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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, 1999

                                       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 29, 2000, 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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<PAGE>
                                TABLE OF CONTENTS

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

PART I
     Item 1.  Business......................................................   2
     Item 2.  Properties....................................................  11
     Item 3.  Legal Proceedings.............................................  14
     Item 4.  Submission of Matters to a Vote of Security Holders...........  14

PART II
     Item 5.  Market for Registrant's Common Stock and Related Security
              Holder Matters................................................  14
     Item 6.  Selected Financial Data.......................................  15
     Item 7.  Financial Review..............................................  16
     Item 7A  Quantitative and Qualitative Disclosures about Market Risk....  21
     Item 8.  Financial Statements and Supplementary Data...................  22
     Item 9.  Changes In and Disagreements with Accountants on Accounting
              and Financial Disclosure......................................  51

PART III
     Item 10. Directors and Executive Officers of the Registrant............  51
     Item 11. Executive Compensation........................................  51
     Item 12. Security Ownership of Certain Beneficial Owners and
              Management....................................................  51
     Item 13. Certain Relationships and Related Transactions................  51

PART IV
     Item 14. Exhibits, Financial Statements, Financial Statement Schedules,
              and Reports on Form 8-K.......................................  52

SIGNATURES..................................................................  73

                                        i
<PAGE>
                                    GLOSSARY

ACC -- Arizona Corporation Commission

ACC STAFF -- Staff of the Arizona Corporation Commission

AFUDC -- Allowance for Funds Used During Construction

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

APS -- Arizona Public Service Company

CC&N -- Certificate of convenience and necessity

CHOLLA -- Cholla Power Plant

CHOLLA 4 -- Unit 4 of the Cholla Power Plant

COMPANY -- Arizona Public Service Company

CUC -- Citizens Utilities Company

EPA -- United States Environmental Protection Agency

FASB -- Financial Accounting Standards Board

FERC -- Federal Energy Regulatory Commission

FOUR CORNERS -- Four Corners Power Plant

GAAP -- Generally accepted accounting principles

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

NGS -- Navajo Generating Station

NRC -- Nuclear Regulatory Commission

PALO VERDE -- Palo Verde Nuclear Generating Station

PINNACLE WEST -- Pinnacle West Capital Corporation, an Arizona corporation, the
                 Company's parent

SEC -- Securities and Exchange Commission

SALT RIVER PROJECT -- Salt River Project Agricultural Improvement and Power
                      District

                                       1
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                                     PART I

                                ITEM 1. BUSINESS

THE COMPANY

     We were  incorporated  in 1920  under the laws of Arizona  and are  engaged
principally  in  serving  electricity  in the State of  Arizona.  Our  principal
executive offices are located at 400 North Fifth Street, Phoenix,  Arizona 85004
(telephone  602-250-1000).  Pinnacle West owns all of the outstanding  shares of
our common stock.

     We are Arizona's  largest  electric  utility,  with 827,000  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.  During
1999, no single  purchaser or user of energy accounted for more than 2% of total
electric revenues. See Note 16 of Notes to Financial Statements for a discussion
of business  segments.  At December 31, 1999, we employed  6,234  people,  which
includes employees assigned to joint projects where we are project manager.

     This document  contains  forward-looking  statements that involve risks and
uncertainties.  Words such as "estimates,"  "expects,"  "anticipates,"  "plans,"
"believes,"   "projects,"  and  similar  expressions  identify   forward-looking
statements.  These risks and uncertainties  include, but are not limited to, the
ongoing  restructuring of the electric  industry;  the outcome of the regulatory
proceedings  relating to the restructuring;  regulatory,  tax, and environmental
legislation;  our  ability  to  successfully  compete  outside  our  traditional
regulated  markets;  regional economic  conditions,  which could affect customer
growth;  the cost of debt  and  equity  capital;  weather  variations  affecting
customer usage;  technological  developments in the electric industry;  and Year
2000 issues.  See  "Competition"  in this Item for a discussion of some of these
factors.

COMPETITION

     RETAIL

     The ACC has  regulatory  authority  over us in matters  relating  to retail
electric rates, the issuance of securities, and the transaction of business with
affiliated parties.  See Note 3 of Notes to Financial Statements in Item 8 for a
discussion of the electric industry restructuring in Arizona, including our 1999
Settlement  Agreement,  ACC  rules  for  the  introduction  of  retail  electric
competition,  and Arizona legislative initiatives.  See also "Financial Review -
Competition  and  Industry   Restructuring"  in  Item  7.  In  addition  to  the
introduction  of competition  pursuant to the  Settlement  Agreement and the ACC
rules, we are subject to varying  degrees of competition in certain  territories
adjacent  to or within  areas  that we serve that are also  currently  served by
other utilities in our region (such as Tucson Electric Power Company,  Southwest
Gas  Corporation,  and  Citizens  Utility  Company)  as  well  as  cooperatives,
municipalities,   electrical  districts,   and  similar  types  of  governmental
organizations (principally Salt River Project).

     We face  competitive  challenges  from  low-cost  hydroelectric  power  and
natural  gas fuel,  as well as the  access  of some  utilities  to  preferential
low-priced  federal  power and other  subsidies.  In addition,  some  customers,
particularly industrial and large commercial,  may own and operate facilities to
generate their own electric energy requirements. Such facilities may be operated
by the customers themselves or by other entities engaged for such purpose.

     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 that competition to sell capacity will remain vigorous.  Our rates for
wholesale power sales and transmission services are subject to regulation by the
FERC. During 1999, approximately 23% of our electric operating revenues resulted
from such sales and charges.

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     The National Energy Policy Act of 1992 has promoted  increased  competition
in the wholesale electric power markets.  The Energy Act reformed  provisions of
the Public Utility  Holding Company Act of 1935 (the "1935 Act") and the Federal
Power  Act  to  remove  certain  barriers  to  competition  for  the  supply  of
electricity.  For example, the Energy Act permits the FERC to order transmission
access for third parties to transmission  facilities  owned by another entity so
that  independent  suppliers  and other third  parties can sell at  wholesale to
customers wherever located. The Energy Act does not, however, permit the FERC to
issue an order requiring transmission access to retail customers.

     Effective  July 9, 1996, a FERC  decision  requires all electric  utilities
subject to the FERC's  jurisdiction to file  transmission  tariffs which provide
competitors   with  access  to   transmission   facilities   comparable  to  the
transmission owners' access for wholesale transactions,  establishes information
requirements,  and provides for recovery of certain  wholesale  stranded  costs.
Retail stranded costs  resulting from a  state-authorized  retail  direct-access
program are the responsibility of the states,  unless a state lacks authority to
impose rates to recover such costs,  in which case FERC will consider  doing so.
We have filed a revised open access tariff in accordance with this decision.  We
do not believe that this  decision  will have a material  adverse  impact on our
results of operations or financial position.

     REGULATORY ASSETS

     Our  major   regulatory   assets  are   deferred   income  taxes  and  rate
synchronization  cost  deferrals.  As a result of our September 1999  Settlement
Agreement,  we have  discontinued  the  application  of  Statement  of Financial
Accounting  Standards  No. 71,  "Accounting  for the Effects of Certain Types of
Regulation," for our generation  operations.  This means that regulatory assets,
unless  reestablished as recoverable  through ongoing regulated cash flows, were
eliminated and the generation  assets were tested for impairment.  We determined
that the generation assets were not impaired. Prior to the 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.  See  Notes  1, 3,  and 10 of  Notes  to  Financial
Statements in Item 8 for additional information.

     COMPETITIVE STRATEGIES

     We  are  pursuing  strategies  to  maintain  and  enhance  our  competitive
position. These strategies include (i) cost management,  with an emphasis on the
reduction of variable costs (fuel, operations,  and maintenance expenses) and on
increased productivity through technological  efficiencies;  (ii) a focus on our
core  business  through  customer  service,   distribution  system  reliability,
business  segmentation,  and the anticipation of market opportunities;  (iii) an
emphasis on good regulatory relationships; (iv) asset maximization (e.g., higher
capacity factors and lower forced outage rates);  (v)  strengthening our capital
structure  and financial  condition;  (vi)  leveraging  core  competencies  into
related  areas,  such as energy  management  products  and  services;  and (vii)
operating a trading floor and implementing a risk management  program to provide
for more  stability  of prices  and the  ability  to retain or grow  incremental
margins through more competitive  pricing and risk management.  Underpinning our
competitive  strategies  are the strong  growth  characteristics  of our service
territory.  As competition in the electric utility industry continues to evolve,
we will continue to evaluate  strategies and alternatives  that will position us
to compete effectively in a more competitive, restructured industry.

GENERATING FUEL AND PURCHASED POWER

     1999 ENERGY MIX

     Our  sources of energy  during  1999 were:  coal - 29.9%;  nuclear - 22.4%;
purchased power - 43.2%; gas - 4.4%; and other - 0.1%.

     COAL SUPPLY

     LEASES NGS and Four Corners are located on the Navajo  Reservation and held
under  easements  granted by the federal  government  as well as leases from the
Navajo Nation. See "Properties- Plant Sites Leased from the

                                       3
<PAGE>
Navajo  Nation"  in Item 2. Most of the coal for  Cholla is  supplied  by 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.
Remaining coal  requirements  are purchased on the spot market.  All of the coal
for Four Corners is purchased  from a coal  supplier  with a long-term  lease of
coal reserves owned by the Navajo Nation. The coal for NGS comes from a supplier
with a long-term lease with the Navajo Nation and the Hopi Tribe. See Note 12 of
Notes to Financial Statements in Item 8 for information regarding our obligation
for coal mine reclamation.

     CONTRACTS Cholla  presently has sufficient coal under current  contracts to
ensure a reliable fuel supply through 2005.  Portions of the fuel supply are bid
on the spot market to take advantage of competitive  pricing options.  Following
expiration  of current  contracts,  there are numerous  competitive  fuel supply
options available to ensure continuous plant operation.  Cholla also has certain
requirements  for low  sulfur  coal and the  current  supplier  is  expected  to
continue to provide  most of Cholla's low sulfur coal  requirements  through the
current  contract.  There are  sufficient  reserves of low sulfur coal available
from other suppliers to ensure the continued  operation of Cholla for its useful
life.  The sulfur  content of coal at Cholla for 1999 was 0.47%.  Average prices
paid for all coal supplied from reserves dedicated under existing contracts were
slightly lower than,  but  comparable  to, 1998. For the years  remaining on the
contracts after 2000, prices will be reduced.

     Four Corners is a  mine-mouth  operation  which is under  contract for coal
through  2004.  There are options to extend the contract  through the plant site
lease  expiration in 2017.  The sulfur content of Four Corners coal for 1999 was
0.77%, and the units are equipped with scrubbers. The average price paid for all
coal  supplied  under  the  existing  contract  was  slightly  lower  than,  but
comparable  to,  1998.  The Four  Corners  lease  waives,  until July 2001,  the
requirement  that we, as well as our fuel  supplier,  pay  certain  taxes to the
Navajo Nation.  In September 1997, a settlement  agreement was finalized between
the coal  supplier,  the Navajo  Nation,  and Four Corners  participants,  which
settled  certain  issues  in the  lease  regarding  the  obligation  of the fuel
supplier to pay taxes prior to the  expiration of tax waivers in 2001.  Pursuant
to this agreement, the coal supplier currently pays a possessory interest tax to
the Navajo  Nation,  which is  contractually  reimbursed  by  participants.  The
parties also agreed to  investigate  alternative  contractual  arrangements  and
business  relationships  before  2001 in an  effort to  permit  the  electricity
generated  at Four  Corners  to be  priced  competitively.  We  anticipate  that
additional  taxes will be levied by the Navajo Nation upon the expiration of the
tax waivers;  however, we cannot currently predict the outcome of this matter or
the amount of the additional taxes.

     NGS is under contract with its coal supplier  through 2011, with options to
extend through the plant site lease.  The sulfur content of coal at NGS for 1999
was 0.53%,  and the units are equipped  with  scrubbers.  Average price paid for
coal supplied in 1999 under the existing contract was lower than, but comparable
to, 1998.  The NGS 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.

     NATURAL GAS SUPPLY

     We are a party to  contracts  with a number of natural gas  suppliers  that
allow us to purchase natural gas in the method we determine to be most economic.
Currently,  we are purchasing the majority of our natural gas requirements  from
numerous companies under these contracts.  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:

     *    the mining and milling of uranium ore to produce uranium concentrates,
     *    the conversion of uranium concentrates to uranium hexafluoride,
     *    the enrichment of uranium hexafluoride,
     *    the fabrication of fuel assemblies,

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<PAGE>
     *    the utilization of fuel assemblies in reactors and
     *    the storage of spent fuel and the disposal thereof.

The Palo  Verde  participants  have  made  contractual  arrangements  to  obtain
quantities  of  uranium  concentrates  anticipated  to  be  sufficient  to  meet
operational  requirements  through 2002. Existing contracts and options could be
utilized to meet  approximately 88% of requirements in 2003, 88% of requirements
in 2004,  49% of  requirements  in  2005,  and 16% of  requirements  in 2006 and
beyond.  Spot purchases on the uranium market will be made, as  appropriate,  in
lieu of any uranium that might be obtained through contractual options.

     The  Palo  Verde   participants  have  contracted  for  uranium  conversion
services. Existing contracts and options could be utilized to meet approximately
70% of requirements in 2000, 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.

     SPENT NUCLEAR FUEL AND WASTE DISPOSAL. Pursuant to the Nuclear Waste Policy
Act of 1982, as amended in 1987, the United States  Department of Energy ("DOE")
is  obligated  to  accept  and  dispose  of all  spent  nuclear  fuel and  other
high-level  radioactive  wastes  generated by domestic power reactors.  The NRC,
pursuant to the Waste Act, requires operators of nuclear power reactors to enter
into spent fuel  disposal  contracts  with DOE.  Under the Waste Act, DOE was to
develop the  facilities  necessary for the storage and disposal of spent nuclear
fuel and to have the first such facility in operation by 1998. That facility was
to be a permanent  repository.  DOE has  announced  that such a  repository  now
cannot be  completed  before  2010.  In July 1996,  the United  States  Court of
Appeals for the District of Columbia  Circuit (D.C.  Circuit) ruled that the DOE
has an obligation to start disposing of spent nuclear fuel no later than January
31, 1998.  By way of letter dated  December 17, 1996,  DOE informed us and other
contract  holders  that  DOE  anticipates  that it  would  be  unable  to  begin
acceptance of spent nuclear fuel for disposal in a repository or interim storage
facility by January 31, 1998. In November 1997,  the D.C.  Circuit issued a Writ
of Mandamus  precluding  DOE from excusing its own delay on the grounds that DOE
has not yet prepared a permanent repository or interim storage facility.  On May
5, 1998, the D.C.  Circuit issued a ruling refusing to order DOE to begin moving
spent nuclear fuel.  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.

     Several  bills  have  been   introduced  in  Congress   contemplating   the
construction of a central interim storage facility; however, there is resistance
to certain features of these bills both in 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  storage  capacity in  existing  fuel  storage  pools at Palo Verde
which,  with certain  modifications,  could  accommodate all fuel expected to be
discharged from normal operation of Palo Verde through about 2002.  Construction
of a new facility  for on-site dry storage of spent fuel is underway.  Once this
facility is completed  and  approvals  are  granted,  we believe that spent fuel
storage or disposal methods will be available for use by Palo Verde to allow its
continued operation beyond 2002.

     A new low-level  waste facility was built in 1995 on-site which could store
an amount of waste  equivalent  to ten years of normal  operation at Palo Verde.
Although some low-level waste has been stored on-site, 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.

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<PAGE>
     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.

PURCHASED POWER AGREEMENTS

     In  addition  to that  available  from  its own  generating  capacity  (see
"Properties"  in Item 2), we purchase  electricity  from other  utilities  under
various arrangements. One of the most important of these is a long-term contract
with Salt River Project.  This contract may be canceled by Salt River Project on
three years' notice and requires Salt River Project to make available, and us to
pay for,  certain amounts of electricity.  The amount of electricity 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 316 MW January  through May 1999, and starting June
1999  changed to 302 MW. In 1999,  we received  approximately  1,056,200  MWh of
energy under the contract and paid about $43.9 million for capacity availability
and  energy  received.  See  Note  3 of  Notes  to  Financial  Statements  for a
discussion of amendments to this contract and other  agreements  with Salt River
Project.

     In September  1990, we entered into a thirty year agreement  under which we
and PacifiCorp  engage in one-for-one  seasonal capacity  exchanges.  We receive
electricity from PacifiCorp  during our summer peak season.  We will have 480 MW
of generating capacity available to us under the agreements until 2020. In 1999,
we had 480 MW of generating  capacity  available from PacifiCorp and we received
approximately 572,382 MWh of energy under the capacity exchange.

CONSTRUCTION PROGRAM

     During the years 1997 through 1999, we incurred  approximately $962 million
in capital expenditures. Utility capital expenditures for the years 2000 through
2002 are expected to be primarily for expanding  transmission  and  distribution
capabilities to meet customer growth,  upgrading  existing  facilities,  and for
environmental  purposes.  Capitalized  expenditures,  including expenditures for
environmental  control  facilities,  for the years 2000  through  2002 have been
estimated as follows:

                              (Millions of Dollars)

              By Year                               By Major Facilities
              -------                               -------------------
2000                      $   384         Production                     $   255
2001                          342         Transmission and Distribution      691
2002                          334         General                            114
                          -------                                        -------
     Total                $ 1,060              Total                     $ 1,060
                          =======                                        =======

     The amounts for 2000 through 2002 exclude  capitalized  interest  costs and
include  capitalized  property  taxes and about  $30-$35  million  each year for
nuclear fuel. We conduct a continuing review of our construction program.

MORTGAGE REPLACEMENT FUND REQUIREMENTS

     So long as any of our first mortgage bonds are outstanding, we are required
for each  calendar year to deposit with the trustee under our mortgage cash in a
formularized  amount related to net additions to our mortgaged utility plant. We
may satisfy all or any part of this "replacement  fund" requirement by utilizing
redeemed or retired bonds, net property additions, or property retirements.  For
1999, the replacement fund requirement  amounted to approximately  $143 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

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replacement  fund.  This is  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. Pursuant to the Clean Air Act, the EPA adopted regulations that address
visibility  impairment  in  certain   federally-protected  areas  which  can  be
reasonably  attributed to specific sources.  In September 1991, the EPA issued a
final rule that  limited  sulfur  dioxide  emissions at NGS. One NGS unit had to
comply  with this  rule in 1997,  one in 1998,  and the last unit in 1999.  Salt
River Project is the NGS operating agent. Salt River Project estimates a capital
cost  of  $430  million  and  annual   operations  and   maintenance   costs  of
approximately   $14  million  for  all  three  units,  for  NGS  to  meet  these
requirements.  We are required to fund 14% of these  expenditures.  About all of
these capital costs have been incurred.

     The Clean Air Act also 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." Each existing utility unit is granted a certain
number  of  "allowances."  For  Phase  II  plants,  which  include  our  plants,
allowances  will be required  beginning  in the year 2000 to operate the 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.  These  limitations  require  certain plants to install  additional
pollution control equipment. In December 1996, the EPA issued rules for nitrogen
oxides emissions  limitations that would have required us to install  additional
pollution  control equipment at Four Corners by January 1, 2000. On February 14,
1997,  we filed a Petition for Review in the United  States Court of Appeals for
the District of Columbia.  We alleged that the EPA  improperly  classified  Four
Corners Unit 4 in these rules,  thereby  subjecting  Unit 4 to a more  stringent
emission   limitation.   ARIZONA  PUBLIC   SERVICE   COMPANY  V.  UNITED  STATES
ENVIRONMENTAL  PROTECTION  AGENCY,  No.  97-1091.  In February  1998,  the Court
vacated  the  Unit 4  emission  limitation  and  remanded  the  issue to EPA for
reconsideration.  In December 1999,  EPA's direct final rule,  which  classified
Four Corners Unit 4 as we had proposed, became final. We do not currently expect
this rule to have a  material  impact on our  financial  position  or results of
operations.

     With respect to protection of visibility in certain  specified  areas,  the
Clean  Air  Act  requires  the EPA to  conduct  a  study  concerning  visibility
impairment  in  those  areas  and  to  identify  sources  contributing  to  such
impairment.  Interim findings of this study indicate that any beneficial  effect
on  visibility  as a result  of the  Amendments  would  be  offset  by  expected
population and industry growth. The Clean Air Act also requires EPA to establish
a  "Grand  Canyon  Visibility  Transport  Commission"  to  complete  a study  on
visibility  impairment in the "Golden Circle of National  Parks" in the Colorado
Plateau.  NGS,  Cholla,  and Four Corners are located near the Golden  Circle of
National  Parks.  The  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 containing
requirements to eliminate all man-made emissions causing  visibility  impairment
in certain specified areas, including the Golden Circle of National Parks in the
Colorado Plateau. The 2008 implementation plans must also include  consideration
and potential  application of best available  retrofit  technology  ("BART") for
major stationary sources which came into operation between August

                                       7
<PAGE>
1962 and August 1977, such as the Navajo Generating Station,  Cholla Power Plant
and  Four  Corners  Power  Plant.  The  nine  western  states  and  tribes  that
participated in the Grand Canyon Visibility  Transport  Commission  process will
have the option to follow an  alternate  implementation  plan and  schedule  for
areas considered by the Commission.  Under this option,  those states and tribes
would submit  implementation plans by 2003, which would incorporate the emission
reduction scheme adopted in the Commission's  recommendations and application of
BART by 2018, possibly using an emission trading program.  Any states and tribes
that implement this option will also have to submit revised implementation plans
in 2008  to  address  visibility  in  certain  specified  areas  that  were  not
considered  by the  Commission.  Because  Arizona and the Navajo Nation have the
discretion to choose between the national or Commission options and a variety of
pollution  controls to meet the  requirements  of the regional  haze rules,  the
actual impact on us cannot be determined at this time.

     Also, in July 1997,  EPA  promulgated  final  National  Ambient Air Quality
Standards for ozone and  particulate  matter.  Pursuant to the 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.  These standards were  challenged and the court  determined that EPA's
promulgation  of  the  standards  violated  the  constitutional  prohibition  on
delegation of legislative power. The court remanded the ozone standard,  vacated
the coarse  particulate  matter  standard,  and invited the parties to brief the
court on vacating or remanding the fine particulate  matter standard.  We cannot
currently  predict EPA's response to this decision.  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 or results of operations.

     With respect to hazardous air pollutants  emitted by electric utility steam
generating  units,  the Clean Air Act requires  two studies.  The results of the
first  study  indicated  an impact  from  mercury  emissions  from such units in
certain  unspecified  areas.  The EPA has not yet stated  whether or not mercury
emissions limitations will be imposed. Secondly, the EPA will complete a general
study by December 2000  concerning  the  necessity of  regulating  hazardous air
pollutant  emissions from such units under the Clean Air Act.  Because we cannot
speculate  as to the  ultimate  requirements  by the EPA,  we  cannot  currently
estimate the capital expenditures,  if any, which may be required as a result of
these studies.

     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 to have a
material impact on our financial position or results of operations.

     FEDERAL  IMPLEMENTATION PLAN. In September 1999, the EPA proposed a Federal
Implementation  Plan  ("FIP") to set air  quality  standards  at  certain  power
plants,  including  the Navajo  Generating  Station and the Four  Corners  Power
Plant.  The comment  period on this proposal  ended in November 1999. The FIP is
similar to current Arizona  regulation of NGS and New Mexico  regulation of Four
Corners,  with minor  modifications.  We do not  currently  expect FIP to have a
material impact on our financial position or results of operations.

     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").  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  or  results  of
operations.

     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:

                                        8
<PAGE>
     *    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 or results of operations.

     PURPORTED NAVAJO ENVIRONMENTAL REGULATION

     Four  Corners  and NGS 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 NGS 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 NGS. By separate  letters  dated
October 12 and October  13,  1995,  the Four  Corners  participants  and the NGS
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 NGS.  On October 17,  1995,  the Four  Corners
participants and the NGS 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 NGS and

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

On October 18, 1995, the Navajo Nation and the Four Corners and NGS 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.

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. We are one of a number of parties

                                       9
<PAGE>
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 is  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  less-utilized  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 recently issued a decision  confirming that certain groundwater rights may
be available to the federal  government and Indian tribes.  We and other parties
have  petitioned  the U.S.  Supreme Court for review of this  decision.  Another
issue important to the claims is pending on appeal to the Arizona Supreme Court.
No trial date concerning our water rights claims has been set in this matter.

     We have also filed claims to water in the Little  Colorado River  Watershed
in Arizona in an action pending in the Apache County 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.

                                       10
<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
                                                                    ---------
Other.............................................................      5,600
                                                                    ---------
     Total                                                          3,986,900
                                                                    =========

----------
(1) West Phoenix steam units (108,300 kW) are currently mothballed.


RESERVE MARGIN

     Our 1999 peak one-hour demand on our electric system was recorded on August
24, 1999 at 4,934,700 kW,  compared to the 1998 peak of 5,027,000 kW recorded on
July 16.  Taking into account  additional  capacity  then  available to us under
traditional  long-term  purchase  power  contracts as well as our own generating
capacity, our capability of meeting system demand on August 24, 1999 amounted to
4,754,600  kW, for an installed  reserve  margin of (4.4%).  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 1999 peak  amounted to 3,587,100 kW, for a
margin of (27.5%).  Firm purchases,  including  short-term  seasonal  purchases,
totaling 1,643,000 kW were in place at the time of the peak ensuring the ability
to meet the load requirement, with an actual reserve margin of 9.1%.

PLANT SITES LEASED FROM NAVAJO NATION

     LEASES NGS 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.

                                       11
<PAGE>
     TAX AND ROYALTY 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 NGS 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

     The NRC recently amended its rules on financial assurance  requirements for
the  decommissioning of nuclear power plants. The amended rules became effective
on November  23,  1998.  The amended  rules  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
rules regarding the introduction of retail electric  competition in Arizona (see
Note 3 of Notes to Financial  Statements) currently 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 2
of Notes to Financial Statements in Item 8 for additional  information about our
nuclear decommissioning costs.

     PALO VERDE LIABILITY AND INSURANCE MATTERS

     See  "Palo  Verde  Nuclear  Generating  Station"  in  Note 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.

                                       12
<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.

                                       13
<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  ("Peabody"),
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 the Navajo and Mohave  Generating
Stations.  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 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 "Regulatory Matters" in
Note  3 of  Notes  to  Financial  Statements  in  Item  8  for a  discussion  of
competition  and  the  rules  regarding  the  introduction  of  retail  electric
competition  in Arizona 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 its  complaints the Company 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.

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

     Not applicable.

                                     PART II

                     ITEM 5. MARKET FOR REGISTRANT'S COMMON
                    STOCK AND RELATED 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 1999 and 1998.


                             COMMON STOCK DIVIDENDS
                             (THOUSANDS OF DOLLARS)

       QUARTER                                  1999             1998
       -------                                 -------          -------
     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.

                                       14
<PAGE>
                         ITEM 6. SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
                                               1999         1998         1997         1996         1995
                                            ----------   ----------   ----------   ----------   ----------
                                                                (Thousands of Dollars)
<S>                                         <C>          <C>          <C>          <C>          <C>
Electric Operating Revenues                 $2,292,798   $2,006,398   $1,878,553   $1,718,272   $1,614,952
Fuel Expenses                                  795,494      545,297      443,571      329,489      275,487

Operating Expenses                           1,108,380    1,090,290    1,063,157    1,023,575      957,711
                                            ----------   ----------   ----------   ----------   ----------
   Operating Income                            388,924      370,811      371,825      365,208      381,754
Other Income                                    20,990       20,448       21,586       35,217       25,548

Interest Deductions ___ Net                    141,592      136,012      141,918      156,954      167,732
                                            ----------   ----------   ----------   ----------   ----------
   Income Before Extraordinary Charge          268,322      255,247      251,493      243,471      239,570
Extraordinary Charge - Net of Tax              139,885           --           --           --           --
                                            ----------   ----------   ----------   ----------   ----------
Net Income                                     128,437      255,247      251,493      243,471      239,570

Preferred Dividends                              1,016        9,703       12,803       17,092       19,134
                                            ----------   ----------   ----------   ----------   ----------
Earnings for Common Stock                   $  127,421   $  245,544   $  238,690   $  226,379   $  220,436
                                            ==========   ==========   ==========   ==========   ==========
Total Assets                                $6,117,624   $6,393,299   $6,331,142   $6,423,222   $6,418,262
                                            ==========   ==========   ==========   ==========   ==========
Capital Structure:
   Common Stock Equity                      $1,983,174   $1,975,755   $1,849,324   $1,729,390   $1,621,555
   Non-Redeemable Preferred Stock                   --       85,840      142,051      165,673      193,561
   Redeemable Preferred Stock                       --        9,401       29,110       53,000       75,000

   Long-Term Debt Less Current Maturities    1,997,400    1,876,540    1,953,162    2,029,482    2,132,021
                                            ----------   ----------   ----------   ----------   ----------
     Total Capitalization                    3,980,574    3,947,536    3,973,647    3,977,545    4,022,137

   Commercial Paper                             38,300      178,830      130,750       16,900      177,800
   Current Maturities of Long-Term Debt        114,711      164,378      104,068      153,780        3,512
                                            ----------   ----------   ----------   ----------   ----------
     Total                                  $4,133,585   $4,290,744   $4,208,465   $4,148,225   $4,203,449
                                            ==========   ==========   ==========   ==========   ==========
</TABLE>

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

                                       15
<PAGE>
                            ITEM 7. FINANCIAL REVIEW


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

     *    the changes in our earnings from 1998 to 1999 and from 1997 to 1998
     *    the factors impacting our business, including competition and electric
          industry restructuring
     *    the effects of regulatory agreements on our results and outlook
     *    our capital needs and resources and
     *    our management of market risks.

Throughout this Financial  Review,  we refer to specific "Notes" in the Notes to
Financial  Statements  that begin on page 30. These Notes add further details to
the discussion.

RESULTS OF OPERATIONS

1999 COMPARED  WITH 1998.  Our 1999  earnings  decreased  $118 million from 1998
earnings   primarily  because  of  the  effects  of  a  $140  million  after-tax
extraordinary charge for a regulatory  disallowance related to our comprehensive
Settlement  Agreement  that was approved by the Arizona  Corporation  Commission
(ACC) in September 1999. See "Regulatory Agreements" below and Notes 1 and 3 for
additional  information  about the  regulatory  disallowance  and the Settlement
Agreement. Earnings excluding the extraordinary charge increased $21 million - a
9% increase - over 1998 earnings primarily because of increases in the number of
customers and in the average amount of  electricity  used by customers and lower
financing  costs.  These positive impacts more than offset the effects of retail
electricity  price  reductions  and higher utility  operations  and  maintenance
expense. See Note 3 for additional information about the price reductions.

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

     *    increased power marketing and trading revenues ($219 million)
     *    increases  in the  number  of  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).

The  increase  in power  marketing  revenues  resulted  from  higher  prices and
increased  activity  in western  U.S.  bulk power  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 more than offset by lower  employee  benefit  costs and  movement of
certain marketing functions to APS Energy Services in early 1999.

1998 COMPARED WITH 1997. Our 1998 earnings  increased $7 million - a 3% increase
- over 1997 earnings  primarily  because of an increase in  customers,  expanded
power  marketing  and trading  activities,  and lower  financing  costs.  In the
comparison,  these  positive  factors  more than  offset  the  effects of milder
weather, the prior year's benefits of the two fuel-related  settlements recorded
in 1997,  and retail price  reductions.  See Note 3 for  additional  information
about the price reductions.

                                       16
<PAGE>
In 1998,  electric  operating  revenues increased $128 million primarily because
of:

     *    increased power marketing and trading revenues ($94 million)
     *    increases  in the  number  of  customers  and the  average  amount  of
          electricity used by customers ($77 million) and
     *    miscellaneous factors ($8 million).

As mentioned above,  these positive factors were partially offset by the effects
of milder weather ($33 million) and reductions in retail prices ($18 million).

The  increase  in power  marketing  revenues  resulted  from  higher  prices and
increased  activity in western U.S. bulk power  markets.  The revenue  increases
were  accompanied by an increase in purchased power expenses.  These  activities
contributed positively to earnings in both periods; the contribution in 1998 was
higher than in 1997.

The two  fuel-related  settlements  increased 1997 pretax  earnings by about $21
million.  The income statement  reflects these settlements as reductions in fuel
expense and as other income.

Operations and maintenance  expense  increased $13 million  primarily because of
customer growth, initiatives related to competition,  and expansion of our power
marketing and trading function.

Depreciation and amortization  expense increased $11 million because we had more
plant in service.

Financing  costs decreased by $9 million  primarily  because of lower amounts of
outstanding debt and preferred stock.

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: 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 included accelerated  amortization
of our deferred investment tax credits (ITCs).

As part of the 1999  Settlement  Agreement,  we reduced  our rates for  standard
offer  service for  customers  with loads less than 3  megawatts  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  related to the 1996  regulatory  agreement (see below).  For customers
having  loads 3 megawatts  or greater,  standard  offer rates will be reduced in
annual increments that total 5% through 2002.

Also,  under the  Settlement  Agreement a regulatory  disallowance  removed $234
million  before  income  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.  Before the ACC approved the 1999
Settlement  Agreement,  we were recovering  substantially  all of our regulatory
assets through accelerated amortization over an eight-year period that would end
June 30, 2004 under the 1996 agreement. For more details, see Note 1.

The regulatory  assets to be recovered under this  Settlement  Agreement are now
being amortized as follows:

                              (Millions of Dollars)

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

                                       17
<PAGE>
Also,  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 the  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,  which was  included in the July 1, 1999 1.5%
          price reduction under the 1999 Settlement Agreement.

CAPITAL NEEDS AND RESOURCES

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 our operations and, to the extent necessary, external financing.

As part of the 1996 regulatory agreement, we received annual cash infusions from
Pinnacle West of $50 million from 1996 through 1999. During the period from 1997
through  1999,  we paid for all of our capital  expenditures  with cash from our
operations. We expect to do so in 2000 through 2002 as well.

Our  capital  expenditures  in 1999 were $332  million.  Our  projected  capital
expenditures for the next three years are: $384 million in 2000; $342 million in
2001; and $334 million in 2002. These amounts include about $30-$35 million each
year for nuclear fuel. In general,  most of the projected  capital  expenditures
are for:

     *    expanding transmission and distribution  capabilities to meet customer
          growth
     *    upgrading existing utility property and
     *    environmental purposes.

During 1999, we redeemed about $323 million of long-term debt and $96 million of
preferred  stock,  including  premiums,  with cash from operations and long- and
short-term  debt.  We no  longer  have  any  outstanding  preferred  stock.  Our
long-term debt redemption  requirements and payment obligations on a capitalized
lease for the next three years are  approximately:  $115  million in 2000;  $253
million  in 2001;  and $125  million  in 2002.  In  addition,  we made  optional
redemptions  of about $89 million of long-term  debt in January  2000.  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, 1999, we had credit  commitments  from various banks totaling
about $350  million,  which were  available  either to support  the  issuance of
commercial  paper or to be used as bank  borrowings.  At the end of 1999, we had
about  $38  million  of  commercial  paper and $50  million  of  long-term  bank
borrowings outstanding.

In February  1999,  we issued $125  million of unsecured  long-term  debt and in
November 1999, we issued $250 million of unsecured long-term debt.

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.

COMPETITION AND INDUSTRY RESTRUCTURING

The  electric  industry  is  undergoing  significant  change.  It is moving to a
competitive,   market-based   structure  from  a  highly-regulated,   cost-based
environment in which companies have been entitled to recover their costs and to

                                       18
<PAGE>
earn fair returns on their invested capital in exchange for commitments to serve
all customers within designated service territories.  See "Results of Operations
-  Regulatory  Agreements"  and  Note 3 for  additional  information  about  our
Settlement  Agreement  with the ACC  related  to the  implementation  of  retail
electric   competition,   the  ACC  rules  that  provide  a  framework  for  the
introduction of retail electric  competition in Arizona,  and other  competitive
developments, including an agreement with Salt River Project.

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 a discussion of legislative developments.

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

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 our Settlement Agreement (see Note 3), we discontinued the application
of SFAS No. 71 for our  generation  operations.  This meant that the  generation
assets  were tested for  impairment  and the  portion of the  regulatory  assets
deemed to be unrecoverable  through ongoing regulated cash flows was eliminated.
We  determined  that the  generation  assets  were not  impaired.  A  regulatory
disallowance  ($140 million after income taxes) was reported as an extraordinary
charge  on the  income  statement.  See  Note 1 for  additional  information  on
regulatory  accounting and Note 3 for  additional  information on the Settlement
Agreement.

YEAR 2000 READINESS DISCLOSURE

Some  companies  expected  to face  problems on January 1, 2000 in the case that
computer  systems and equipment  would not properly  recognize  calendar  dates.
During 1997, we had initiated a comprehensive  company-wide Year 2000 program to
review and resolve all Year 2000 issues in mission  critical systems in a timely
manner to ensure the reliability of electric  service to our customers.  We have
spent about $5 million to be Year 2000 ready.  To date, we have not  experienced
any material Year 2000 related  problems,  and we do not  anticipate  any in the
future.

ACCOUNTING MATTERS

We describe a new  standard on  accounting  for  derivatives  in Note 2. The new
standard on derivatives is effective for us in 2001. We are currently evaluating
what impact it will have on our  financial  statements.  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.

RISK MANAGEMENT

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, 1999 and December 31, 1998. The interest

                                       19
<PAGE>
rates  presented in the tables below  represent  the weighted  average  interest
rates for the years ended December 31, 1999 and December 31, 1998.

EXPECTED MATURITY/PRINCIPAL REPAYMENT
DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)

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

EXPECTED MATURITY/PRINCIPAL REPAYMENT
DECEMBER 31, 1998
(THOUSANDS OF DOLLARS)

                     Short-Term        Variable Long-Term     Fixed Long-Term
                  ------------------   ------------------   --------------------
                  Interest             Interest             Interest
                    Rates    Amount      Rates    Amount      Rates     Amount
                  --------  --------   --------  --------   --------  ----------
1999                5.88%   $178,830       --    $     --     7.24%   $  164,378
2000                  --          --       --          --     5.79%      114,711
2001                  --          --       --          --     7.48%        2,488
2002                  --          --       --          --     8.13%      125,000
2003                  --          --     5.94%    125,000       --         --
Years thereafter      --          --     3.39%    456,860     7.75%    1,058,963
                            --------             --------             ----------
Total                       $178,830             $581,860             $1,465,540
                            ========             ========             ==========
Fair value                  $178,830             $581,860             $1,525,900
                            ========             ========             ==========

COMMODITY PRICE RISK. We are exposed to the impact of market fluctuations in the
price and  distribution  costs of electricity,  natural gas, coal, and emissions
allowances. We employ established procedures to manage our 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 these
derivative  transactions for trading and to hedge certain natural gas in storage
as  well  as  purchases  and  sales  of   electricity,   fuels,   and  emissions
allowances/credits.

As of December 31, 1999, a  hypothetical  adverse  price  movement of 10% in the
market  price of our  commodity  derivative  portfolio  would  decrease the fair
market value of these contracts by approximately $6 million.  This analysis does
not include the favorable impact this same hypothetical price move would have on
the underlying position being hedged with the commodity derivative portfolio.

                                       20
<PAGE>
We are exposed to credit losses in the event of  non-performance  or non-payment
by counterparties.  We use a credit management process to assess and monitor our
financial exposure to counterparties.  We do not expect counterparty defaults to
materially impact our financial  condition,  results of operations,  or net cash
flow.

FORWARD-LOOKING STATEMENTS

The above discussion contains forward-looking  statements that involve risks and
uncertainties.  Words such as "estimates,"  "expects,"  "anticipates,"  "plans,"
"believes,"   "projects,"  and  similar  expressions  identify   forward-looking
statements.  These risks and uncertainties  include, but are not limited to, the
ongoing  restructuring of the electric  industry;  the outcome of the regulatory
proceedings  relating to the restructuring;  regulatory,  tax, and environmental
legislation;  our  ability  to  successfully  compete  outside  our  traditional
regulated  markets;  regional economic  conditions,  which could affect customer
growth;  the cost of debt  and  equity  capital;  weather  variations  affecting
customer usage;  technological  developments in the electric industry;  and Year
2000 issues.

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  "Financial  Review"  in  Item  7  for  a  discussion  of  quantitative  and
qualitative disclosures about market risk.

                                       21
<PAGE>
                          ITEM 8. FINANCIAL STATEMENTS
                             AND SUPPLEMENTARY DATA

                          INDEX TO FINANCIAL STATEMENTS

                                                                            Page
                                                                            ----

Report of Management.......................................................  23

Independent Auditors' Report...............................................  24

Statements of Income for 1999, 1998, and 1997..............................  25

Balance Sheets as of December 31, 1999 and 1998............................  26

Statements of Cash Flows for 1999, 1998, and 1997..........................  28

Statements of Retained Earnings for 1999, 1998, and 1997...................  29

Notes to Financial Statements..............................................  30

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

                                       22
<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.  Such information was prepared in accordance with generally
accepted  accounting  principles  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.

Management  maintains and relies upon systems of internal accounting controls. A
limiting factor in all systems of internal  accounting  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  accounting  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
Chief Executive Officer                 Vice President and Controller
                                        Pinnacle West Capital Corporation

                                       23
<PAGE>
                          INDEPENDENT AUDITORS' REPORT


We have  audited  the  accompanying  balance  sheets of Arizona  Public  Service
Company as of December 31, 1999 and 1998 and the related  statements  of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 1999.  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  generally   accepted  auditing
standards.  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 the Company at December 31, 1999 and 1998
and the results of its operations and its cash flows for each of the three years
in the period ended  December 31, 1999 in  conformity  with  generally  accepted
accounting principles.

Deloitte & Touche LLP

Deloitte & Touche LLP
Phoenix, Arizona
February 18, 2000

                                       24
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                              STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                         Year Ended December 31,
                                                   -----------------------------------------
                                                      1999           1998           1997
                                                   -----------    -----------    -----------
                                                            (Thousands of Dollars)
<S>                                                <C>            <C>            <C>
Electric Operating Revenues ....................   $ 2,292,798    $ 2,006,398    $ 1,878,553
                                                   -----------    -----------    -----------
Fuel Expenses:
   Fuel for electric generation ................       243,849        231,967        201,341
   Purchased power .............................       551,645        313,330        242,230
                                                   -----------    -----------    -----------
     Total .....................................       795,494        545,297        443,571
                                                   -----------    -----------    -----------

Operating Revenues Less Fuel Expenses ..........     1,497,304      1,461,101      1,434,982
                                                   -----------    -----------    -----------
Other Operating Expenses:
   Operations and maintenance excluding
     fuel expenses .............................       437,729        419,433        406,025
   Depreciation and amortization (Note 1).......       382,057        376,574        365,671
   Income taxes (Note 10) ......................       192,015        192,207        184,737
   Other taxes .................................        96,579        102,076        106,724
                                                   -----------    -----------    -----------
     Total .....................................     1,108,380      1,090,290      1,063,157
                                                   -----------    -----------    -----------

Operating Income ...............................       388,924        370,811        371,825
                                                   -----------    -----------    -----------
Other Income (Deductions):
   Income taxes (Note 10) ......................        32,527         32,751         31,413
   Other -- net ................................       (11,537)       (12,303)        (9,827)
                                                   -----------    -----------    -----------
     Total .....................................        20,990         20,448         21,586
                                                   -----------    -----------    -----------

Income Before Interest Deductions ..............       409,914        391,259        393,411
                                                   -----------    -----------    -----------
Interest Deductions:
   Interest on long-term debt ..................       132,676        137,214        140,931
   Interest on short-term borrowings ...........         8,272          7,481          9,404
   Debt discount, premium and expense ..........         7,323          7,580          7,791
   Capitalized interest ........................        (6,679)       (16,263)       (16,208)
                                                   -----------    -----------    -----------
     Total .....................................       141,592        136,012        141,918
                                                   -----------    -----------    -----------
Income Before Extraordinary Charge .............       268,322        255,247        251,493
Extraordinary Charge - net of income
   taxes of $94,115 (Note 1) ...................       139,885             --             --
                                                   -----------    -----------    -----------
Net Income .....................................       128,437        255,247        251,493

Preferred Stock Dividend Requirements ..........         1,016          9,703         12,803
                                                   -----------    -----------    -----------
Earnings for Common Stock ......................   $   127,421    $   245,544    $   238,690
                                                   ===========    ===========    ===========
</TABLE>

See Notes to Financial Statements.

                                       25
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                                 BALANCE SHEETS
                                     ASSETS

                                                            December 31,
                                                      -------------------------
                                                         1999          1998
                                                      -----------   -----------
                                                        (Thousands of Dollars)
Utility Plant (Notes 5, 8 and 9):
 Electric plant in service and held for
  future use ......................................   $ 7,545,575   $ 7,265,604
 Less accumulated depreciation and amortization ...     3,026,041     2,814,762
                                                      -----------   -----------
   Total ..........................................     4,519,534     4,450,842
 Construction work in progress ....................       184,764       228,643
 Nuclear fuel, net of amortization of $66,357
   and $68,569 ....................................        49,114        51,078
                                                      -----------   -----------
   Utility Plant -- net ...........................     4,753,412     4,730,563
                                                      -----------   -----------

Investments and Other Assets (Note 13) ............       208,457       183,549
                                                      -----------   -----------
Current Assets:
 Cash and cash equivalents ........................         7,477         5,558
 Accounts receivable:
   Service customers ..............................       201,704       205,999
   Other ..........................................        35,684        23,213
   Allowance for doubtful accounts ................        (1,538)       (1,725)
 Accrued utility revenues .........................        72,919        67,740
 Materials and supplies (at average cost) .........        69,977        69,074
 Fossil fuel (at average cost) ....................        21,869        13,978
 Deferred income taxes (Note 10) ..................         8,163         3,999
 Other ............................................        30,885        26,695
                                                      -----------   -----------
   Total Current Assets ...........................       447,140       414,531
                                                      -----------   -----------

Deferred Debits:
 Regulatory assets (Note 1) .......................       613,729       980,084
 Unamortized debt issue costs .....................        15,172        14,916
 Other ............................................        79,714        69,656
                                                      -----------   -----------
   Total Deferred Debits ..........................       708,615     1,064,656
                                                      -----------   -----------
   Total ..........................................   $ 6,117,624   $ 6,393,299
                                                      ===========   ===========

See Notes to Financial Statements.

                                       26
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                                 BALANCE SHEETS
                                   LIABILITIES

                                                             December 31,
                                                       ------------------------
                                                          1999          1998
                                                       ----------    ----------
                                                        (Thousands of Dollars)
Capitalization (Notes 4 and 5):
  Common stock ......................................  $  178,162    $  178,162
  Additional paid - in capital ......................   1,246,804     1,195,625
  Retained earnings .................................     558,208       601,968
                                                       ----------    ----------
    Common stock equity .............................   1,983,174     1,975,755
  Non-redeemable preferred stock ....................          --        85,840
  Redeemable preferred stock ........................          --         9,401
  Long-term debt less current maturities ............   1,997,400     1,876,540
                                                       ----------    ----------
    Total Capitalization ............................   3,980,574     3,947,536
                                                       ----------    ----------
Current Liabilities:
  Commercial paper (Note 6) .........................      38,300       178,830
  Current maturities of long-term debt (Note 5) .....     114,711       164,378
  Accounts payable ..................................     170,662       145,139
  Accrued taxes .....................................      62,858        59,827
  Accrued interest ..................................      32,299        31,218
  Customer deposits .................................      24,682        26,815

  Other .............................................      26,248        16,755
                                                       ----------    ----------
    Total Current Liabilities .......................     469,760       622,962
                                                       ----------    ----------
Deferred Credits and Other:
  Deferred income taxes (Note 10) ...................   1,178,085     1,312,007
  Deferred investment tax credit (Note 10) ..........       4,839        32,465
  Unamortized gain -- sale of utility
   plant (Note 9) ...................................      73,212        77,787
  Customer advances for construction ................      38,150        31,451

  Other .............................................     373,004       369,091
                                                       ----------    ----------
    Total Deferred Credits and Other ................   1,667,290     1,822,801
                                                       ----------    ----------
Commitments and Contingencies (Note 12)

  Total .............................................  $6,117,624    $6,393,299
                                                       ==========    ==========

                                       27
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                            STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
                                                                   Year Ended December 31,
                                                              -----------------------------------
                                                                1999         1998         1997
                                                              ---------    ---------    ---------
                                                                     (Thousands of Dollars)
<S>                                                           <C>          <C>          <C>
Cash Flows from Operations:
  Net income ............................................    $ 128,437     $ 255,247     $ 251,493
  Items not requiring cash:
    Depreciation and amortization .......................      382,057       376,574       365,671
    Nuclear fuel amortization ...........................       31,371        32,856        32,702
    Deferred income taxes -- net ........................      (29,654)      (26,374)      (55,278)
    Deferred investment tax credit -- net ...............      (27,626)      (27,628)      (27,630)
    Extraordinary Charge -- net of income taxes .........      139,885            --            --
  Changes in certain current assets and liabilities:
    Accounts receivable -- net ..........................       (8,363)      (56,490)      (11,069)
    Accrued utility revenues ............................       (5,179)       (9,181)       (3,089)
    Materials, supplies and fossil fuel .................       (8,794)       (2,797)        7,793
    Other current assets ................................       (4,190)       (2,166)       (1,762)
    Accounts payable ....................................       22,992        33,731       (56,710)
    Accrued taxes .......................................        3,031       (26,059)         (441)
    Accrued interest ....................................        1,081          (442)       (7,455)
    Other current liabilities ...........................        7,833        (4,654)       (3,997)
  Other -- net ..........................................       (4,922)      (29,641)       46,625
                                                             ---------     ---------     ---------
    Net cash provided ...................................      627,959       512,976       536,853
                                                             ---------     ---------     ---------
Cash Flows from Investing:
  Capital expenditures ..................................     (322,547)     (319,142)     (307,876)
  Capitalized interest ..................................       (6,679)      (16,263)      (16,208)
  Other .................................................       (8,173)       (8,593)      (15,982)
                                                             ---------     ---------     ---------
    Net cash used .......................................     (337,399)     (343,998)     (340,066)
                                                             ---------     ---------     ---------
Cash Flows from Financing:
  Long-term debt ........................................      392,952       126,245       109,906
  Short-term borrowings -- net ..........................     (140,530)       48,080       113,850
  Common equity infusion from parent ....................       50,000        50,000        50,000
  Dividends paid on common stock ........................     (170,000)     (170,000)     (170,000)
  Dividends paid on preferred stock .....................       (1,393)      (10,279)      (13,307)
  Repayment of preferred stock ..........................      (96,499)      (75,517)      (47,201)
  Repayment and reacquisition of long-term debt .........     (323,171)     (144,501)     (240,004)
                                                             ---------     ---------     ---------
    Net cash used .......................................     (288,641)     (175,972)     (196,756)
                                                             ---------     ---------     ---------

Net increase (decrease) in cash and cash equivalents.....        1,919        (6,994)           31
Cash and cash equivalents at beginning of year ..........        5,558        12,552        12,521
                                                             ---------     ---------     ---------

Cash and cash equivalents at end of year ................    $   7,477     $   5,558     $  12,552
                                                             =========     =========     =========
Supplemental Disclosure of Cash Flow Information:
  Cash paid during the year for:
    Interest (excluding capitalized interest) ...........    $ 132,995     $ 128,627     $ 141,991
    Income taxes ........................................    $ 189,002     $ 235,475     $ 236,676
</TABLE>

See Notes to Financial Statements.

                                       28
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                         STATEMENTS OF RETAINED EARNINGS


                                                      Year Ended December 31,
                                                  ------------------------------
                                                    1999       1998       1997
                                                  --------   --------   --------
                                                      (Thousands of Dollars)

Retained earnings at beginning of year .........  $601,968   $528,798   $460,106
Add: Net income ................................   128,437    255,247    251,493
                                                  --------   --------   --------
  Total ........................................   730,405    784,045    711,599
                                                  --------   --------   --------
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     12,801
  Other ........................................     1,181      2,374         --
                                                  --------   --------   --------
    Total deductions ...........................   172,197    182,077    182,801
                                                  --------   --------   --------
Retained earnings at end of year ...............  $558,208   $601,968   $528,798
                                                  ========   ========   ========

See Notes to Financial Statements.

                                       29
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE  OF  OPERATIONS.   We  are  Arizona's  largest  electric  utility,   with
approximately  827,000  customers.  We provide  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,  sell and deliver electricity and energy-related
products and services to wholesale  and retail  customers in the western  United
States.

ACCOUNTING  RECORDS.  Our accounting  records are maintained in accordance  with
generally  accepted  accounting  principles (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  Federal  Energy
Regulatory Commission (FERC). The accompanying  financial statements reflect the
rate-making  policies of these  commissions.  For our regulated  operations,  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.

During 1997, the Emerging  Issues Task Force (EITF) of the Financial  Accounting
Standards  Board (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.

In September 1999, our Settlement  Agreement was approved by the ACC (see Note 3
for a discussion of the agreement). We have discontinued the application of SFAS
No. 71 for our generation operations. This means that the generation assets were
tested for impairment  and the portion of regulatory  assets that were deemed to
be  unrecoverable  through  ongoing  regulated  cash  flows was  eliminated.  We
determined  that  the  generation   assets  were  not  impaired.   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. Prior to the 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 this  Settlement  Agreement are now
being amortized as follows:

                              (Millions of Dollars)

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

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

                                       30
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


The balance sheets  include the amounts  listed below for generation  assets not
subject to SFAS No. 71:

                             (Thousands of Dollars)

                                                      December 31,  December 31,
                                                         1999          1998
                                                      -----------   -----------
Electric plant in service and held for future use ..  $ 3,770,234   $ 3,680,482
Accumulated depreciation and amortization ..........   (1,817,589)   (1,681,099)
Construction work in progress ......................       67,306       107,324
Nuclear fuel, net of amortization ..................       49,114        51,078

COMMON  STOCK All of the  outstanding  shares of our  common  stock are owned by
Pinnacle West (see Note 4).

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.

UTILITY PLANT AND DEPRECIATION  Utility plant is the term we use to describe the
business  property and  equipment  that  supports  electric  service.  We report
utility plant at its original cost, which includes:

     *    material and labor
     *    contractor costs
     *    construction overhead costs (where applicable) and
     *    capitalized   interest   or  an   allowance   for  funds  used  during
          construction.

We 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 1997 through 1999 the rates, as prescribed by our regulators,  ranged from
a low of 1.51% to a high of 20%. The  weighted-average  rate for 1999 was 3.34%.
We depreciate non-utility property and equipment over the estimated useful lives
of the related assets, ranging from 3 to 50 years.

CAPITALIZED INTEREST Capitalized interest represents the cost of debt funds used
to finance  construction of utility plant. 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 6.65% for 1999, 6.88% for 1998, and 7.25% for 1997.

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 expect to produce with that fuel.
We then multiply that rate by

                                       31
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


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 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.

CASH AND CASH  EQUIVALENTS  For purposes of reporting cash flows, we define cash
equivalents  as highly  liquid  investments  that will mature in three months or
less.

RECLASSIFICATIONS  We  reclassified  certain  prior year amounts for  comparison
purposes with the 1999 presentation.

2. ACCOUNTING MATTERS

In June 1998,  the  Financial  Accounting  Standards  Board issued SFAS No. 133,
"Accounting  for  Derivative  Instruments  and  Hedging  Activities,"  which  is
effective  for us in 2001.  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. The standard also provides  specific  guidance
for  accounting  for  derivatives  designated  as  hedging  instruments.  We are
currently  evaluating  what  impact  this  standard  will have on our  financial
statements.

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 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

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 Settlement  Agreement,  with
some modifications. On December 13, 1999, two parties filed lawsuits challenging
the ACC's approval of the Settlement  Agreement.  One of the parties  questioned
the  authority of the ACC to approve the  Settlement  Agreement and both parties
challenged several specific provisions of the Settlement Agreement.

                                       32
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


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

     *    We will reduce rates for standard  offer  service for  customers  with
          loads  less than 3  megawatts  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)  includes the July 1, 1999 retail
          price decrease of approximately $11 million annually ($7 million after
          income  taxes)  related to the 1996  regulatory  agreement.  See "1996
          Regulatory Agreement" below. For customers having loads 3 megawatts or
          greater,  standard  offer  rates will be reduced in annual  increments
          that total 5% through 2002.

     *    Unbundled  rates being  charged by us for  competitive  direct  access
          service (for example,  distribution  services)  became  effective upon
          approval of the Settlement Agreement, retroactive to July 1, 1999, and
          also will be 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  the  Company  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 our  "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  will be 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),  with  an
          additional   140   megawatts   being  made   available   to   eligible
          non-residential  customers.  Unless  subject to judicial or regulatory
          restraint,  we will open our distribution  system to retail access for
          all customers on January 1, 2001.

     *    Prior to the Settlement  Agreement,  we were recovering  substantially
          all of our  regulatory  assets  through July 1, 2004,  pursuant to the
          1996  regulatory  agreement.  In addition,  the  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  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   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 that 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. 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.

                                       33
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


     *    When the 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 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 Statement
of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation," 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 (Rules).  If any of the Rules conflict with the
Settlement Agreement,  the terms of the Settlement Agreement govern. 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 and the adoption or amendment of the Rules,
but two related cases filed by other utilities have been partially  decided in a
manner  adverse to those  utilities'  positions.  On January 14, 2000, a special
action was filed  requesting the Arizona Supreme Court to enjoin  implementation
of the Rules and decide whether the ACC can allow the  competitive  marketplace,
rather  than  the ACC,  to set  just and  reasonable  rates  under  the  Arizona
Constitution.  The issue of  competitively  set rates has been  decided by lower
Arizona  courts  in favor  of the ACC in four  separate  lawsuits,  two of which
relate to  telecommunications  companies.  The Supreme  Court denied to hear the
case as a special  action on March 17,  2000.  The lower court  litigation  will
continue.

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.

     *    The  Rules  require  each  affected  utility,  including  us,  to make
          available  at least 20% of its 1995  system  retail  peak  demand  for
          competitive  generation  supply  beginning  when the ACC makes a final
          decision on each utility's  stranded costs and unbundled  rates (Final
          Decision  Date) or January 1, 2001,  whichever  is  earlier,  and 100%
          beginning January 1, 2001. Under the Settlement Agreement, the Company
          will provide retail access to customers  representing  the minimum 20%
          required by the ACC and an additional 140 megawatts of non-residential
          load in 1999,  and to all  customers  as of January  1, 2001,  or such
          other dates as approved by the ACC.

     *    Subject to the 20%  requirement,  all  utility  customers  with single
          premise  loads  of one  megawatt  or  greater  will  be  eligible  for
          competitive  electric  services on the Final Decision Date,  which for
          the Company's customers was the approval of the Settlement  Agreement.
          Customers may also  aggregate  smaller loads to meet this one megawatt
          requirement.

     *    When effective,  residential  customers will be phased in at 1.25% per
          quarter  calculated  beginning on January 1, 1999,  subject to the 20%
          requirement above.

     *    Electric  service  providers that get  Certificates of Convenience and
          Necessity  (CC&Ns) 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.

                                       34
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


     *    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 Settlement  Agreement,  the
          Company  received  a  waiver  to  allow  transfer  of its  competitive
          generation  assets and services to  affiliates  no later than December
          31, 2002.

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  of
approximately $49 million ($29 million after income taxes),  or 3.4%,  effective
July 1, 1996;  approximately  $18 million ($11 million after income  taxes),  or
1.2%,  effective  July 1, 1997;  approximately  $17 million ($10  million  after
income taxes),  or 1.1%,  effective July 1, 1998; and  approximately $11 million
($7 million after income taxes), or 0.7%, effective as of July 1, 1999. The July
1,  1999 rate  decrease  was  included  in the first  rate  reduction  under the
Settlement  Agreement  discussed above.  The regulatory  agreement also required
Pinnacle West to infuse $200 million of common equity into us in annual payments
of $50 million from 1996 through 1999.  All of these equity  infusions were made
by December 31, 1999.

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

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

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

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

In addition,  the Arizona  legislature will review and make  recommendations for
the 1999-2000 legislative session on certain competitive issues.

GENERAL

We cannot  accurately  predict  the  impact of full  retail  competition  on our
financial position,  cash flows, or results of operation.  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  Energy  Policy  Act of 1992 and recent  rulemakings  by FERC have  promoted
increased  competition in the wholesale electric power markets. We do not expect
these rules to have a material impact on our financial statements.

                                       35
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


Several  electric  utility  industry  restructuring  bills have been  introduced
during the 106th Congress. Several of these bills are written to allow consumers
to choose their electricity suppliers beginning in 2000 and beyond. These bills,
other bills that 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.

AGREEMENT WITH SALT RIVER PROJECT

On April 25, 1998,  we entered into a  Memorandum  of Agreement  with Salt River
Project  in  anticipation  of, and to  facilitate,  the  opening of the  Arizona
electric  industry.  The ACC  approved the  Agreement on February 18, 1999.  The
Agreement contains the following major components:

     *    Both parties amended the Territorial  Agreement to remove any barriers
          to   the   provision   of   competitive    electricity    supply   and
          non-distribution services.

     *    Both  parties  amended the Power  Coordination  Agreement to lower the
          price that we pay Salt River Project for purchased power. During 1999,
          the price we paid Salt River Project for  purchased  power was reduced
          by  approximately  $3 million (pretax) and we estimate the decrease to
          be  approximately  $16  million  (pretax)  in 2000 and  annual  lesser
          amounts through 2006.

     *    Both  parties  agreed  on  certain  legislative   positions  regarding
          electric utility restructuring at the state and federal levels.

Certain provisions of the Agreement  (including those relating to the amendments
of the  Territorial  Agreement  and the  Power  Coordination  Agreement)  became
effective upon the introduction of competition.  See "Settlement  Agreement" and
"ACC Rules" above.

                                       36
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


4. COMMON AND PREFERRED STOCKS

On March 1, 1999, we redeemed all of our preferred  stock.  Common and preferred
stock balances at December 31, 1999 and 1998 are shown below:

<TABLE>
<CAPTION>
                                                       Number
                                                      of Shares              Par           Par Value
                                                     Outstanding            Value         Outstanding
                                              --------------------------     Per     -----------------------
                                Authorized       1999          1998         Share       1999         1998
                                -----------   -----------   ------------   -------   ----------   ----------
                                                                                     (Thousands of Dollars)
<S>                             <C>           <C>           <C>            <C>       <C>          <C>
Common Stock.................   100,000,000    71,264,947     71,264,947   $  2.50   $  178,162   $  178,162
                                              ===========   ============             ==========   ==========
Preferred Stock:
   Non-Redeemable:
   $1.10.....................       160,000            --        139,030   $ 25.00   $       --   $    3,476
   $2.50.....................       105,000            --         86,440     50.00           --        4,322
   $2.36.....................       120,000            --         32,520     50.00           --        1,626
   $4.35.....................       150,000            --         62,986    100.00           --        6,299
   Serial preferred..........     1,000,000
     $2.40  Series A.........                          --        200,587     50.00           --       10,029
     $2.625 Series C.........                          --        214,895     50.00           --       10,745
     $2.275 Series D.........                          --         90,691     50.00           --        4,534
     $3.25  Series E.........                                    304,475     50.00           --       15,224
   Serial preferred..........     4,000,000
     Adjustable rate --
       Series Q..............                          --        295,851    100.00           --       29,585
                                              -----------   ------------             ----------   ----------
       Total.................                          --      1,427,475             $       --   $   85,840
                                              ===========   ============             ==========   ==========
   Redeemable:
   Serial preferred:
     $10.00  Series U........                          --         94,011   $100.00   $       --   $    9,401
                                              ===========   ============             ==========   ==========
</TABLE>

Redeemable  preferred stock  transactions  during each of the three years in the
period ended December 31, 1999 are as follows:

<TABLE>
<CAPTION>
                                           Number of Shares                     Par Value
                                             Outstanding                       Outstanding
                                    ------------------------------    ------------------------------
                                                                         (Thousands of Dollars)
        Description                  1999       1998       1997         1999       1998       1997
        -----------                 --------   --------   --------    --------   --------   --------
<S>                                 <C>        <C>        <C>         <C>        <C>        <C>
Balance, January 1...............     94,011    291,098    530,000    $  9,401   $ 29,110   $ 53,000
   Retirements:
     $10.00 Series U.............    (94,011)  (197,087)  (118,902)     (9,401)   (19,709)   (11,890)
     $7.875 Series V.............         --         --   (120,000)         --         --    (12,000)
                                    --------   --------   --------    --------   --------   --------
Balance, December 31.............         --     94,011    291,098    $     --   $  9,401   $ 29,110
                                    ========   ========   ========    ========   ========   ========
</TABLE>

                                       37
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


5. LONG-TERM DEBT

The following  table presents the  components of long-term  debt  outstanding at
December 31, 1999 and December 31, 1998:

<TABLE>
<CAPTION>
                                                                                  December 31
                                                                            -----------------------
                                              Maturity Dates    Interest       1999         1998
                                              --------------    --------    ----------   ----------
                                                   (A)           Rates      (Thousands of Dollars)
<S>                                             <C>           <C>           <C>          <C>
First mortgage bonds                               1999          7.625%     $       --   $  100,000
                                                   2000           5.75%        100,000      100,000
                                                   2002          8.125%        125,000      125,000
                                                   2004          6.625%         80,000       85,000
                                                   2020          10.25%        100,550      100,550
                                                   2021           9.5%          45,140       45,140
                                                   2021            9%           72,370       72,370
                                                   2023           7.25%         70,650       91,900
                                                   2024           8.75%        121,668      121,668
                                                   2025            8%           47,075       88,300
                                                   2028           5.5%          25,000       25,000
                                                   2028          5.875%        154,000      154,000
Unamortized discount and premium                                                (5,860)      (6,482)
Pollution control bonds                          2024-2034     Adjustable      476,860      456,860
                                                                rate (b)
Funds held in trust account for certain
pollution control bonds                                                         (1,236)          --
Collateralized loan                              1999-2000       5.375% -       10,000       20,000
                                                                 6.125%
Unsecured notes                                    2005           6.25%        100,000      100,000
Unsecured notes                                    2004          5.875%        125,000           --
Floating rate notes                                2001        Adjustable      250,000
                                                                rate (c)
Senior notes(d)                                    1999           6.72%             --       50,000
Senior notes(d)                                    2006           6.75%         83,695      100,000
Debentures                                         2025            10%          75,000       75,000
Bank loans                                         2003        Adjustable       50,000      125,000
                                                                rate (e)
Capitalized lease obligation                     1999-2001      7.48% (f)        7,199       11,612
                                                                            ----------   ----------
   Total long-term debt                                                      2,112,111    2,040,918

Less current maturities                                                        114,711      164,378
                                                                            ----------   ----------
   Total long-term debt less current maturities                             $1,997,400   $1,876,540
                                                                            ==========   ==========
</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, 1999 was 3.15%
     And for December 31, 1998 was 3.39%.  Changes in short-term  interest rates
     would affect the costs associated with this debt.

                                       38
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


(c)  The weighted average rate for the year ended 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, 1999 was 5.50%
     And for December 31, 1998 was 5.94%.  Changes in short-term  interest rates
     would affect the costs associated with this debt.

(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 (see Note 9).

Principal  payments due on total  long-term  debt and sinking fund  requirements
over the next five years are approximately:

     *    $115 million in 2000
     *    $253 million in 2001
     *    $125 million in 2002
     *    $50 million in 2003 and
     *    $205 million in 2004.

First  mortgage  bondholders  share a lien on  substantially  all utility  plant
assets  (other than nuclear  fuel,  transportation  equipment,  and the combined
cycle plant). The mortgage bond indenture  restricts the payment of common stock
dividends under certain  conditions.  These conditions did not exist at December
31, 1999.

6. LINES OF CREDIT

We had committed  lines of credit with various banks of $350 million at December
31, 1999 and $400 million at December 31, 1998,  which were available  either to
support the issuance of commercial paper or to be used for bank borrowings.  The
commitment  fees at December 31, 1999 and 1998 for these lines of credit  ranged
from 0.07% to 0.125% per annum.  We had long-term bank borrowings of $50 million
outstanding  at December 31, 1999 and $125 million  outstanding  at December 31,
1998.

Our commercial  paper  borrowings  outstanding  were $38 million at December 31,
1999 and $179 million at December 31, 1998. The weighted  average  interest rate
on commercial  paper  borrowings  was 5.33% for the year ended December 31, 1999
and 5.88% for December 31, 1998. 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, 1999 and
1998 due to their  short  maturities.  We hold  investments  in debt and  equity
securities for purposes other than trading.  The December 31, 1999 and 1998 fair
values of such

                                       39
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


investments,  which we determine by using quoted market values or by discounting
cash flows at rates equal to our cost of  capital,  approximate  their  carrying
amounts.

The  carrying  value  of our  long-term  debt  (excluding  a  capitalized  lease
obligation) was $2.10 billion on December 31, 1999, with an estimated fair value
of $2.08 billion. On December 31, 1998, the carrying value of our long-term debt
(excluding a capitalized lease obligation) was $2.03 billion,  with an estimated
fair value of $2.11 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.

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, 1999.  Our share of operating and  maintaining  these
facilities  is included in the income  statement in operations  and  maintenance
expense.

<TABLE>
<CAPTION>
                                             Percent                               Construction
                                             Owned by    Plant in    Accumulated     Work in
                                             Company      Service    Depreciation    Progress
                                             -------      -------    ------------    --------
                                                          (Thousands of Dollars)
<S>                                         <C>       <C>            <C>            <C>
Generating Facilities:
   Palo Verde Nuclear Generating Station
     Units 1 and 3                            29.1%     $1,829,633     $751,567       $ 7,220
   Palo Verde Nuclear Generating Station
     Unit 2 (see Note 9)                      17.0%        572,574      240,696        17,145
   Four Corners Steam Generating Station
     Units 4 and 5                            15.0%        139,209       71,333           364
   Navajo Steam Generating Station
     Units 1, 2, and 3                        14.0%        230,536       94,332         4,555
   Cholla Steam Generating Station
     Common Facilities (a)                    62.8%(b)      68,643       38,068         1,679
Transmission Facilities:
   ANPP 500KV System                          35.8%(b)      68,133       21,446             7
   Navajo Southern System                     31.4%(b)      27,364       17,550            42
   Palo Verde-Yuma 500KV System               23.9%(b)      11,728        4,388            36
   Four Corners Switchyards                   27.5%(b)       3,071        1,855            --
   Phoenix-Mead System                        17.1%(b)      36,434        1,768            --
</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


                                       40
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


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  $46  million in 2000 and  approximately  $49  million per year in
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. The accelerated  amortization is included in
depreciation and amortization  expense on the Statements of Income.  The balance
of this regulatory asset at December 31, 1999 was $43 million. Lease expense was
approximately $42 million in each of the years 1997 through 1999.

We have a capital  lease on a  combined  cycle  plant,  which we sold and leased
back. The lease requires  semiannual  payments of $3 million  through June 2001,
and includes  renewal and purchase options based on fair market value. The plant
is included in plant in service at its original cost of $54 million; accumulated
amortization at December 31, 1999 was $51 million.

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

Miscellaneous lease expense was approximately $7 million in 1999, $10 million in
1998 and $8 million in 1997.

Estimated  future  minimum  lease  commitments,  excluding  the Palo  Verde  and
combined cycle leases, are as follows:

            Year                                (Dollars in Millions)
            ----
            2000                                       $  13
            2001                                          14
            2002                                          14
            2003                                          14
            2004                                          14
            Thereafter                                    82
                                                       -----
            Total future commitments                   $ 151
                                                       =====

10. 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  investment tax credits
(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

                                       41
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


construction.  We amortize this amount as the differences reverse. In accordance
with  the  1999  Settlement  Agreement,  we are  continuing  to  accelerate  the
amortization of the regulatory asset for income taxes over an eight-year  period
that will end on June 30, 2004. We have included this  accelerated  amortization
in depreciation and amortization expense on the Statements of Income.

The components of income tax expense for income before the extraordinary  charge
are as follows:

                                                  Year Ended December 31,
                                            -----------------------------------
                                              1999         1998         1997
                                            ---------    ---------    ---------
                                                   (Thousands of dollars)
Current:
   Federal ..............................   $ 175,227    $ 170,806    $ 187,701
   State ................................      41,541       42,652       48,531
                                            ---------    ---------    ---------
     Total current ......................     216,768      213,458      236,232

Deferred ................................     (29,654)     (26,374)     (55,278)
Investment tax credit amortization ......     (27,626)     (27,628)     (27,630)
                                            ---------    ---------    ---------
     Total expense ......................   $ 159,488    $ 159,456    $ 153,324
                                            =========    =========    =========

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

<TABLE>
<CAPTION>
                                                                 Year Ended December 31,
                                                           -----------------------------------
                                                             1999         1998         1997
                                                           ---------    ---------    ---------
                                                                  (Thousands of Dollars)
<S>                                                        <C>          <C>          <C>
Federal income tax expense at 35% statutory rate .......   $ 149,710    $ 145,146    $ 141,686
Increases (reductions) in tax expense resulting from:
   Tax under book depreciation .........................      14,575       17,848       14,694
   Investment tax credit amortization ..................     (27,626)     (27,628)     (27,630)
   State income tax -- net of federal
     income tax benefit.................................      24,135       23,024       23,160
   Other ...............................................      (1,306)       1,066        1,414
                                                           ---------    ---------    ---------
     Income tax expense ................................   $ 159,488    $ 159,456    $ 153,324
                                                           =========    =========    =========
</TABLE>

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

                                                              December 31,
                                                         -----------------------
                                                            1999         1998
                                                         ----------   ----------
                                                         (Thousands of Dollars)
Deferred tax assets:
   Deferred gain on Palo Verde Unit 2 sale/leaseback ..  $   29,446   $   31,285
   Other ..............................................     139,518      159,432
                                                         ----------   ----------
     Total deferred tax assets ........................     168,964      190,717
                                                         ----------   ----------
Deferred tax liabilities:
   Plant related ......................................   1,104,769    1,117,253
   Regulatory assets ..................................     234,117      381,472
                                                         ----------   ----------
     Total deferred tax liabilities ...................   1,338,886    1,498,725
                                                         ----------   ----------
Deferred income taxes -- net ..........................  $1,169,922   $1,308,008
                                                         ==========   ==========

                                       42
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


11. RETIREMENT PLANS AND OTHER BENEFITS

PENSION PLAN.  Through 1999, we sponsored a defined benefit pension plan for our
employees. As of January 1, 2000, this plan is now sponsored by Pinnacle West. 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 this plan 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, 1999 were mostly  domestic  and
international  common  stocks  and  bonds  and  real  estate.  Pension  expense,
including administrative costs, was:

     *    $4 million in 1999
     *    $10 million in 1998 and
     *    $9 million in 1997.

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

<TABLE>
<CAPTION>
                                                             1999        1998        1997
                                                           --------    --------    --------
                                                                (Thousands of Dollars)
<S>                                                        <C>         <C>         <C>
Service cost -- benefits earned during the period......   $ 24,266    $ 24,126    $ 19,881
Interest cost on projected benefit obligation .........     52,208      50,863      47,824
Expected return on plan assets ........................    (67,528)    (53,883)    (47,422)
Amortization of:
  Transition asset ....................................     (3,216)     (3,216)     (3,216)
  Prior service cost ..................................      2,063       2,063       2,063
                                                          --------    --------    --------
Net periodic pension cost .............................   $  7,793    $ 19,953    $ 19,130
                                                          ========    ========    ========
</TABLE>

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

                                                             1999        1998
                                                           --------    --------
                                                          (Thousands of Dollars)

Funded status -- Pension plan assets more than
  (less than) projected benefit obligation ..............  $ 37,784    $(38,957)
Unrecognized net transition asset .......................   (19,943)    (23,159)
Unrecognized prior service cost .........................    20,499      22,562
Unrecognized net actuarial gains ........................   (99,602)    (38,916)
                                                           --------    --------
Net pension liability recognized in the balance sheets ..  $(61,262)   $(78,470)
                                                           ========    ========

                                       43
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


The  following  table sets forth the defined  benefit  pension  plan's change in
projected benefit obligation for the plan years 1999 and 1998:

                                                           1999         1998
                                                         ---------    ---------
                                                         (Thousands of Dollars)
Projected pension benefit obligation
  at beginning of year ...............................   $ 721,229    $ 699,600
Service cost .........................................      24,266       24,126
Interest cost ........................................      52,208       50,863
Benefit payments .....................................     (29,444)     (29,384)
Actuarial gains ......................................     (35,348)     (23,976)
                                                         ---------    ---------
Projected pension benefit obligation
  at end of year .....................................   $ 732,911    $ 721,229
                                                         =========    =========


The following  table sets forth the defined benefit pension plan's change in the
fair value of plan assets for the plan years 1999 and 1998:

                                                           1999         1998
                                                         ---------    ---------
                                                         (Thousands of Dollars)
Fair value of pension plan assets at
 beginning of year ...................................   $ 682,272    $ 612,392
Actual return on plan assets .........................      92,867       85,764
Employer contributions ...............................      25,000       13,500
Benefit payments .....................................     (29,444)     (29,384)
                                                         ---------    ---------
Fair value of pension plan assets at end of year .....   $ 770,695    $ 682,272
                                                         =========    =========

We made the assumptions below to calculate
  the pension liability:
    Discount rate ....................................        7.75%        7.00%
    Rate of increase in compensation levels ..........        4.25%        3.50%
    Expected long-term rate of return on assets ......       10.00%       10.00%

EMPLOYEE   SAVINGS  PLAN   BENEFITS.   Through  1999,  we  sponsored  a  defined
contribution  savings  plan for  nearly all of our  employees.  As of January 1,
2000,  this plan is now  sponsored by Pinnacle West and covers nearly all of our
employees.  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 $4 million for each of the last
three years (1997-1999).

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.

                                       44
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


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:

     *    $6 million for 1999
     *    $9 million for 1998 and
     *    $9 million for 1997.

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

<TABLE>
<CAPTION>
                                                      1999        1998        1997
                                                    --------    --------    --------
                                                         (Thousands of Dollars)
<S>                                                 <C>         <C>         <C>
Service cost -- benefits earned during
 the period .....................................   $  8,676    $  7,676    $  6,865
Interest cost on accumulated benefit
 obligation .....................................     17,188      15,610      14,315
Expected return on plan assets ..................    (18,454)    (12,001)     (8,706)
Amortization of:
    Transition obligation .......................      7,652       7,652       7,652
    Net actuarial gains .........................     (5,095)     (2,927)     (2,647)
                                                    --------    --------    --------
Net periodic postretirement benefit cost ........   $  9,967    $ 16,010    $ 17,479
                                                    ========    ========    ========
</TABLE>

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

                                                           1999         1998
                                                         ---------    ---------
                                                         (Thousands of Dollars)

Funded status -- postretirement plan assets more than
  (less than) accumulated benefit obligation .........   $  27,930    $ (21,912)
Unrecognized net obligation at transition ............      99,482      107,134
Unrecognized net actuarial gains .....................    (127,338)     (86,131)
                                                         ---------    ---------
Net postretirement amount recognized
  in the balance sheets ..............................   $      74    $    (909)
                                                         =========    =========

The  following  table sets forth the  postretirement  benefit  plan's  change in
accumulated benefit obligation for the plan years 1999 and 1998:

                                                           1999         1998
                                                         ---------    ---------
                                                         (Thousands of Dollars)
Accumulated postretirement benefit
  obligation at beginning of year ....................   $ 235,322    $ 197,581
Service cost .........................................       8,675        7,676
Interest cost ........................................      17,188       15,610
Benefit payments .....................................      (8,761)     (10,347)
Actuarial (gains) losses .............................     (22,816)      24,802
                                                         ---------    ---------
Accumulated postretirement benefit
  obligation at end of year ..........................   $ 229,608    $ 235,322
                                                         =========    =========

                                       45
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


The following table sets forth the  postretirement  benefit plan's change in the
fair value of plan assets for the plan years 1999 and 1998:

                                                           1999         1998
                                                         ---------    ---------
                                                         (Thousands of Dollars)
Fair value of postretirement plan
  assets at beginning of year ........................   $ 213,410    $ 151,146
Actual return on plan assets .........................      42,975       47,284
Employer contributions ...............................       9,914       25,327
Benefit payments .....................................      (8,761)     (10,347)
                                                         ---------    ---------
Fair value of postretirement plan
  assets at end of year ..............................   $ 257,538    $ 213,410
                                                         =========    =========

We made the assumptions below to calculate the postretirement liability:

<TABLE>
<S>                                                                          <C>      <C>
   Discount rate...........................................................   7.75%    7.00%
   Expected long-term rate of return on assets-after tax...................   8.77%    8.73%
   Initial health care cost trend rate - under age 65......................   7.00%    7.50%
   Initial health care cost trend rate - age 65 and over...................   6.00%    6.50%
   Ultimate health care cost trend rate (reached in the year 2002) ........   5.00%    5.00%
</TABLE>

Assuming a 1%  increase  in the health  care cost trend  rate,  the 1999 cost of
postretirement  benefits other than pensions would increase by  approximately $5
million and the  accumulated  benefit  obligation  as of December 31, 1999 would
increase by approximately $37 million.

Assuming a 1%  decrease  in the health  care cost trend  rate,  the 1999 cost of
postretirement  benefits other than pensions would decrease by  approximately $4
million and the  accumulated  benefit  obligations as of December 31, 1999 would
decrease by approximately $29 million.

12. COMMITMENTS AND CONTINGENCIES

LITIGATION.  We are a 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.

PALO VERDE NUCLEAR GENERATING  STATION.  Under the Nuclear Waste Policy Act, DOE
was to develop the  facilities  necessary  for the storage and disposal of spent
fuel and to have the first such facility in operation by 1998. That facility was
to be a permanent  repository,  but DOE has announced that such a repository now
cannot be  completed  before  2010.  In response  to  lawsuits  filed over DOE's
obligation to accept used nuclear  fuel,  the United States Court of Appeals for
the D.C.  Circuit has ruled that DOE had an obligation to begin  accepting  used
nuclear fuel in 1998.  However,  the Court refused to issue an order  compelling
DOE to begin  moving  used fuel.  Instead,  the Court  ruled that any damages to
utilities  should be sought under the standard  contract  signed between DOE and
utilities,  including us. The United  States  Supreme Court has refused to grant
review of the D.C. Circuit's decision.

We have  capacity in  existing  fuel  storage  pools at Palo Verde  which,  with
certain modifications, could accommodate all fuel expected to be discharged from
normal  operation of Palo Verde through about 2002, and believe we could augment
that wet storage with new  facilities  for on-site dry storage of spent fuel for
an  indeterminate  period of  operation  beyond 2002,  subject to obtaining  any
required governmental  approvals.  We currently estimate that we will incur $113
million (in 1999 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,
1999,  we had  recorded a  liability  and  regulatory  asset of $37  million for
on-site interim nuclear fuel storage costs related to nuclear fuel

                                       46
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


burned to date. We currently believe that spent fuel storage or disposal methods
will be available for use by Palo Verde to allow its continued  operation beyond
2002.

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 29.1%
interest in the three Palo Verde units,  our maximum  potential  assessment  per
incident  for all  three  units is  approximately  $77  million,  with an annual
payment limitation of approximately $9 million.

The Palo Verde  participants  maintain "all risk"  (including  nuclear  hazards)
insurance for property damage to, and decontamination of, property at Palo Verde
in the aggregate  amount of $2.75 billion,  a substantial  portion of which must
first be applied to  stabilization  and  decontamination.  We have also  secured
insurance  against  portions of any  increased  cost of  generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the  three  units.  The  insurance  coverage  discussed  in this  and the
previous paragraph is subject to certain policy conditions and exclusions.

FUEL  AND  PURCHASED  POWER  COMMITMENTS.  We are a party  to  various  fuel and
purchased  power  contracts  with terms  expiring  from 2000  through  2020 that
include required purchase provisions. We estimate our 2000 contract requirements
to be about $177 million.  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 $57  million at  December  31,  1999 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  approved  by 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, 1999 was about $41 million.

CONSTRUCTION  PROGRAM.  Total capital expenditures in 2000 are estimated at $384
million.

13. NUCLEAR DECOMMISSIONING COSTS

We recorded $11 million for  decommissioning  expense in each of the years 1999,
1998,  and 1997.  We estimate it will cost about $1.8 billion  ($472  million in
1999 dollars) to decommission our 29.1% 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 include them in the accumulated  depreciation balance
until each unit is  retired.  Nuclear  decommissioning  costs are  recovered  in
rates.

Our current  estimates  are based on a 1998  site-specific  study for Palo Verde
that  assumes the prompt  removal/dismantlement  method of  decommissioning.  An
independent consultant prepared this study for us. 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  trusts  in  accordance  with  Nuclear   Regulatory   Commission  (NRC)
regulations.  The trust accounts are reported in "Investments  and Other Assets"
in our Balance Sheets at their market value of $176 million at December 31, 1999
and $146 million at

                                       47
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


December  31,  1998.  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 1999 and 1998 is as follows:


                            Electric                                  Earnings/
                            Operating    Operating    Net Income/    (Loss) for
Quarter Ended               Revenues     Income (a)    (Loss) (b)   Common Stock
-------------               --------     ----------    ----------   ------------
                                          (Thousands of Dollars)
1999
   March 31                 $413,983      $ 66,956     $ 33,795       $ 32,779
   June 30                   511,434        98,503       69,542         69,542
   September 30              867,504       150,914      (10,377)       (10,377)
   December 31               499,877        72,551       35,477         35,477

1998
   March 31                 $380,423      $ 63,541     $ 31,935       $ 29,057
   June 30                   441,715        81,299       52,184         49,749
   September 30              740,734       155,079      133,193        130,846
   December 31               443,526        70,892       37,935         35,892

----------
(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 ended  September 30, 1999 includes an  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 most  recent plan  provides  for the  granting of new options  (which may be
non-qualified  stock  options or incentive  stock  options) of up to 3.5 million
shares at a price per option not less than the fair market value on the date the
option is granted. The plan also provides for the granting of any combination of
restricted stock, stock appreciation rights or dividend equivalents.  The awards
outstanding under the incentive plans at December 31, 1999 approximate 1,441,124
non-qualified  stock options,  159,837  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.  This  statement  encourages,  but does not
require,  that a company  record  compensation  expense  based on the fair value
method.  We continue to recognize  expense based on Accounting  Principles Board
Opinion No. 25,

                                       48
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS


"Accounting  for Stock Issued to  Employees."  If we had  recorded  compensation
expense based on the fair value  method,  our net income would have been reduced
to the following pro forma amounts:

                                             1999          1998          1997
                                           --------      --------      --------
                                                  (Thousands of Dollars)
Net income
  As reported..........................    $128,437      $255,247      $251,493
  Pro forma (fair value method)........    $127,658      $254,640      $251,142

We did not consider  compensation costs for stock options granted before January
1, 1995. Therefore, future reported net income may not be representative of this
compensation cost calculation.

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:

                                             1999          1998          1997
                                           --------      --------      --------
Risk-free interest rate................      5.68%         4.54%         5.66%
Dividend yield.........................      3.33%         3.03%         4.50%
Volatility.............................     20.50%        18.80%        15.63%
Expected life (months).................        60            60            60

16. BUSINESS SEGMENTS

Historically,  we  reported  our  operations  as a single,  integrated  business
segment  due to our  regulated  operating  environment.  The  ACC  authorized  a
combined rate for supplying and delivering  electricity  to customers  which was
cost-based  and was  designed to recover the  Company's  operating  expenses and
investment in electric utility assets and to provide a return on the investment.

As a result of the 1999 Settlement Agreement,  our generation operations are now
deregulated for accounting purposes. For the purposes of complying with SFAS No.
131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS
No. 131), we are required to disclose  information  about our business  segments
separately.  Accordingly, we have separately identified expenses between the two
segments and allocated revenues and other expenses using a study that identifies
the portion of our base rates related to generation  and delivery.  We then used
that information to develop the financial  information of the business  segments
for each of the three years ended  December 31, 1999 (or as of December 31, 1999
and 1998, with respect to assets).

Beginning  in 1999,  we have two  principal  business  segments  (determined  by
products,  services and regulatory  environment) which consist of the generation
of  electricity   (generation   business   segment)  and  the  transmission  and
distribution   of  electricity   (delivery   business   segment).   Intercompany
eliminations  primarily relate to intercompany  sales of electricity.  Financial
data for business segments is provided as follows:

                                       49
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                Business Segments
                                              -----------------------
                                              Generation    Delivery   Eliminations    Total
                                              ----------   ----------   ----------   ----------
<S>                                           <C>          <C>          <C>          <C>
(Thousands of Dollars)
YEAR ENDED DECEMBER 31, 1999
Operating Revenues ........................   $  853,755   $2,292,798   $ (853,755)  $2,292,798
Operating Expenses ........................      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
                                              ----------   ----------   ----------   ----------
  Pre-Tax 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 ..............................   $2,321,778   $3,795,846   $       --   $6,117,624
                                              ==========   ==========   ==========   ==========
Capital Expenditures ......................   $   90,285   $  241,469   $       --   $  331,754
                                              ==========   ==========   ==========   ==========

YEAR ENDED DECEMBER 31, 1998
Operating Revenues ........................   $  858,340   $2,006,398   $ (858,340)  $2,006,398
Operating Expenses ........................      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
                                              ----------   ----------   ----------   ----------
  Pre-Tax 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   $3,993,740   $       --   $6,393,300
                                              ==========   ==========   ==========   ==========
Capital Expenditures ......................   $   85,767   $  241,638   $       --   $  327,405
                                              ==========   ==========   ==========   ==========

YEAR ENDED DECEMBER 31, 1997
Operating Revenues ........................   $  803,647   $1,878,553   $ (803,647)  $1,878,553
Operating Expenses ........................      471,992    1,297,802     (803,647)     966,147
                                              ----------   ----------   ----------   ----------
  Operating Margin ........................      331,655      580,751           --      912,406
Depreciation and Amortization .............      131,684      233,987           --      365,671
Interest and Preferred Stock Dividend
  Requirements ............................       50,311      104,410           --      154,721
                                              ----------   ----------   ----------   ----------
  Pre-Tax Margin ..........................      149,660      242,354           --      392,014
Income Taxes ..............................       44,898      108,426           --      153,324
                                              ----------   ----------   ----------   ----------
  Earnings for Common Stock ...............   $  104,762   $  133,928   $       --   $  238,690
                                              ==========   ==========   ==========   ==========
Capital Expenditures ......................   $   84,960   $  217,047   $       --   $  302,007
                                              ==========   ==========   ==========   ==========
</TABLE>

                                       50
<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.

                                       51
<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

27.1      --     Financial Data Schedule

     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

  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
</TABLE>

                                       52
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  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 of    Report
                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

  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
</TABLE>

                                       53
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  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 Indenture      4.10 to Registration              1-4473            4-9-97
                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>

                                       54
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  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

  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
</TABLE>

                                       55
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  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 Amended         10.3 to 1994 Form 10-K            1-4473            3-30-95
                and Restated                       Report
                Decommissioning Trust
                Agreement (PVNGS Unit 2)
                dated as of November 1, 1994

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

  10.10         Amendment No. 4 to Amended         10.5 to 1996 Form 10-K            1-4473            3-28-97
                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                    10.2 to June 1991 Form            1-4473            8-8-91
                Transactions 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 and/or    Statement
                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-Term     Report
                Power Transactions Agreement
                and Asset Purchase and Power
                Exchange Agreement between
                PacifiCorp and the Company
</TABLE>

                                       56
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  10.15         Restated Transmission              10.4 to 1995 Form 10-K            1-4473            3-29-96
                Agreement between PacifiCorp       Report
                and the Company dated
                April 5, 1995

  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, Four      Registration Statement
                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 Lease,     Pinnacle West
                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 and      Registration Statement
                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>

                                       57
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  10.23         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

  10.24         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

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

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

  10.27         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

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

                                       58
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  10.29         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
                Participation Agreement,
                dated August 23, 1973, among
                the Company, Salt River
                Project Agricultural
                Improvement and Power
                District, Southern California
                Edison Company, Public
                Service Company of New
                Mexico, El Paso Electric
                Company, Southern California
                Public Power Authority, and
                Department of Water and
                Power of the City of Los
                Angeles

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

  10.31(c)      Amendment No. 1, dated as of       10.5 to September 1986            1-4473            12-4-86
                November 1, 1986, to Facility      Form 10-Q Report by
                Lease, dated as of August 1,       means of Amendment No.
                1986, between State Street         1 on December 3, 1986
                Bank and Trust Company, as         Form 8
                successor to The First
                National Bank of Boston, in
                its capacity as Owner Trustee,
                as Lessor, and the Company,
                as Lessee

  10.32(c)      Amendment No. 2 dated as of        10.3 to 1988 Form 10-K            1-4473            3-8-89
                June 1, 1987 to Facility Lease     Report
                dated as of August 1, 1986
                between State Street Bank
                and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Lessor, and APS, as Lessee
</TABLE>

                                       59
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  10.33(c)      Amendment No. 3, dated as of       10.3 to 1992 Form 10-K            1-4473            3-30-93
                March 17, 1993, to Facility        Report
                Lease, dated as of August 1,
                1986, between State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Lessor, and the Company, as
                Lessee

  10.34         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

  10.35         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

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

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

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

                                       60
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  10.39(a)      Third Amendment to the             10.1 to September 1994            1-4473            11-10-94
                Arizona Public Service             Form 10-Q
                Company Directors' Deferred
                Compensation Plan effective
                as of May 1, 1993

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

  10.41(a)      Arizona Public Service             10.4 to 1988 Form 10-K            1-4473            3-8-89
                Company Deferred                   Report
                Compensation Plan, as
                restated, effective January 1,
                1984, and the second and
                third amendments thereto,
                dated December 22, 1986, and
                December 23, 1987, respectively

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

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

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

  10.45(a)      Pinnacle West Capital              10.10 to 1995 Form 10-K           1-4473            3-29-96
                Corporation, Arizona Public        Report
                Service Company, SunCor
                Development Company
                and El Dorado Investment
                Company Deferred
                Compensation Plan as
                amended and restated
                effective January 1, 1996
</TABLE>

                                       61
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  10.46(a)      First Amendment effective as       10.6 to Pinnacle West's           1-8962            3-30-00
                of January 1, 1998, 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

  10.47(a)      Second Amendment effective as      10.10 to Pinnacle West's          1-8962            3-30-00
                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

  10.48(a)      Arizona Public Service             10.11 to 1995 Form 10-K           1-4473            3-29-96
                Company Supplemental               Report
                Excess Benefit Retirement
                Plan as amended and
                restated on December 20, 1995

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

  10.50(a)      Pinnacle West Capital              10.7 to 1994 Form 10-K            1-4473            3-30-95
                Corporation and Arizona            Report
                Public Service Company
                Directors' Retirement Plan
                effective as of January 1, 1995

  10.51(a)      Arizona Public Service             10.1 to September 1997            1-4473            11-12-97
                Company Director                   Form 10-K Report
                Equity Plan

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

                                       62
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  10.53(a)      Letter Agreement dated             10.8 to 1996 Form 10-K            1-4473            3-28-97
                August 16, 1996 between            Report
                the Company and
                William L. Stewart

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

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

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

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

  10.58(a)      Employment Agreement,              10.1 to Pinnacle West's           1-8962            3-28-91
                effective as of February 5,        1990 Form 10-K
                1990, between Richard Snell
                and Pinnacle West

  10.59(a)      First Amendment to                 10.2 to Pinnacle West's           1-8962            4-1-96
                Employment Agreement,              1995 Form 10-K Report
                effective March 31, 1995,
                between Richard Snell and
                Pinnacle West

  10.60(a)      Second Amendment to                10.2 to Pinnacle West's           1-8962            3-31-97
                Employment Agreement,              1996 Form 10-K Report
                effective February 5, 1997,
                between Richard Snell and
                Pinnacle West

  10.61(a)(d)   Key Executive Employment and       10.1 to Pinnacle West's           1-8962            8-16-99
                Severance Agreement between        June 1999 Form 10-Q
                Pinnacle West and certain          Report
                executive officers of Pinnacle
                West and its subsidiaries

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

                                       63
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  10.63(a)      First Amendment dated              10.11 to Pinnacle West's          1-8962            3-30-00
                December 7, 1999 to the            1999 Form 10-K Report
                Pinnacle West Capital
                Corporation Stock Option
                and Incentive Plan

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

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

  10.66         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

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

  10.68(a)      2000 Management Variable           10.4 to Pinnacle West's           1-8962            3-30-00
                Incentive Plan (APS)               1999 Form 10-K Report

  10.69(a)      2000 Senior Management             10.5 to Pinnacle West's           1-8962            3-30-00
                Variable Incentive Plan (APS)      1999 Form 10-K Report

  10.70(a)      2000 Officer Variable              10.6 to Pinnacle West's           1-8962            3-30-00
                Incentive Plan (APS)               1999 Form 10-K Report
</TABLE>

                                       64
<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

  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
</TABLE>

                                       65
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  99.3(c)       Participation Agreement,           28.1 to September 1992            1-4473            11-9-92
                dated as of August 1, 1986,        Form 10-Q Report
                among PVNGS Funding
                Corp., Inc., Bank of America
                National Trust and Savings
                Association, State Street Bank
                and Trust Company, as
                successor to The First
                National Bank of Boston, in
                its individual capacity and as
                Owner Trustee, Chemical
                Bank, in its individual
                capacity and as Indenture
                Trustee, the Company, and
                the Equity Participant named
                therein

  99.4(c)       Amendment No. 1 dated as of        10.8 to September 1986            1-4473            12-4-86
                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>

                                       66
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  99.5(c)       Amendment No. 2, dated as of       28.4 to 1992 Form 10-K            1-4473            3-30-93
                March 17, 1993, to                 Report
                Participation Agreement,
                dated as of August 1, 1986,
                among PVNGS Funding
                Corp., Inc., PVNGS II
                Funding Corp., Inc., State
                Street Bank and Trust
                Company, as successor to The
                First National Bank of
                Boston, in its individual
                capacity and as Owner
                Trustee, Chemical Bank, in its
                individual capacity and as
                Indenture Trustee, the
                Company, and the Equity
                Participant named therein

  99.6(c)       Trust Indenture, Mortgage,         4.5 to Form S-3                   33-9480           10-24-86
                Security Agreement and             Registration Statement
                Assignment of Facility Lease,
                dated as of August 1, 1986,
                between State Street Bank
                and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Owner Trustee, and Chemical
                Bank, as Indenture Trustee

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

                                       67
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  99.8(c)       Supplemental Indenture No. 2       4.4 to 1992 Form 10-K             1-4473            3-30-93
                to Trust Indenture, Mortgage,      Report
                Security Agreement and
                Assignment of Facility Lease,
                dated as of August 1, 1986,
                between State Street Bank
                and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Owner Trustee, and Chemical
                Bank, as Indenture Trustee

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

  99.10(c)      Amendment No. 1, dated as of       10.10 to September 1986           1-4473            12-4-86
                November 1, 1986, to               Form 10-Q Report by
                Assignment, Assumption and         means of Amendment No.
                Further Agreement, dated as        1 on December 3, 1986
                of August 1, 1986, between         Form 8
                the Company and State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Owner Trustee

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

                                       68
<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 as of       28.20 to Form S-3                 1-4473            8-10-87
                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 Funding          8-K Report
                Corp., Inc. as Funding
                Corporation, State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Owner Trustee, Chemical
                Bank, as Indenture Trustee,
                the Company, and the Owner
                Participant named therein

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

                                       69
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  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 Lease,      Report
                dated as of December 15,
                1986, between State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Owner Trustee, and Chemical
                Bank, as Indenture Trustee

  99.17         Supplemental Indenture No. 2       4.5 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 December 15,
                1986, between State Street
                Bank and Trust Company, as
                successor to The First
                National Bank of Boston, as
                Owner Trustee, and Chemical
                Bank, as Indenture Trustee

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

                                       70
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  99.19         Amendment No. 1, dated as of       28.7 to 1992 Form 10-K            1-4473            3-30-93
                March 17, 1993, to                 Report
                Assignment, Assumption and
                Further Agreement, dated as
                of December 15, 1986,
                between the Company and
                State Street Bank and Trust
                Company, as successor to The
                First National Bank of
                Boston, as Owner Trustee

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

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

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

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

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

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

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

                                       71
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.     Description                        Originally Filed as Exhibit:      File No.(b)   Date Effective
-----------     -----------                        ----------------------------      -----------   --------------
<S>             <C>                                <C>                               <C>           <C>
  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, including
                the Retail Electric Competition
                Rules
</TABLE>

----------
(a)  Management  contract or compensatory  plan or arrangement to be filed as an
     exhibit pursuant to Item 14(c) of Form 10-K.

(b)  Reports  filed  under  File No.  1-4473  were  filed in the  office  of the
     Securities and Exchange Commission located in Washington, D.C.

(c)  An additional document, substantially identical in all material respects to
     this  Exhibit,  has been entered  into,  relating to an  additional  Equity
     Participant. Although such additional document may differ in other respects
     (such as dollar amounts,  percentages,  tax indemnity matters, and dates of
     execution),  there are no material  details in which such document  differs
     from this Exhibit.

(d)  Additional agreements,  substantially identical in all material respects to
     this  Exhibit  have been  entered  into with  additional  officers  and key
     employees of the Company.  Although such additional documents may differ in
     other respects  (such as dollar amounts and dates of execution),  there are
     no material details in which such agreements differ from this Exhibit.

REPORTS ON FORM 8-K

     During the quarter  ended  December 31, 1999 and the period ended March 29,
2000, the Company filed the following Reports on Form 8-K:

     Report dated  November 2, 1999  comprised  of Exhibits to our  Registration
Statement  (Registration No. 333-58445) relating to our offering of $250 million
of Notes.

                                       72
<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 29, 2000                               William J. Post
                                      ------------------------------------------
                                      (William J. Post, 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 29, 2000
----------------------------     Principal Accounting Officer
     (William J. Post,                   and Director
  Chief Executive Officer)


     Michael V. Palmeri          Principal Financial Officer      March 29, 2000
----------------------------
    (Michael V. Palmeri,
  Vice President, Finance)


       Jack E. Davis                President and Director        March 29, 2000
----------------------------
      (Jack E. Davis)


    Michael L. Gallagher                   Director               March 29, 2000
----------------------------
   (Michael L. Gallagher)


      Martha O. Hesse                      Director               March 29, 2000
----------------------------
     (Martha O. Hesse)


    Marianne M. Jennings                   Director               March 29, 2000
----------------------------
   (Marianne M. Jennings)


      Robert E. Keever                     Director               March 29, 2000
----------------------------
     (Robert E. Keever)


     Robert G. Matlock                     Director               March 29, 2000
----------------------------
    (Robert G. Matlock)

      Kathryn L. Munro                     Director               March 29, 2000
----------------------------
     (Kathryn L. Munro)

                                       73
<PAGE>
     Bruce J. Nordstrom                    Director               March 29, 2000
----------------------------
    (Bruce J. Nordstrom)

      Donald M. Riley                      Director               March 29, 2000
----------------------------
     (Donald M. Riley)

   Quentin P. Smith, Jr.                   Director               March 29, 2000
----------------------------
  (Quentin P. Smith, Jr.)

       Richard Snell                       Director               March 29, 2000
----------------------------
      (Richard Snell)

     William L. Stewart             President and Director        March 29, 2000
----------------------------
    (William L. Stewart)

      Dianne C. Walker                     Director               March 29, 2000
----------------------------
     (Dianne C. Walker)

    Ben F. Williams, Jr.                   Director               March 29, 2000
----------------------------
   (Ben F. Williams, Jr.)

                                       74
<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, 1999

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

                         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

27.1      --     Financial Data Schedule

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