                        ------------------------
                                                           2000          1999
                                                        ----------    ----------
DEFERRED TAX ASSETS
  Deferred gain on Palo Verde Unit 2 sale/leaseback     $   27,056    $   29,446
  Other                                                    122,019       139,518
                                                        ----------    ----------
Total deferred tax assets                                  149,075       168,964
                                                        ----------    ----------
DEFERRED TAX LIABILITIES
  Plant-related                                          1,081,637     1,104,769
  Regulatory asset for income taxes                        172,082       234,117
                                                        ----------    ----------
Total deferred tax liabilities                           1,253,719     1,338,886
                                                        ----------    ----------
Accumulated deferred income taxes - net                 $1,104,644    $1,169,922
                                                        ==========    ==========

11. RETIREMENT PLANS AND OTHER BENEFITS

PENSION PLANS

     Through 1999, we sponsored defined benefit pension plans for our employees.
As of January 1, 2000, this plan is sponsored by Pinnacle West. In 2000, we
represent 71% 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, we calculate the benefits under these
plans based on age, years of service, and pay. We fund 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, 2000 were mostly domestic and international common stocks and bonds
and real estate.

     Pension expense, including administrative costs, was:

     *    $2 million in 2000;
     *    $4 million in 1999; and
     *    $10 million in 1998.

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


     The following table shows the components of net pension cost before
consideration of amounts capitalized or billed to others:

                             (dollars in thousands)

<TABLE>
<CAPTION>
                                                      2000         1999         1998
                                                    --------     --------     --------
<S>                                                 <C>          <C>          <C>
Service cost - benefits earned during the period    $ 24,197     $ 24,266     $ 24,126
Interest cost on projected benefit obligation         57,785       52,208       50,863
Expected return on plan assets                       (76,524)     (67,528)     (53,883)
Amortization of:
  Transition asset                                    (3,198)      (3,216)      (3,216)
  Prior service cost                                   2,059        2,063        2,063
Net actuarial gain                                    (1,617)          --           --
                                                    --------     --------     --------
Net periodic pension cost                           $  2,702     $  7,793     $ 19,953
                                                    ========     ========     ========
</TABLE>

     The following table shows a reconciliation of the funded status of the
plans to the amounts recognized in the balance sheets:

                             (dollars in thousands)

                                                             2000        1999
                                                           --------    --------
Fund status - pension plan assets more than (less than)
  projected benefit obligation                             $(22,438)   $ 37,784
Unrecognized net transition asset                           (16,745)    (19,943)
Unrecognized prior service cost                              18,440      20,499
Unrecognized net actuarial gains                            (20,075)    (99,602)
                                                           --------    --------
Net pension liability recognized in the balance sheets     $(40,818)   $(61,262)
                                                           ========    ========

     The following table sets forth the defined benefit pension plans' change in
projected benefit obligation for the plan years 2000 and 1999:

                             (dollars in thousands)

                                                             2000        1999
                                                           --------    --------

Projected pension benefit obligation at beginning of year  $732,911    $721,229
Service cost                                                 24,197      24,266
Interest cost                                                57,785      52,208
Benefit payments                                            (30,498)    (29,444)
Actuarial (gains)/losses                                      3,461     (35,348)
                                                           --------    --------
Projected pension benefit obligation at end of year        $787,856    $732,911
                                                           ========    ========

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


     The following table sets forth the defined benefit pension plans' change in
the fair value of plan assets for the plan years 2000 and 1999:

                             (dollars in thousands)

                                                           2000         1999
                                                         ---------    ---------

Fair value of pension plan assets at beginning of year   $ 770,695    $ 682,272
Actual return on plan assets                                 1,830       92,867
Employer contributions                                      23,391       25,000
Benefit payments                                           (30,498)     (29,444)
                                                         ---------    ---------
Fair value of pension plan assets at end of year         $ 765,418    $ 770,695
                                                         =========    =========

     We made the assumptions below to calculate the pension liability:

                                                           2000           1999
                                                           -----          -----

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

EMPLOYEE SAVINGS PLAN BENEFITS

     Through 1999, we sponsored defined contribution savings plans for our
employees. As of January 1, 2000, this plan is sponsored by Pinnacle West. In
2000, we represent 92% 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, we make matching
contributions to participant accounts. We recorded expenses for this plan of
approximately $3 million for 2000 and $4 million for each of the years 1999 and
1998.

POSTRETIREMENT PLANS

     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. In 2000, we represent
84% of the total cost of this plan.

     Funding is based upon actuarially determined contributions that take tax
consequences into account. Plan assets consist primarily of domestic stocks and
bonds. The postretirement benefit expense was:

     *    $ 2 million for 2000;
     *    $ 6 million for 1999; and
     *    $ 9 million for 1998.

     The following table shows the components of net periodic postretirement
benefit costs before consideration of amounts capitalized or billed to others:

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


                             (dollars in thousands)
<TABLE>
<CAPTION>
                                                      2000         1999         1998
                                                    --------     --------     --------
<S>                                                 <C>          <C>          <C>
Service cost - benefits earned during the period    $  8,312     $  8,676     $  7,676
Interest cost on accumulated benefit obligation       19,169       17,188       15,610
Expected return on plan assets                       (22,381)     (18,454)     (12,001)
Amortization of:
  Transition obligation                                7,638        7,652        7,652
  Net actuarial gains                                 (7,931)      (5,095)      (2,927)
                                                    --------     --------     --------
Net periodic postretirement benefit cost            $  4,807     $  9,967     $ 16,010
                                                    ========     ========     ========
</TABLE>

     The following table shows a reconciliation of the funded status of the plan
to the amounts recognized in the balance sheets:

                             (dollars in thousands)

                                                           2000         1999
                                                         ---------    ---------
Funded status - postretirement plan assets more than
  (less than) projected benefit obligation               $ (12,786)   $  27,930
Unrecognized net obligation at transition                   91,844       99,482
Unrecognized net actuarial gains                           (79,596)    (127,338)
                                                         ---------    ---------
Net postretirement amount recognized in the balance
  sheets                                                 $    (538)   $      74
                                                         =========    =========

     The following table sets forth the postretirement benefit plans' change in
accumulated benefit obligation for the plan years 2000 and 1999:

                             (dollars in thousands)

                                                           2000         1999
                                                         ---------    ---------
Accumulated postretirement benefit obligation at
  beginning of year                                      $ 229,608    $ 235,322
Service cost                                                 8,312        8,675
Interest cost                                               19,169       17,188
Benefit payments                                            (8,905)      (8,761)
Actuarial (gains) losses                                    13,756      (22,816)
                                                         ---------    ---------
Accumulated postretirement benefit obligation at
  end of year                                            $ 261,940    $ 229,608
                                                         =========    =========

     The following table sets forth the postretirement benefit plans' change in
the fair value of plan assets for the plan years 2000 and 1999:

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

                             (dollars in thousands)

                                                           2000         1999
                                                         ---------    ---------
Fair value of postretirement plan assets at beginning
  of year                                                $ 257,538    $ 213,410
Actual return on plan assets                                (4,436)      42,975
Employer contributions                                       4,957        9,914
Benefit payments                                            (8,905)      (8,761)
                                                         ---------    ---------
Fair value of postretirement plan assets at
  the end of year                                        $ 249,154    $ 257,538
                                                         =========    =========

     We made the assumptions below to calculate the postretirement liability:

                                                                2000       1999
                                                                -----      -----

Discount rate                                                   7.75%      7.75%
Expected long-term rate of return on assets - after tax         8.77%      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           6.00%      6.00%
Ultimate health care cost trend rate (reached in the
  year 2002)                                                    5.00%      5.00%

     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 2000 cost of postretirement benefits
  other than pensions                                     $  5           $ (4)
Effect on the accumulated postretirement benefit
  obligation at December 31, 2000                           42            (34)

12. COMMITMENTS AND CONTINGENCIES

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.

POWER SERVICE AGREEMENT

     We are a party to a power service agreement with Citizens Communications
Company (Citizens) under which we supply Citizens with power. By letter dated
March 7, 2001, Citizens advised us that it believes we have overcharged Citizens
by over $50 million under the agreement since the summer of 2000. We believe
that our charges to Citizens under the agreement are fully in accordance with
the terms of the agreement and will vigorously defend any contrary claims raised
by Citizens.

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

PALO VERDE NUCLEAR GENERATING STATION

     Pursuant to the Nuclear Waste Policy Act of 1982, the DOE must accept and
dispose of all spent nuclear fuel and other high-level radioactive wastes
generated by domestic power reactors. The United States Nuclear Regulatory
Commission (NRC) requires operators of nuclear power reactors to enter into
spent fuel disposal contracts with the DOE. Under the Nuclear Waste Policy Act
of 1982, the DOE was to develop a permanent repository for the storage and
disposal of spent nuclear fuel by 1998. The DOE has announced that such a
permanent 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 precluding the DOE from
excusing its own delay, but refused to order the DOE to begin accepting spent
nuclear fuel. Based on this decision, a number of utilities filed damages
actions against DOE in the Court of Federal Claims. In decisions that became
final in December 2000, the United States Court of Appeals for the Federal
Circuit held that utilities do not have to exhaust the DOE administrative claims
before filing lawsuits for damages against the DOE in the Court of Federal
Claims.

     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.

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

     We currently estimate that we will incur $113 million (in 2000 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, 2000, we have recorded
a liability and regulatory asset of $40 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.

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

     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 2001 through 2021 that include required purchase provisions. We
estimate our 2001 contract requirements to be approximately $277 million in
2001; $145 million in 2002; $90 million in 2003; $83 million in 2004; and $55
million in 2005. However, this amount may vary significantly pursuant to certain
provisions in such contracts that permit us to decrease our required purchases
under certain circumstances.

     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 $58 million at December 31, 2000 and is included in
"Deferred Credits-Other" in the Balance Sheet.

     A regulatory asset has been established for amounts not yet recovered from
ratepayers. 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. The balance of the regulatory asset at December 31, 2000
was about $32 million.

     CALIFORNIA ENERGY MARKET ISSUES

     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 power marketing exposures. Based upon the financial transactions to
date, we do not believe the foregoing matters will have a material adverse
effect on our financial position or 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 market in
general.

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

CONSTRUCTION PROGRAM

     Total capital expenditures in 2001 are estimated at $455 million.

13. NUCLEAR DECOMMISSIONING COSTS

     We recorded $11 million for nuclear decommissioning expense in each of the
years 2000, 1999, and 1998. We estimate it will cost about $1.8 billion ($493
million in 2000) to decommission our share of the three Palo Verde units. The
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 includes 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 1998 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.
The trust accounts are reported in investments and other assets on the Balance
Sheets at their market value of $205 million at December 31, 2000 and $176
million at December 31, 1999. 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.

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

14. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

     Quarterly financial information for 2000 and 1999 is as follows:

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

                             (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)           $ 66,094    $132,345     $  160,646     $ 91,810
Net income and
Earnings for Common Stock      $ 32,775    $ 95,851     $  124,231     $ 53,737

                             (dollars in thousands)

                                                   1999
                               -------------------------------------------------
QUARTER ENDED                  March 31    June 30    September 30   December 31
                               --------    -------    ------------   -----------

Electric operating revenues    $413,983    $511,434      $867,504      $499,877
Operating income (a)           $ 66,956    $ 98,503      $150,914      $ 72,551
Net Income/(Loss) (b)          $ 33,795    $ 69,542      $(10,377)     $ 35,477
Earnings/(Loss) for Common
  Stock                        $ 32,779    $ 69,542      $(10,377)     $ 35,477

----------
(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.

(b)  The quarter ending September 30, 1999 includes and extraordinary charge of
     $139,885, net of income taxes of $94,115.

15. STOCK-BASED COMPENSATION

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

     The 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. 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, 2000
approximate 1,569,171 non-qualified stock options, 193,992 shares of restricted
stock, and no incentive stock options, stock appreciation rights or dividend
equivalents.

     The FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation"
which was effective beginning in 1996. The statement 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."

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

     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)

                                              2000          1999          1998
                                            --------      --------      --------
Net income
  As reported                               $306,594      $128,437      $255,247
  Pro forma (fair value method)             $305,610      $127,658      $254,640

     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:

                                                       2000     1999      1998
                                                      -----     -----     -----

Risk-free interest rate                                5.81%     5.68%     4.54%
Dividend yield                                         3.48%     3.33%     3.03%
Volatility                                            32.00%    20.50%    18.80%
Expected life (months)                                   60        60        60

16. BUSINESS SEGMENTS

     We have two principal business segments (determined by products, services
and regulatory environment) which consist of the transmission and distribution
of electricity and wholesale activities (delivery business segment) and the
generation of electricity (generation business segment). Eliminations primarily
relate to intersegment sales of electricity. Financial data for the business
segments is provided as follows:

               Business Segments For Year Ended December 31, 2000
                             (dollars in thousands)

<TABLE>
<CAPTION>
                                 Generation      Delivery     Eliminations     Total
                                 ----------     ----------     ---------     ----------
<S>                              <C>            <C>            <C>           <C>
Operating revenues               $  990,415     $3,480,252     $(990,415)    $3,480,252
Operating expense                   597,948      2,814,259      (990,415)     2,421,792
                                 ----------     ----------     ---------     ----------
Operating margin                    392,467        665,993            --      1,058,460
Depreciation and Amortization       125,220        263,440            --        388,660
Interest                             41,808         96,081            --        137,889
                                 ----------     ----------     ---------     ----------
Pretax margin                       225,439        306,472            --        531,911
Income taxes                         88,755        136,562            --        225,317
                                 ----------     ----------     ---------     ----------
Earnings for common stock        $  136,684     $  169,910     $      --     $  306,594
                                 ==========     ==========     =========     ==========
Total assets                     $2,377,499     $4,022,216     $      --     $6,399,715
                                 ==========     ==========     =========     ==========
Capital expenditures             $  186,521     $  285,455     $      --     $  471,976
                                 ==========     ==========     =========     ==========
</TABLE>

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


               Business Segments For Year Ended December 31, 1999
                             (dollars in thousands)

<TABLE>
<CAPTION>
                                        Generation     Delivery    Eliminations     Total
                                        ----------    ----------    ----------    ----------
<S>                                     <C>           <C>           <C>           <C>
Operating revenues                      $  853,755    $2,292,798    $ (853,755)   $2,292,798
Operating expense                          522,925     1,672,169      (853,755)    1,341,339
                                        ----------    ----------    ----------    ----------
Operating margin                           330,830       620,629            --       951,459
Depreciation and Amortization              121,683       260,374            --       382,057
Interest and preferred stock dividend
requirements
                                            40,753       101,855            --       142,608
                                        ----------    ----------    ----------    ----------
Pretax margin                              168,394       258,400            --       426,794
Income taxes                                47,976       111,512            --       159,488
Extraordinary charge - net
  of income tax of $94,115
                                                --       139,885            --       139,885
                                        ----------    ----------    ----------    ----------
Earnings for common stock               $  120,418    $    7,003    $       --    $  127,421
                                        ==========    ==========    ==========    ==========
Total assets                            $2,371,014    $3,746,611    $       --    $6,117,624
                                        ==========    ==========    ==========    ==========

Capital expenditures                    $   90,285    $  241,469    $       --    $  331,754
                                        ==========    ==========    ==========    ==========

               Business Segments For Year Ended December 31, 1998
                             (dollars in thousands)

                                        Generation     Delivery    Eliminations     Total
                                        ----------    ----------    ----------    ----------
Operating revenues                      $  858,340    $2,006,398    $ (858,340)   $2,006,398
Operating expense                          522,696     1,414,753      (858,340)    1,079,109
                                        ----------    ----------    ----------    ----------
Operating margin                           335,644       591,645            --       927,289
Depreciation and Amortization              135,406       241,168            --       376,574
Interest and preferred stock
  dividend requirements                     37,045       108,670            --       145,715
                                        ----------    ----------    ----------    ----------
Pretax margin                              163,193       241,807            --       405,000
Income taxes                                49,969       109,487            --       159,456
                                        ----------    ----------    ----------    ----------
Earnings for common stock               $  113,224    $  132,320    $       --    $  245,544
                                        ==========    ==========    ==========    ==========
Total assets                            $2,399,560    $3,993,739    $       --    $6,393,299
                                        ==========    ==========    ==========    ==========
Capital expenditures                    $   85,767    $  241,638    $       --    $  327,405
                                        ==========    ==========    ==========    ==========
</TABLE>

                                       68
<PAGE>
       ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
                            AND FINANCIAL DISCLOSURE

     None.

                                    PART III

                        ITEM 10. DIRECTORS AND EXECUTIVE
                           OFFICERS OF THE REGISTRANT

     Not applicable.

                         ITEM 11. EXECUTIVE COMPENSATION

     Not applicable.

                         ITEM 12. SECURITY OWNERSHIP OF
                    CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     Not applicable.

             ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Not applicable.

                                       69
<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:

<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>

                                       70
<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>

                                       71
<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>

                                       72
<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

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

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
</TABLE>

                                       73
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
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>

                                       74
<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>

                                       75
<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>

                                       76
<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>

                                       77
<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

10.32c          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>

                                       78
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
10.33c          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

10.34c          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,
                1986between State Street
                Bank and Trust Company,
                as successor to The First
                National Bank of Boston, as
                Lessor, and APS, as Lessee

10.35c          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>

                                       79
<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

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

10.40a          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

10.41a          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

10.42a          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>

                                       80
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
10.43a          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

10.44a          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

10.45a          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

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

10.47a          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

10.48a          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>

                                       81
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
10.49a          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

10.50a          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

10.51a          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

10.52a          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

10.53a          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

10.54a          Arizona Public Service              10.1 to September 1997            1-4473            11-12-97
                Company Director                    Form 10-K Report
                Equity Plan
</TABLE>

                                       82
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
10.55a          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

10.56a          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

10.57a          Letter Agreement between            10.2 to September 1997            1-4473            11-12-97
                the Company and                     Form 10-Q Report
                William L. Stewart

10.58a          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

10.59a          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

10.60a          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

10.61ad         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

10.62a          Pinnacle West Capital               10.1 to 1992 Form 10-K            1-4473            3-30-93
                Corporation Stock Option            Report
                and Incentive Plan

10.63a          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
</TABLE>

                                       83
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
10.64a          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

10.65a          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

10.66a          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

10.67a          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

10.68a          2001 Management Variable            10.4 to Pinnacle West's           1-8962            3-14-01
                Incentive Plan (APS)                1999 Form 10-K Report

10.69a          2001 Senior Management              10.5 to Pinnacle West's           1-8962            3-14-01
                Variable Incentive Plan (APS)       1999 Form 10-K Report

10.70a          2001 Officer Variable               10.6 to Pinnacle West's           1-8962            3-14-01
                Incentive Plan (APS)                1999 Form 10-K Report
</TABLE>

                                       84
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
10.71           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

10.72           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

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

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

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

10.76           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
</TABLE>

                                       85
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
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

99.3c           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

99.4c           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
</TABLE>

                                       86
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
99.5c           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

99.6c           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

99.7c           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
</TABLE>

                                       87
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
99.8c           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

99.9c           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

99.10c          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

99.11c          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
</TABLE>

                                       88
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
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

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
</TABLE>

                                       89
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
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

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
</TABLE>

                                       90
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
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

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

99.20c          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
</TABLE>

                                       91
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                        ORIGINALLY FILED AS EXHIBIT:      FILE NO.b     DATE EFFECTIVE
-----------     -----------                        ----------------------------      --------      --------------
<S>             <C>                                <C>                               <C>           <C>
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

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
</TABLE>

                                       92
<PAGE>
----------
(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.

REPORTS ON FORM 8-K

     During the quarter ended December 31, 2000 and the period ended March 13,
2001, the Company filed the following Reports on Form 8-K:

     Report dated November 27, 2000, regarding (i) the Court of Appeals
affirming the ACC's approval of the 1999 Settlement Agreement; (ii) a Maricopa
County Superior Court judge's final judgment related to the Rules; (iii) the
proposed timing of the transfer of generation assets; and (iv) the issues
related to generation expansion.

                                       93
<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
                                       (Registrant)


Date: March 13, 2001                   William J. Post
                                       -----------------------------------------
                                       (William J. Post, Chairman of the Board
                                       of Directors and Chief Executive Officer)


     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

        Signature                           Title                     Date
        ---------                           -----                     ----

William J. Post                   Principal Executive Officer     March 13, 2001
-----------------------------     and Director
(William J. Post, Chairman
of the Board of Directors and
Chief Executive Officer)


Jack E. Davis                     Principal Accounting Officer,   March 13, 2001
-----------------------------     President and Director
(Jack E. Davis, President)


Michael V. Palmeri                Principal Financial Officer     March 13, 2001
-----------------------------
(Michael V. Palmeri,
Vice President, Finance)


Edward N. Basha, Jr.              Director                        March 13, 2001
-----------------------------
(Edward N. Basha, Jr.)


Michael L. Gallagher              Director                        March 13, 2001
-----------------------------
(Michael L. Gallagher)


Pamela Grant                      Director                        March 13, 2001
-----------------------------
(Pamela Grant)

                                       94
<PAGE>
Roy A. Herberger, Jr.             Director                        March 13, 2001
-----------------------------
(Roy A. Herberger, Jr.)


Martha O. Hesse                   Director                        March 13, 2001
-----------------------------
(Martha O. Hesse)


William S. Jamieson, Jr.          Director                        March 13, 2001
-----------------------------
(William S. Jamieson, Jr.)


Humberto S. Lopez                 Director                        March 13, 2001
-----------------------------
(Humberto S. Lopez)


Robert G. Matlock                 Director                        March 13, 2001
-----------------------------
(Robert G. Matlock)


Kathryn L. Munro                  Director                        March 13, 2001
-----------------------------
(Kathryn L. Munro)


Bruce J. Nordstrom                Director                        March 13, 2001
-----------------------------
(Bruce J. Nordstrom)

                                       95
<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, 2000

                                   ----------

                         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.