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, 1998
                                       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                                 86-0011170
     (State or other jurisdiction           (I.R.S. Employer Identification No.)
   of incorporation or organization)
400 North Fifth Street, P.O. Box 53999
      Phoenix, Arizona 85072-3999
    (Address of principal executive                   (602) 250-1000
               offices,                       (Registrant's telephone number,
          including zip code)                       including area code)

--------------------------------------------------------------------------------
Securities registered pursuant to
    Section 12(b) of the Act:

                                                        Name of each exchange on
       Title of each class                                   which registered
--------------------------------------------------------------------------------
10% Junior Subordinated Deferrable Interest
     Debentures, Series A, Due 2025...............      New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None.


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

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

     As of March 30, 1999, 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.
<PAGE>
                                TABLE OF CONTENTS
                                                                            Page
                                                                            ----

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

PART I
     Item 1.  Business....................................................    3
     Item 2.  Properties..................................................   12
     Item 3.  Legal Proceedings...........................................   15
     Item 4.  Submission of Matters to a Vote of Security Holders.........   15
     Supplemental Item.
              Executive Officers of the Registrant........................   16

PART II
     Item 5.  Market for Registrant's Common Stock and Related
              Security Holder Matters.....................................   18
     Item 6.  Selected Financial Data.....................................   19
     Item 7.  Financial Review............................................   20
     Item 7A  Quantitative and Qualitative Disclosures about
              Market Risk.................................................   27
     Item 8.  Financial Statements and Supplementary Data.................   28
     Item 9.  Changes In and Disagreements with Accountants on
              Accounting and Financial Disclosure.........................   58

PART III
     Item 10. Directors and Executive Officers of the Registrant..........   58
     Item 11. Executive Compensation......................................   58
     Item 12. Security Ownership of Certain Beneficial Owners and
              Management..................................................   58
     Item 13. Certain Relationships and Related Transactions..............   58

PART IV
     Item 14. Exhibits, Financial Statements, Financial Statement
              Schedules, and Reports on Form 8-K..........................   59

SIGNATURES................................................................   80

                                       i
<PAGE>
                                    GLOSSARY

ACC -- Arizona Corporation Commission
ACC STAFF -- Staff of the Arizona Corporation Commission
AFUDC -- Allowance for Funds Used During Construction
AMENDMENTS -- Clean Air Act Amendments of 1990
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
DOE -- United States Department of Energy
EITF -- Emerging Issues Task Force
EITF 97-4 -- Emerging  Issues Task Force Issue No.  97-4,  "Deregulation  of the
Pricing of Electricity -- Issues Related to the  Applications of FASB Statements
No. 71, Accounting for the Effects of Certain Types of Regulation,  and No. 101,
Regulated  Enterprises -- Accounting for the  Discontinuation  of Application of
FASB Statement No. 71"
EITF 98-10 --  Emerging  Issues  Task Force  Issue No.  98-10,  "Accounting  for
Contracts Involved in Energy Trading and Risk Management Activities"
ENERGY ACT -- National Energy Policy Act of 1992
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
MORTGAGE  --  Mortgage  and  Deed  of  Trust,  dated  as of  July  1,  1946,  as
supplemented and amended
MW -- Megawatt, one million watts
MWH -- Megawatt hours, one million watts per hour
1935 ACT -- Public Utility Holding Company Act of 1935
NGS -- Navajo Generating Station
NRC -- Nuclear Regulatory Commission
PACIFICORP -- An Oregon-based utility company
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
SFAS  NO.  34  --   Statement  of  Financial   Accounting   Standards   No.  34,
"Capitalization of Interest Cost"

                                       1
<PAGE>
SFAS NO. 71 -- Statement of Financial  Accounting  Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"

SFAS NO. 123 -- Statement of Financial Accounting Standards No. 123, "Accounting
for Stock-Based Compensation"

SFAS NO. 130 -- Statement of Financial  Accounting Standards No. 130, "Reporting
Comprehensive Income"

SFAS NO. 133 -- Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities"

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

USEC -- United States Enrichment Corporation

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

                                       2
<PAGE>
                                     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 799,000  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
1998, no single  purchaser or user of energy accounted for more than 2% of total
electric  revenues.  At December  31,  1998,  we employed  6,075  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

     GENERAL. Under current law, we are not in direct competition with any other
regulated electric utility for electric service in our retail service territory.
Nevertheless,  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.

     ARIZONA ELECTRIC INDUSTRY  RESTRUCTURING.  See Note 3 of Notes to Financial
Statements in Item 8 for a discussion of the electric industry  restructuring in
Arizona,   including  ACC  rules  for  the   introduction   of  retail  electric
competition;  stranded cost recovery; and Arizona legislative  initiatives.  See
also "Financial Review - Competition and Industry Restructuring" in Item 7.

     WHOLESALE

     GENERAL. 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

                                       3
<PAGE>
vigorous.  Our rates for  wholesale  power sales and  transmission  services are
subject  to  regulation  by the  FERC.  During  1998,  approximately  16% of our
electric operating revenues resulted from such sales and charges.

     The  National  Energy  Policy Act of 1992 (the  "Energy  Act") 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.   These  items,  combined  with  miscellaneous
regulatory  assets and liabilities,  amounted to  approximately  $900 million at
December 31, 1998.  Under a 1996 regulatory  agreement,  the ACC accelerated the
amortization  of  substantially  all of our  regulatory  assets to an eight-year
period  that will end June 30,  2004.  Our  existing  regulatory  orders and the
current  regulatory  environment  support our  accounting  practices  related to
regulatory  assets.  If rate  recovery  of these  assets is no longer  probable,
whether due to competition or regulatory  action,  we would be required to write
off the remaining balance as an extraordinary charge to expense. This could have
a material impact on our financial  statements.  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) expanding our generation
asset base to support growth in the  competitive  power  marketing  arena;  (vi)
strengthening  our capital structure and financial  condition;  (vii) leveraging
core competencies  into related areas,  such as energy  management  products and
services;  and  (viii)  establishing  a trading  floor and  implementing  a risk
management  program to provide for more  stability  of prices and the ability to
retain or grow  incremental  margin  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.

                                       4
<PAGE>
GENERATING FUEL AND PURCHASED POWER

     1998 ENERGY MIX

     Our  sources of energy  during  1998 were:  coal - 36.2%;  nuclear - 27.5%;
purchased power - 32.3%; and other - 4.0%.

     COAL SUPPLY

     We believe that Cholla has sufficient reserves of low sulfur coal committed
to the plant through 2005. In 1998, the current  supplier agreed to allow Cholla
to test burn coal from other  sources,  which led to coal  purchases on the spot
market.  The current  supplier is expected to continue to provide  substantially
all of Cholla's low sulfur coal  requirements.  We believe there are  sufficient
reserves of low sulfur coal available to allow the continued operation of Cholla
for its useful life.  We also believe that Four Corners and NGS have  sufficient
reserves  of low  sulfur  coal  available  for use by those  plants to  continue
operating them for their useful lives.

     The current  sulfur  content of coal being used at Four  Corners,  NGS, and
Cholla is approximately 0.77%, 0.54%, and 0.44%, respectively.  In 1998, average
prices  paid for  coal  supplied  from the  reserves  dedicated  under  existing
contracts  were  slightly  lower,  but  still  comparable  to  1997.  Escalation
components of existing  long-term coal contracts  impact future coal prices.  In
addition,  major  price  adjustments  can occur from time to time as a result of
contract renegotiation.

     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 Navajo Nation" in Item 2.
We purchase all of the coal which fuels Four Corners from a coal supplier with a
long-term  lease of coal reserves  owned by the Navajo Nation and for NGS from a
coal supplier with a long-term  lease with the Navajo Nation and the Hopi Tribe.
Coal is supplied to Cholla from a coal  supplier who mines all of the coal under
a  long-term  lease of coal  reserves  owned by the Navajo  Nation,  the federal
government,  and  private  landholders.  See  Note  12  of  Notes  to  Financial
Statements  in Item 8 for  information  regarding our  obligation  for coal mine
reclamation.

     NATURAL GAS SUPPLY

     We are a party to  contracts  with a number of natural  gas  operators  and
marketers  which 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 25 companies pursuant to 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,
          +    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 2001. Existing contracts and options could be
utilized to meet  approximately 93% of requirements in 2002, 62% of requirements
in 2003, 51% of requirements

                                       5
<PAGE>
in 2004, and 44% of  requirements  from 2005 through 2007. 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 85% of conversion  services
required through 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 2003 for each Palo Verde  unit,  and  through  contract  options,
approximately fifteen additional years are available.

     SPENT NUCLEAR FUEL AND WASTE DISPOSAL. Pursuant to the Nuclear Waste Policy
Act of 1982,  as amended in 1987 (the "Waste  Act"),  DOE is obligated to accept
and dispose of all spent nuclear fuel and other  high-level  radioactive  wastes
generated by all 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.  We have done so on our  behalf  and on behalf of the other
Palo Verde participants.  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 will 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. On July 24,
1998,  we filed a  Petition  for  Review  regarding  DOE's  obligation  to begin
accepting  spent nuclear fuel.  ARIZONA PUBLIC SERVICE  COMPANY V. DEPARTMENT OF
ENERGY AND UNITED STATES OF AMERICA,  No. 98-1346 (D.C.  Cir.).  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.  We also
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. One way or another, 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.

     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 292 MW January  through May 1998, and starting June
1998  increased  to 316 MW. In 1998,  we received  approximately  943,354 MWh of
energy under the  contract and paid about $43 million for capacity  availability
and  energy  received.  See  Note  3 of  Notes  to  Financial  Statements  for a
discussion of amendments to agreements with Salt River Project.

     In  September  1990,  we entered into certain  agreements  with  PacifiCorp
relating  principally  to sales and  purchases  of electric  power and  electric
utility  assets.  In July 1991 we sold  Cholla 4 to  PacifiCorp.  As part of the
transaction, PacifiCorp agreed to make a firm system sale to us for thirty years
during our summer peak season.  The amount of the sale for the first seven years
was 175 MW and it increases after that at our option,  up to a maximum amount of
380 MW. We converted  the firm system  sales to  one-for-one  seasonal  capacity
exchanges with PacifiCorp on October 31, 1997. On January 1, 1999 our agreements
with PacifiCorp  provide for 275 MW capacity exchange and beginning in May 1999,
an  additional  205 MW  capacity  exchange  begins.  In  1998,  we had 275 MW of
generating capacity available from PacifiCorp. We received approximately 281,217
MWh of energy under the exchange.

     During 1996, we entered into an agreement with Citizens  Utilities  Company
to build, own, operate,  and maintain a combustion turbine in northwest Arizona.
CUC terminated the combustion turbine project in February 1999. We have notified
CUC that we will retain the rights to the combustion turbine project.

CONSTRUCTION PROGRAM

     During the years 1996 through 1998, we incurred  approximately $899 million
in capitalized expenditures. Utility capitalized expenditures for the years 1999
through  2001 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 1999 through
2001 have been estimated as follows:

                              (MILLIONS OF DOLLARS)
BY YEAR                                          BY MAJOR FACILITIES
------------------------------         -----------------------------------------
1999                       $328        Production                           $236
2000                        317        Transmission and Distribution         564
2001                        300        General                               113
                           ----        Other Projects                         32
  Total                    $945                                             ----
                           ====        Total                                $945
                                                                            ====

     The amounts for 1999 through 2001 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. We are
considering  expanding  certain of our  operations  over the next several years,
which may result in  additional  expenditures.  We currently  believe that there
will be opportunities to expand our investment in generating  assets in the next
five years. It is expected that these generating  assets would be organized in a
newly-created, non-regulated affiliate under Pinnacle West.

                                       7
<PAGE>
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
1998, the replacement fund requirement  amounted to approximately  $138 million.
Certain of the bonds we have issued under the Mortgage  that are callable  prior
to maturity are redeemable at their par value plus accrued interest with cash we
deposit in the  replacement  fund.  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 1977  amendments 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.  Approximately
93% of these capital costs have been incurred through 1998.

     The Clean Air Act  Amendments  of 1990 (the  "Amendments")  address,  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 Amendments establish 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. On March 5, 1993,
the EPA  promulgated  rules  listing  allowance  allocations  applicable  to our
plants. Based on those allocations, we will have sufficient allowances to permit
continued   operation  of  our  plants  at  current  levels  without  installing
additional equipment.

     In  addition,  the  Amendments  require  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 may  require  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.  We cannot currently predict how the EPA will respond. However,
based on our initial  evaluation,  we  currently  estimate  our capital  cost of
complying with the rules may be approximately $4 million.

     With respect to protection of visibility in certain  specified  areas,  the
Amendments require the EPA to conduct a study concerning  visibility  impairment
in those areas and to identify sources contributing to such impairment.

                                       8
<PAGE>
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 Amendments  also require 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. The Commission  recommended that,  beginning in 2000
and  every 5 years  thereafter,  if actual  sulfur  dioxide  emissions  from all
stationary  sources in an eight-state  region  (including  Arizona,  New Mexico,
Utah,  Nevada,  and  California)  exceed  the  projected  emissions,  which  are
projected to decline under the current  regulatory  scheme,  the projected total
emissions will be changed to a "regional emissions cap" and an emissions trading
program  would be  implemented  to limit total sulfur  dioxide  emissions in the
region. The EPA will consider these  recommendations  before  promulgating final
requirements  on a regional  haze  regulatory  program which the EPA proposed in
July 1997 and which is expected to be finalized by mid-1999.

     Under EPA's  proposed  regional haze  program,  states would be required to
submit plans to meet  "presumptive  reasonable  progress  targets" for achieving
perceptible  improvements  in  visibility  conditions  in Federal  Class I areas
(e.g.,  national parks) every 10-15 years. The proposal also calls for states to
conduct three year "best  available  retrofit  technology"  ("BART")  reviews on
point  sources  which  became  operational  between  1962 and 1977 and which may
normally be anticipated to contribute to regional haze visibility impairment.

     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.  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 Amendments  require 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 in
the next several years  concerning  the  necessity of  regulating  hazardous air
pollutant  emissions  from such units  under the  Amendments.  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  Amendments  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.

     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
predecessor,  that  were  at one  time  sites  of,  or  sites  associated  with,
manufactured gas plants. The purpose of this investigation is to determine if:

                                       9
<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, pursuant
to the Amendments. We are currently evaluating the impact of these regulations.

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.

                                       10
<PAGE>
     Both  groundwater  and surface water in areas  important to our  operations
have been the subject of inquiries,  claims,  and legal  proceedings  which will
require a number of years to  resolve.  We are one of a number of  parties  in a
proceeding  before a state court in New Mexico to adjudicate  rights to a stream
system from which water for Four  Corners is derived.  (STATE OF NEW MEXICO,  IN
THE RELATION OF S.E. REYNOLDS, STATE ENGINEER VS. UNITED STATES OF AMERICA, CITY
OF FARMINGTON,  UTAH  INTERNATIONAL,  INC., ET AL., SAN JUAN COUNTY, NEW MEXICO,
District Court No. 75-184). An agreement reached with the Navajo Nation in 1985,
however,  provides  that if Four  Corners  loses a portion  of its rights in the
adjudication,  the Navajo  Nation will  provide,  for a  then-agreed  upon cost,
sufficient water from its allocation to offset the loss.

     A summons  served on us in early 1986  required all water  claimants in the
Lower Gila River Watershed in Arizona to assert any claims to water on or before
January 20, 1987, in an action pending in Maricopa County Superior Court. (IN RE
THE GENERAL ADJUDICATION OF ALL RIGHTS TO USE WATER IN THE GILA RIVER SYSTEM AND
SOURCE,  Supreme Court Nos. WC-79-0001 through WC 79-0004  (Consolidated) [WC-1,
WC-2, WC-3 and WC-4 (Consolidated)],  Maricopa County Nos. W-1, W-2, W-3 and W-4
(Consolidated)). Palo Verde is located within the geographic area subject to the
summons.  Our rights and the rights of the Palo Verde participants to the use of
groundwater  and effluent at Palo Verde 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. Issues important to
the claims are 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 or results of operations.

                                       11
<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 peak  one-hour  demand on our electric  system was recorded on July 16,
1998 at  5,072,000  kW,  compared to the 1997 peak of  4,608,600  kW recorded on
August 22. Taking into account  additional  capacity then  available to us under
purchase power contracts as well as our own generating capacity,  our capability
of meeting system demand on July 16, 1998,  computed in accordance with accepted
industry practices, amounted to 5,139,600 kW, for an installed reserve margin of
3.1%. The power actually available to us from our resources fluctuates from time
to time due in part to planned  outages and  technical  problems.  The available
capacity from sources actually operable at the time of the 1998 peak amounted to
4,862,600 kW, for a margin of (3.9%). Firm purchases from neighboring  utilities
totaling 1,467,000 kW were in place at the time of the peak ensuring the ability
to meet the load requirement, with an actual reserve margin of 7.4%.

PLANT SITES LEASED FROM NAVAJO NATION

     NGS and Four  Corners  are  located on land held under  easements  from the
federal  government  and also under  leases  from the Navajo  Nation.  We do not
believe that the risk with respect to enforcement of these  easements and leases
is material.  The lease for Four Corners waives until 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
to Four Corners,  the Navajo Nation,  and us which settled certain issues in the
Four Corners lease  regarding  the  obligation of the fuel supplier to pay taxes
prior to the expiration of tax waivers in 2001.  Pursuant to the  agreement,  in
1997 we recognized  approximately  $14 million of pretax  earnings  related to a
partial refund of

                                       12
<PAGE>
possessory interest taxes paid by the fuel supplier.  The parties also agreed to
renegotiate their business  relationship  before 2001 in an effort to permit the
electricity  generated  at Four  Corners to be priced  competitively.  We cannot
currently predict the outcome of this matter.  Certain of our transmission lines
and  almost  all of its  contracted  coal  sources  are also  located  on Indian
reservations.  See "Generating Fuel and Purchased Power--Coal Supply" in Item 1.

PALO VERDE NUCLEAR GENERATING STATION

     PALO VERDE LEASES

     See Note 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.
Proposed ACC rules regarding the introduction of retail electric  competition in
Arizona  (see Note 3)  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 13 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.

                                       13
<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.

                                       14
<PAGE>
                            ITEM 3. LEGAL PROCEEDINGS

     See  "Environmental  Matters"  and  "Water  Supply"  in Item 1 in regard to
pending or threatened litigation and other disputes. See "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.  On February  28, 1997 and October 16,  1998,  we filed
lawsuits to protect our legal rights  regarding the rules and the amended rules,
respectively,  and in each  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 97-03753  (consolidated under CV 97-03748.) ARIZONA
PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV 98-18896. 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.

                                       15
<PAGE>

                      SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS
                                OF THE REGISTRANT

The Company's executive officers are as follows:

                           AGE AT
NAME                    MARCH 1, 1999          POSITION(S) AT MARCH 1, 1999
----                    -------------          ----------------------------
Richard Snell                 68    Chairman of the Board of Directors(1)
William J. Post               48    Chief Executive Officer(1)
Jack E. Davis                 52    President, Energy Delivery and Sales(1)
William L. Stewart            55    President, Generation(1)
George A. Schreiber, Jr.      50    Executive Vice President and Chief Financial
                                      Officer(1)
Armando B. Flores             55    Executive Vice President, Corporate Business
                                      Services
James M. Levine               49    Senior Vice President, Nuclear Generation
Jan H. Bennett                51    Vice President, Distribution
John G. Bohon                 53    Vice President, Corporate Services and Human
                                      Resources
John R. Denman                56    Vice President, Fossil Generation
Edward Z. Fox                 45    Vice President, Environmental/Health/Safety
                                      and New Technology Ventures
William E. Ide                52    Vice President, Nuclear Engineering
Nancy C. Loftin               45    Vice President, Chief Legal Counsel and
                                      Secretary
Gregg R. Overbeck             52    Vice President, Nuclear Production
Chris N. Froggatt             41    Controller
Michael V. Palmeri            40    Treasurer

----------
(1) Member of the Board of Directors.

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

     Mr. Snell was elected to his present  position as of February  1990. He was
also elected  Chairman of the Board,  President and Chief  Executive  Officer of
Pinnacle  West at that time.  He retired as  President  in February  1997 and as
Chief  Executive  Officer in  February  1999.  Mr.  Snell is also a director  of
Pinnacle West, Aztar Corporation, and Central Newspapers, Inc.

     Mr.  Post was elected  President  and Chief  Executive  Officer in February
1997. In October 1998, he resigned as President and  maintained  the position of
Chief  Executive  Officer.  Prior to that time he was Senior Vice  President and
Chief  Operating  Officer  (September  1994 -  February  1997) and  Senior  Vice
President,  Planning, Information and Financial  Services (June 1993 - September
1994).  Mr. Post was President of Pinnacle West  (February 1997 - February 1999)
and in February  1999, he became Chief  Executive  Officer of Pinnacle West. Mr.
Post is also a director of Pinnacle West.

     Mr.  Davis was elected to his present  position in October  1998.  Prior to
that time he was Executive Vice President, Commercial Operations (September 1996
-  October  1998)  and  Vice  President,   Generation  and  Transmission   (June
1993-September 1996).

                                       16
<PAGE>
     Mr. Stewart was elected to his present  position in October 1998.  Prior to
that time he was Executive Vice President,  Generation (September 1996 - October
1998), Executive Vice President,  Nuclear (May 1994 - September 1996) and Senior
Vice President--Nuclear for Virginia Power (since 1989).

     Mr.  Schreiber was elected to his present  position in February 1997. Prior
to that time he was  Managing  Director at  PaineWebber,  Inc.  (since  February
1990).  Mr.  Schreiber was Executive  Vice  President of Pinnacle West (February
1997 - February 1999),  and he is currently  President (since February 1999) and
Chief Financial Officer (since February 1997) of Pinnacle West. Mr. Schreiber is
also a director of Pinnacle West.

     Mr. Flores was elected to his present  position in October  1998.  Prior to
that time, he was Senior Vice President,  Corporate Business Services (September
1996 - October 1998) and Vice President, Human Resources (1991-1996). Mr. Flores
is a director of Harris Trust Bank.

     Mr. Levine was elected to his present  position in September 1996. Prior to
that time he was Vice President, Nuclear Production (since September 1989).

     Mr. Bennett was elected to his present position in May 1991.

     Mr.  Bohon was elected to his present  position in October  1998.  Prior to
that time he was Vice  President,  Procurement  (April 1997 - October  1998) and
Director, Corporate Services (December 1989-April 1997).

     Mr. Denman was elected to his present position in April 1997. Prior to that
time he was Director of Fossil Generation (since 1990).

     Mr. Fox was elected to his present  position in October 1995. Prior to that
time he was Director,  Arizona Department of Environmental Quality and Chairman,
Wastewater Management Authority of Arizona (July 1991-September 1995).

     Mr. Ide was elected to his present  position in  September  1996.  Prior to
that time he was Director, Palo Verde Operations (1994-1996) and Palo Verde Unit
1 Plant Manager (1988-1994).

     Ms. Loftin was elected to the  positions of Vice  President and Chief Legal
Counsel in September 1996 and has been Secretary since April 1987. Prior to that
time, in addition to Secretary, she was Corporate Counsel (since February 1989).

     Mr.  Overbeck  was elected to his current  position in July 1995.  Prior to
that time he was Assistant to Vice President of the Company  (January  1994-July
1995).

     Mr.  Froggatt  was elected to his present  position in July 1997.  Prior to
that time he was Director,  Accounting  Services  (since  December  1992) of the
Company.

     Mr. Palmeri was elected to his present position in July 1997. Prior to that
time he was Assistant Treasurer (February 1994-July 1997) and Manager of Finance
(June 1990-February 1994) of Pinnacle West. He also became Treasurer of Pinnacle
West in July 1997.

                                       17
<PAGE>
                                     PART II

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

     The  Company's  common stock is  wholly-owned  by Pinnacle  West and is not
listed for trading on any stock exchange.  As a result,  there is no established
public trading market for the Company's common stock.

     The chart below sets forth the dividends  declared on the Company's  common
stock for each of the four quarters for 1998 and 1997.


                             COMMON STOCK DIVIDENDS
                             (THOUSANDS OF DOLLARS)
--------------------------------------------------------------------------------
       QUARTER                           1998                       1997
--------------------------------------------------------------------------------
     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 Notes 4 and 5 of
Notes to Financial  Statements in Item 8 for  restrictions on retained  earnings
available for the payment of common stock dividends.

                                       18
<PAGE>
                         ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
                                               1998         1997         1996         1995         1994
                                            ----------   ----------   ----------   ----------   ----------
                                                                (THOUSANDS OF DOLLARS)
<S>                                         <C>          <C>          <C>          <C>          <C>
Electric Operating Revenues .............   $2,006,398   $1,878,553   $1,718,272   $1,614,952   $1,626,168
Fuel and Purchased Power ................      537,501      436,627      325,523      269,798      300,689
Operating Expenses ......................    1,098,086    1,070,101    1,027,541      963,400      957,046
                                            ----------   ----------   ----------   ----------   ----------
   Operating Income .....................      370,811      371,825      365,208      381,754      368,433
Other Income ............................       20,448       21,586       35,217       25,548       44,510
Interest Deductions -- Net ..............      136,012      141,918      156,954      167,732      169,457
                                            ----------   ----------   ----------   ----------   ----------
   Net Income ...........................      255,247      251,493      243,471      239,570      243,486
   Preferred Dividends ..................        9,703       12,803       17,092       19,134       25,274
                                            ----------   ----------   ----------   ----------   ----------
   Earnings for Common Stock ............   $  245,544   $  238,690   $  226,379   $  220,436   $  218,212
                                            ==========   ==========   ==========   ==========   ==========

Total Assets ............................   $6,393,299   $6,331,142   $6,423,222   $6,418,262   $6,348,261
                                            ==========   ==========   ==========   ==========   ==========

Capital Structure:
   Common Stock Equity ..................   $1,975,755   $1,849,324   $1,729,390   $1,621,555   $1,571,120
   Non-Redeemable Preferred Stock .......       85,840      142,051      165,673      193,561      193,561
   Redeemable Preferred Stock ...........        9,401       29,110       53,000       75,000       75,000
   Long-Term Debt Less Current
     Maturities..........................    1,876,540    1,953,162    2,029,482    2,132,021    2,181,832
                                            ----------   ----------   ----------   ----------   ----------
     Total Capitalization ...............    3,947,536    3,973,647    3,977,545    4,022,137    4,021,513
   Current Maturities of Long-Term Debt .      164,378      104,068      153,780        3,512        3,428
   Commercial Paper .....................      178,830      130,750       16,900      177,800      131,500
                                            ----------   ----------   ----------   ----------   ----------
     Total ..............................   $4,290,744   $4,208,465   $4,148,225   $4,203,449   $4,156,441
                                            ==========   ==========   ==========   ==========   ==========
</TABLE>
----------
     See "Financial Review" in Item 7 for a discussion of certain information in
the foregoing table.

                                       19
<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 1997 to 1998 and from 1996 to
               1997
          +    the factors  impacting our business,  including  competition  and
               electric industry restructuring
          +    the effects of regulatory agreements on our results
          +    our capital needs and resources and
          +    Year 2000 technology issues.

Throughout this Financial  Review,  we refer to specific "Notes" in the Notes to
Financial  Statements  that begin on page 35. These Notes add further details to
the discussion.

RESULTS OF OPERATIONS

1998  COMPARED  WITH  1997 Our 1998  earnings  increased  $6.9  million - a 2.9%
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,  two  fuel-related  settlements  recorded in 1997, and two retail price
reductions. See Note 3 for additional information about the price reductions.

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  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).

Power marketing and trading activities are predominantly  short-term opportunity
wholesale sales. The increase in power marketing  revenues  resulted from higher
prices, increased activity in Western bulk power markets, and increased sales to
large  customers  in  California.  The increase in power  marketing  and trading
revenues was accompanied by related increases in purchased power expenses.

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 $15 million  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.

                                       20
<PAGE>
1997  COMPARED  WITH 1996 Our 1997  earnings  increased  $12.3  million - a 5.4%
increase - over 1996 earnings primarily because of:

          +    an increase in customers
          +    a $32 million  pretax  charge in 1996 for a  voluntary  severance
               program
          +    two fuel-related settlements in 1997 and
          +    lower financing costs.

These  positive  factors  more than  offset the  effects of our 1996  regulatory
agreement  with the Arizona  Corporation  Commission  (ACC),  which  during 1997
resulted in about $60 million of additional  regulatory asset amortization and a
$35 million revenue decrease caused by two retail price  reductions.  See Note 3
and "Results of  Operations  ___  Regulatory  Agreements"  below for  additional
information.  In addition,  we recognized  $12 million of income tax benefits in
1996 that were not repeated in 1997.

In 1997,  electric  operating  revenues increased $160 million primarily because
of:

          +    increased power marketing revenues ($128 million)
          +    an increase in the number of customers ($58 million) and
          +    weather effects ($7 million).

As  mentioned  above,  these  positive  factors were  partially  offset by a $35
million  revenue  decrease  caused by retail price  reductions.  The increase in
power marketing  revenues resulted from increased activity in Western bulk power
markets. This did not significantly affect our earnings because the increase was
substantially offset by higher purchased power expenses.

Two  fuel-related  settlements  in 1997 increased  pretax  earnings by about $21
million.  The income  statement  shows these  settlements  as reductions in fuel
expense and as other  income.  About $16 million of the  settlements  related to
years prior to 1997 and $5 million  related to 1997.  We expect the total annual
savings from the settlements for at least the next several years to be about $10
million before income taxes. We do not have a fuel adjustment  clause as part of
our retail rate  structure.  As a result,  we show changes in fuel and purchased
power expenses in current earnings.

We lowered our operations and maintenance expenses in 1997 by putting in place a
voluntary  severance  program in late 1996,  with related  savings  reflected in
1997. These savings were partially  offset by increased  expenses for marketing,
information technology, and power plant maintenance.

We  decreased  our  financing  costs by $12 million  during 1997 by lowering the
amounts of outstanding debt and preferred stock.

REGULATORY  AGREEMENTS  Regulatory agreements with the ACC affect the results of
our  operations.  The following  discussion  focuses on two  agreements:  a 1996
agreement to accelerate the  amortization  of our  regulatory  assets and a 1994
settlement to accelerate  amortization  of our deferred  investment  tax credits
(ITCs).

Under the 1996 agreement with the ACC, we are  recovering  substantially  all of
our present regulatory assets through accelerated amortization.  The recovery of
these  assets is taking place over an  eight-year  period that will end June 30,
2004.  For more details,  see Note 3. This  accelerated  amortization  increased
annual amortization expense by about $120 million ($72 million after taxes).

Also, as part of the 1996 regulatory agreement,  we reduced our retail prices by
3.4%  effective  July 1,  1996.  This  reduces  revenue by about  $48.5  million
annually ($29 million after taxes).  We also agreed to share future cost savings
with our  customers,  which  resulted in the following  additional  retail price
reductions:

                                       21
<PAGE>
          +    $17.6 million  annually  ($10.5 million after income  taxes),  or
               1.2%, effective July 1, 1997, and

          +    $17 million  annually ($10 million after income taxes),  or 1.1%,
               effective July 1, 1998.

We  expect  to  file  with  the  ACC  for  another   retail  price  decrease  of
approximately $10.8 million annually ($6.5 million after income taxes) to become
effective  July 1, 1999. The amount and timing of the price decrease are subject
to ACC approval.  This will be the last price decrease under the 1996 regulatory
agreement.

We discuss  above,  in "Results  of  Operations,"  the  factors  that offset the
earnings impact of the accelerated  regulatory asset  amortization and the price
decreases.

As  part  of  the  1994  rate   settlement,   we  accelerated   amortization  of
substantially  all deferred  ITCs over a five-year  period that ends on December
31, 1999.  The  amortization  of ITCs is shown on our income  statement as Other
Income ___ Income  Taxes.  It decreases  annual  income tax expense by about $28
million.  Beginning in 2000, no further benefits will be reflected in income tax
expense. See Note 10.

CAPITAL NEEDS AND RESOURCES

Our capital  requirements consist primarily of capital expenditures and optional
and mandatory  redemptions of long-term debt and preferred stock. We pay for our
capital requirements with:

          +    cash from our operations
          +    annual cash  payments from Pinnacle West of $50 million from 1996
               through 1999 (see Note 3) and
          +    to the extent necessary, external financing.

During  the  period  from  1996  through  1998,  we paid for all of our  capital
expenditures  with cash from our operations.  We expect to do so in 1999 through
2001 as well.

Our  capital  expenditures  in 1998 were $327  million.  Our  projected  capital
expenditures  for the next three  years are:  1999,  $328  million;  2000,  $317
million;  and 2001,  $300 million.  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.

In addition,  we are  considering  expanding  certain of our operations over the
next several years,  which may result in additional  expenditures.  We currently
believe that there will be  opportunities to expand our investment in generating
assets in the next five years. It is expected that these generating assets would
be organized in a newly created non-regulated affiliate under Pinnacle West.

During 1998, we redeemed about $145 million of long-term debt and $76 million of
preferred  stock,  including  premiums,  with cash from operations and long- and
short-term debt. Our long-term debt and preferred stock redemption  requirements
and payment  obligations  on a  capitalized  lease for the next three years are:
1999, $260 million;  2000, $115 million; and 2001, $2 million. On March 1, 1999,
we redeemed all $95 million of our outstanding  preferred stock. Based on market
conditions  and optional call  provisions,  we may make optional  redemptions of
long-term debt from time to time.

                                       22
<PAGE>
As of December 31, 1998, we had credit  commitments  from various banks totaling
about $400  million,  which were  available  either to support  the  issuance of
commercial  paper or to be used as bank  borrowings.  At the end of 1998, we had
about $179  million of  commercial  paper and $125  million  of  long-term  bank
borrowings outstanding.

In 1998,  we issued $100  million of  unsecured  long-term  debt and in February
1999, we issued $125 million of unsecured long-term debt.

Although   provisions  in  our  first  mortgage  bond  indenture,   articles  of
incorporation,  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
earn fair returns on their invested capital in exchange for commitments to serve
all customers within designated service  territories.  In December 1996, the ACC
adopted rules that provide a framework for the  introduction  of retail electric
competition  in Arizona and adopted  amendments  to the rules in August 1998. On
January 11,  1999,  the ACC issued an order which  stayed the amended  rules and
granted  waivers  from  compliance  with  the  rules to all  affected  utilities
(including us) pending  further ACC decisions.  On February 5, 1999, ACC hearing
officers  issued  recommendations  for  changes  to  the  amended  rules.  These
recommended  changes were further amended by an ACC Procedural Order dated March
12,  1999.  See Note 3 for  additional  information  about these rules and other
competitive  developments,  including  an  agreement  with  Salt  River  Project
Agricultural  Improvement  and Power  District (Salt River  Project).  We cannot
currently  predict when or if the amended rules will be further  modified,  when
the  stay  of the  amended  rules  will  be  lifted,  or  when  retail  electric
competition will be introduced in Arizona with respect to affected utilities.

The rules as recommended indicate that the ACC will allow affected utilities the
opportunity to fully recover  unmitigated  stranded costs,  but do not set forth
the mechanisms for  determining and recovering such costs. On June 22, 1998, the
ACC issued an order on stranded cost  determination and recovery and on February
5, 1999, an ACC hearing officer issued recommended  changes to that order. These
recommended  changes were further amended by an ACC Procedural Order dated March
12, 1999. See Note 3 for additional information on proposed modifications to the
stranded cost order.

An Arizona joint legislative  committee  studied electric utility  restructuring
issues  in  1996  and  1997.  In May  1998,  a law  was  enacted  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 believe that further ACC  decisions,  legislation  at the Arizona and federal
levels,  and perhaps  amendments to the Arizona  Constitution will ultimately be
required before  significant  implementation of retail electric  competition can
lawfully occur in Arizona.  Until it has been determined how competition will be
implemented  in Arizona,  including the manner in which  stranded  costs will be
addressed, 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.  Our
existing  regulatory orders and the current regulatory  environment  support our
accounting  practices related to regulatory assets, which amounted to about $900
million at December 31, 1998. Under the 1996 regulatory agreement, the ACC

                                       23
<PAGE>
accelerated the amortization of substantially all of our regulatory assets to an
eight-year  period  that will end June 30,  2004.  If we cease to be  cost-based
regulated,  we would no longer be able to apply the provisions of SFAS No. 71 to
part  or all of our  operations,  which  could  have a  material  impact  on our
financial  statements.  See  Note 1 for  additional  information  on  regulatory
accounting.

YEAR 2000 READINESS DISCLOSURE

OVERVIEW As the year 2000 approaches,  many companies face problems because many
computer  systems and  equipment  will not  properly  recognize  calendar  dates
beginning with the year 2000. We are addressing the Year 2000 issue as described
below. We initiated a comprehensive  company-wide  Year 2000 program during 1997
to review and resolve all Year 2000 issues in mission  critical systems (systems
and equipment that are key to business function, health, and safety) in a timely
manner to ensure the  reliability  of electric  service to our  customers.  This
included a company-wide awareness program of the Year 2000 issue.

The following chart shows Year 2000 readiness of our mission critical systems as
of January 31, 1999:

               INVENTORY     ASSESSMENT     REMEDIATION & TESTING

                  100%          100%                70%*

*  Estimated  to be at 100% by June 30,  1999,  except  one Palo  Verde  unit as
discussed below.

DISCUSSION  We  have  been  actively  implementing  and  replacing  systems  and
technology since 1995 for general  business reasons  unrelated to the Year 2000,
and these actions have resulted in  substantially  all of our major  information
technology  (IT)  systems  becoming  Year 2000 ready.  The major IT systems that
were, and are being, implemented and replaced include the following:

          +    Work Management
          +    Materials Management
          +    Energy Management
          +    Payroll
          +    Financial
          +    Human Resources
          +    Trouble Call Management
          +    Computer and Communications Network Upgrades
          +    Geographic Information Management
          +    Customer Information System and
          +    Palo Verde Site Work Management.

We have made,  and will  continue  to make,  certain  modifications  to computer
hardware and software systems and applications, including IT and non-IT systems,
in an effort to ensure  they are capable of handling  changing  business  needs,
including dates in the year 2000 and thereafter.  In addition,  we are analyzing
other IT systems and non-IT systems, including embedded technology and real-time
process control systems, for potential modifications.

We have inventoried and assessed  essentially all mission critical IT and non-IT
systems and equipment.  We are 70% complete with the  remediation and testing of
these systems.  Remediation  and testing is expected to be completed by June 30,
1999, for all mission critical systems,  except for those items that can only be
completed during maintenance  outages at Palo Verde, which will be completed for
the last unit, which is substantially  identical to the other two units,  during
the last half of 1999.  We have an  internal  audit/quality  review team that is
periodically  reviewing  the  individual  Year 2000 projects and their Year 2000
readiness.

                                       24
<PAGE>
We currently  estimate that we will spend about $5 million relating to Year 2000
issues,  about $3  million  of which has been spent to date.  This  includes  an
estimated  allocation of payroll  costs for our  employees  working on Year 2000
issues, and costs for consultants,  hardware, and software. We do not separately
track other internal  costs.  This does not include costs incurred since 1995 to
implement  and  replace  systems  for  reasons  unrelated  to the Year 2000,  as
discussed above. Our cost to address the Year 2000 issue is charged to operating
expenses as incurred  and has not had,  and is not  expected to have, a material
adverse effect on our financial position,  cash flows, or results of operations.
We expect to fund this cost with  available  cash  balances and cash provided by
operations.

We are communicating with our significant  suppliers,  business partners,  other
utilities,  and  large  customers  to  determine  the  extent to which we may be
affected by these third parties'  plans to remediate  their own Year 2000 issues
in a  timely  manner.  We have  been  interfacing  with  suppliers  of  systems,
services,  and materials in order to assess whether their schedules for analysis
and  remediation  of Year 2000 issues are timely and to assess their  ability to
continue to supply required services and materials.

We are also working with the North American Electric  Reliability Council (NERC)
through the Western Systems  Coordinating  Council (WSCC) to develop operational
plans for stable grid operation  that will be used by other  utilities and us in
the western United States.  These plans are expected to be completed by June 30,
1999.  However,  we cannot currently  predict the effect on us if the systems of
these other companies are not Year 2000 ready.

We  currently  expect  that our most  reasonably  likely  worst  case  Year 2000
scenario would be intermittent loss of power to customers,  similar to an outage
during a severe weather disturbance.  In this situation,  we would restore power
as soon as possible by, among other things,  re-routing  power flows.  We do not
currently  expect that this scenario would have a material adverse effect on our
financial position, cash flows, or results of operations.

We are working to develop our own contingency  plans to handle Year 2000 issues,
including the most reasonably  likely worst case scenario,  discussed above, and
we expect these plans to be completed by June 30, 1999. As discussed  above,  we
have also been working with NERC and WSCC to develop  contingency  plans related
to grid operation.

ACCOUNTING MATTERS

We describe two new  accounting  rules in Note 2. First,  the new rule on energy
trading and risk  management is effective in 1999. We do not expect it to have a
material  impact  on our  financial  results.  Secondly,  the  new  standard  on
derivatives is effective for us in 2000. We are currently evaluating what impact
it will have on our financial statements. Also, see Note 13 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 the nuclear  decommissioning  trust
fund. Our policy is to manage interest rates through the use of a combination of
fixed 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 rates.

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, 1998 and  December  31,  1997.  The weighted
average  interest rates for the various debt presented are actual as of December
31, 1998 and December 31, 1997.

                                       25
<PAGE>
EXPECTED MATURITY/PRINCIPAL REPAYMENT
DECEMBER 31, 1998
(THOUSANDS OF DOLLARS)

<TABLE>
<CAPTION>
                          SHORT-TERM         VARIABLE LONG-TERM       FIXED LONG-TERM
                     -------------------    -------------------    -------------------
                     INTEREST               INTEREST               INTEREST
                      RATES      AMOUNT      RATES      AMOUNT      RATES      AMOUNT
                     -------------------    -------------------    -------------------
<S>                    <C>    <C>            <C>     <C>           <C>     <C>
  1999                 6.21%  $  178,830        --   $       --      7.24%  $  164,378
  2000                   --           --        --           --      5.79%     114,711
  2001                   --           --        --           --      7.48%       2,488
  2002                   --           --        --           --      8.13%     125,000
  2003                   --           --      5.69%     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
                              ==========             ==========             ==========
</TABLE>

EXPECTED MATURITY/PRINCIPAL REPAYMENT
DECEMBER 31, 1997
(THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
                          SHORT-TERM         VARIABLE LONG-TERM        FIXED LONG-TERM
                     -------------------    -------------------     -------------------
                     INTEREST               INTEREST                INTEREST
                      RATES      AMOUNT      RATES      AMOUNT       RATES      AMOUNT
                     -------------------    -------------------     -------------------
<S>                    <C>    <C>                    <C>              <C>    <C>       
  1998                 6.27%  $  130,750        --   $       --       7.62%  $  104,068
  1999                   --           --        --           --       7.25%     164,378
  2000                   --           --        --           --       5.83%     104,711
  2001                   --           --        --           --       7.48%       2,488
  2002                   --           --      6.25%     150,000       8.13%     125,000
  Years thereafter       --           --      3.62%     439,990       7.92%     973,628
                              ----------             ----------              ----------
  Total                       $  130,750             $  589,990              $1,474,273
                              ==========             ==========              ==========

Fair Value                    $  130,750             $  589,990              $1,504,417
                              ==========             ==========              ==========
</TABLE>

COMMODITY  PRICE RISK We utilize a variety of derivative  instruments  including
exchange-traded  futures,  options,  and  swaps  as  part  of our  overall  risk
management  strategies and for trading purposes.  In order to reduce the risk of
adverse price fluctuations in the electricity and natural gas markets,  we enter
into futures  and/or option  transactions  to hedge certain  natural gas held in
storage  as well as certain  expected  purchases  and sales of  natural  gas and
electricity.  The  changes  in  market  value  of  such  contracts  have  a high
correlation  to the price  changes  in the  hedged  commodity.  Gains and losses
related to  derivatives  that  qualify as hedges of  expected  transactions  are
recognized in income when the  underlying  hedged  physical  transaction  closes
(deferral  method).  Gains and losses on  derivatives  utilized  for trading are
recognized in income on a current basis (the mark to market method).

                                       26
<PAGE>
We have prepared a  sensitivity  analysis to estimate our exposure to the market
risk of our derivative position for natural gas and electricity. With respect to
these derivatives, a potential adverse price movement of 10% in the market price
of natural gas and electricity  from the December 31, 1998 levels would decrease
the fair value of these  instruments by approximately $1 million.  This analysis
does not include the favorable impact that the same hypothetical  price movement
would  have  on  expected  physical  purchases  and  sales  of  natural  gas and
electricity.

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 the
financial viability of counterparties. We do not expect counterparty defaults to
materially impact our financial  condition,  results of operations,  or net cash
flows.

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.

                                       27
<PAGE>
                          ITEM 8. FINANCIAL STATEMENTS
                             AND SUPPLEMENTARY DATA

                          INDEX TO FINANCIAL STATEMENTS

                                                                            Page
                                                                            ----
Report of Management......................................................   29

Independent Auditors' Report..............................................   30

Statements of Income for 1998, 1997, and 1996.............................   31

Balance Sheets as of December 31, 1998 and 1997...........................   32

Statements of Cash Flows for 1998, 1997, and 1996.........................   34

Statements of Retained Earnings for 1998, 1997, and 1996..................   35

Notes to Financial Statements.............................................   35

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

                                       28
<PAGE>

                              REPORT OF MANAGEMENT

The  primary  responsibility  for  the  integrity  of  the  Company's  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.  Materiality was given
due consideration.  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 the Company's  system provides the  appropriate  balance between such costs
and benefits.

Periodically  the  internal  accounting  control  system is reviewed by both the
Company's internal auditors and its 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 Review  Committee of
the Board of Directors and the independent auditors on a timely basis.

The  Audit  Review  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  Review  Committee,  without  management
present, to discuss the results of their audit work.

Management believes that the Company's 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                                 George A. Schreiber, Jr.

William J. Post                                 George A. Schreiber, Jr.
Chief Executive Officer                         Executive Vice President
                                                and Chief Financial Officer

                                       29
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

We have  audited  the  accompanying  balance  sheets of Arizona  Public  Service
Company as of December 31, 1998 and 1997 and the related  statements  of income,
retained earnings and cash flows for each of the three years in the period ended
December 31, 1998.  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, 1998 and 1997
and the results of its operations and its cash flows for each of the three years
in the period ended  December 31, 1998 in  conformity  with  generally  accepted
accounting principles.


Deloitte & Touche LLP

Deloitte & Touche LLP
Phoenix, Arizona
March 4, 1999

                                       30
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                              STATEMENTS OF INCOME


                                                   YEAR ENDED DECEMBER 31,
                                           -------------------------------------
                                              1998         1997         1996
                                           ----------   ----------   ----------
                                                   (THOUSANDS OF DOLLARS)

Electric Operating Revenues .............  $2,006,398   $1,878,553   $1,718,272
                                           ----------   ----------   ----------
Fuel Expenses:
   Fuel for electric generation .........     231,967      201,341      230,393
   Purchased power ......................     305,534      235,286       95,130
                                           ----------   ----------   ----------
     Total ..............................     537,501      436,627      325,523
                                           ----------   ----------   ----------

Operating Revenues Less Fuel Expenses ...   1,468,897    1,441,926    1,392,749
                                           ----------   ----------   ----------
Other Operating Expenses:
   Operations and maintenance excluding
     fuel expenses ......................     414,041      399,434      430,714
   Depreciation and amortization (Note 1)     376,574      365,671      297,210
   Income taxes (Note 10) ...............     192,207      184,737      178,513
   Other taxes ..........................     115,264      120,259      121,104
                                           ----------   ----------   ----------
     Total ..............................   1,098,086    1,070,101    1,027,541
                                           ----------   ----------   ----------

Operating Income ........................     370,811      371,825      365,208
                                           ----------   ----------   ----------
Other Income (Deductions):
   Allowance for equity funds used during
     construction .......................          --           --        5,209
   Income taxes (Note 10) ...............      32,751       31,413       45,552
   Other -- net .........................     (12,303)      (9,827)     (15,544)
                                           ----------   ----------   ----------
     Total ..............................      20,448       21,586       35,217
                                           ----------   ----------   ----------

Income Before Interest Deductions .......     391,259      393,411      400,425
                                           ----------   ----------   ----------
Interest Deductions:
   Interest on long-term debt ...........     137,214      140,931      147,666
   Interest on short-term borrowings ....       7,481        9,404       10,621
   Debt discount, premium and expense ...       7,580        7,791        8,176
   Capitalized interest .................     (16,263)     (16,208)      (9,509)
                                           ----------   ----------   ----------
     Total ..............................     136,012      141,918      156,954
                                           ----------   ----------   ----------

Net Income ..............................     255,247      251,493      243,471
Preferred Stock Dividend Requirements ...       9,703       12,803       17,092
                                           ----------   ----------   ----------

Earnings for Common Stock ...............  $  245,544   $  238,690   $  226,379
                                           ==========   ==========   ==========

See Notes to Financial Statements.

                                       31
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                                 BALANCE SHEETS
                                     ASSETS

                                                              DECEMBER 31,
                                                      -------------------------
                                                          1998          1997
                                                      -----------   -----------
                                                        (THOUSANDS OF DOLLARS)
Utility Plant (Notes 5, 8 and 9):
   Electric plant in service and held for
    future use......................................  $ 7,265,604   $ 7,009,059
   Less accumulated depreciation and amortization ..    2,814,762     2,620,607
                                                      -----------   -----------
     Total .........................................    4,450,842     4,388,452
   Construction work in progress ...................      228,643       237,492
   Nuclear fuel, net of amortization of $68,569
     and $66,081 ...................................       51,078        51,624
                                                      -----------   -----------
     Utility Plant -- net ..........................    4,730,563     4,677,568
                                                      -----------   -----------

Investments and Other Assets (Note 13) .............      183,549       164,906
                                                      -----------   -----------

Current Assets:
   Cash and cash equivalents .......................        5,558        12,552
   Accounts receivable:
     Service customers .............................      205,999       141,022
     Other .........................................       23,213        31,313
     Allowance for doubtful accounts ...............       (1,725)       (1,338)
   Accrued utility revenues ........................       67,740        58,559
   Materials and supplies (at average cost) ........       69,074        70,634
   Fossil fuel (at average cost) ...................       13,978         9,621
   Deferred income taxes (Note 10) .................        3,999         3,496
   Other ...........................................       26,695        24,529
                                                      -----------   -----------
     Total Current Assets ..........................      414,531       350,388
                                                      -----------   -----------
Deferred Debits:
   Regulatory asset for income taxes (Note 10) .....      400,795       458,369
   Rate synchronization cost deferral ..............      303,660       358,871
   Unamortized costs of reacquired debt ............       53,744        63,501
   Unamortized debt issue costs ....................       14,916        15,303
   Other ...........................................      291,541       242,236
                                                      -----------   -----------
     Total Deferred Debits .........................    1,064,656     1,138,280
                                                      -----------   -----------
     Total .........................................  $ 6,393,299   $ 6,331,142
                                                      ===========   ===========

See Notes to Financial Statements.

                                       32
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                                 BALANCE SHEETS
                                   LIABILITIES

                                                               DECEMBER 31,
                                                         -----------------------
                                                            1998         1997
                                                         ----------   ----------
                                                          (THOUSANDS OF DOLLARS)
Capitalization (Notes 4 and 5):
   Common stock ......................................   $  178,162   $  178,162
   Additional paid--in capital .......................    1,195,625    1,142,364
   Retained earnings .................................      601,968      528,798
                                                         ----------   ----------
     Common stock equity .............................    1,975,755    1,849,324
   Non-redeemable preferred stock ....................       85,840      142,051
   Redeemable preferred stock ........................        9,401       29,110
   Long-term debt less current maturities ............    1,876,540    1,953,162
                                                         ----------   ----------
     Total Capitalization ............................    3,947,536    3,973,647
                                                         ----------   ----------
Current Liabilities:
   Commercial paper (Note 6) .........................      178,830      130,750
   Current maturities of long-term debt (Note 5) .....      164,378      104,068
   Accounts payable ..................................      145,139      107,423
   Accrued taxes .....................................       59,827       85,886
   Accrued interest ..................................       31,218       31,660
   Customer deposits .................................       26,815       29,116
   Other .............................................       16,755       19,588
                                                         ----------   ----------
     Total Current Liabilities .......................      622,962      508,491
                                                         ----------   ----------
Deferred Credits and Other:
   Deferred income taxes (Note 10) ...................    1,312,007    1,345,177
   Deferred investment tax credit (Note 10) ..........       32,465       60,093
   Unamortized gain--sale of utility plant (Note 9)...       77,787       82,363
   Customer advances for construction ................       31,451       29,294
   Other .............................................      369,091      332,077
                                                         ----------   ----------
     Total Deferred Credits and Other ................    1,822,801    1,849,004
                                                         ----------   ----------
Commitments and Contingencies (Note 12)

   Total .............................................   $6,393,299   $6,331,142
                                                         ==========   ==========

                                       33
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                            STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
                                                                  YEAR ENDED DECEMBER 31,
                                                           ---------------------------------
                                                              1998        1997        1996
                                                           ---------   ---------   ---------
                                                                 (THOUSANDS OF DOLLARS)
<S>                                                        <C>         <C>         <C>
Cash Flows from Operations:
   Net income ..........................................   $ 255,247   $ 251,493   $ 243,471
   Items not requiring cash:
     Depreciation and amortization .....................     376,574     365,671     297,210
     Nuclear fuel amortization .........................      32,856      32,702      33,566
     Allowance for equity funds used during
       construction.....................................          --          --      (5,209)
     Deferred income taxes -- net ......................     (26,374)    (55,278)    (12,717)
     Deferred investment tax credit -- net .............     (27,628)    (27,630)    (27,630)
   Changes in certain current assets and liabilities:
     Accounts receivable -- net ........................     (56,490)    (11,069)    (33,044)
     Accrued utility revenues ..........................      (9,181)     (3,089)     (1,951)
     Materials, supplies and fossil fuel ...............      (2,797)      7,793      11,945
     Other current assets ..............................      (2,166)     (1,762)     (4,928)
     Accounts payable ..................................      33,731     (56,710)     68,788
     Accrued taxes .....................................     (26,059)       (441)      3,500
     Accrued interest ..................................        (442)     (7,455)     (2,565)
     Other current liabilities .........................      (4,654)     (3,997)       (522)
   Other -- net ........................................     (29,641)     46,625       7,616
                                                           ---------   ---------   ---------
     Net cash provided .................................     512,976     536,853     577,530
                                                           ---------   ---------   ---------
Cash Flows from Investing:
   Capital expenditures ................................    (319,142)   (307,876)   (258,598)
   Capitalized interest ................................     (16,263)    (16,208)     (9,509)
   Other ...............................................      (8,593)    (15,982)       (102)
                                                           ---------   ---------   ---------
     Net cash used .....................................    (343,998)   (340,066)   (268,209)
                                                           ---------   ---------   ---------
Cash Flows from Financing:
   Long-term debt ......................................     126,245     109,906     205,830
   Short-term borrowings--net ..........................      48,080     113,850    (160,900)
   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 ...................     (10,279)    (13,307)    (17,416)
   Repayment of preferred stock ........................     (75,517)    (47,201)    (50,360)
   Repayment and reacquisition of long-term debt .......    (144,501)   (240,004)   (172,343)
                                                           ---------   ---------   ---------
     Net cash used .....................................    (175,972)   (196,756)   (315,189)
                                                           ---------   ---------   ---------

Net increase (decrease) in cash and cash equivalents ...      (6,994)         31      (5,868)
Cash and cash equivalents at beginning of year .........      12,552      12,521      18,389
                                                           ---------   ---------   ---------

Cash and cash equivalents at end of year ...............   $   5,558   $  12,552   $  12,521
                                                           =========   =========   =========

Supplemental Disclosure of Cash Flow Information:
   Cash paid during the year for:
     Interest (excluding capitalized interest) .........   $ 128,627   $ 141,991   $ 150,603
     Income taxes ......................................   $ 235,475   $ 236,676   $ 158,553
</TABLE>

See Notes to Financial Statements.

                                       34
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                         STATEMENTS OF RETAINED EARNINGS


                                                      YEAR ENDED DECEMBER 31,
                                                  ------------------------------
                                                    1998       1997       1996
                                                  --------   --------   --------
                                                      (THOUSANDS OF DOLLARS)

Retained earnings at beginning of year .......... $528,798   $460,106   $403,843
Add:  Net income ................................  255,247    251,493    243,471
                                                  --------   --------   --------
   Total ........................................  784,045    711,599    647,314
                                                  --------   --------   --------
Deduct:
 Dividends:
   Common stock (Notes 4 and 5) .................  170,000    170,000    170,000
   Preferred stock (at required rates) (Note 4)..    9,703     12,801     17,092
 Other ..........................................    2,374         --        116
                                                  --------   --------   --------
   Total deductions .............................  182,077    182,801    187,208
                                                  --------   --------   --------

Retained earnings at end of year ................ $601,968   $528,798   $460,106
                                                  ========   ========   ========

See Notes to Financial Statements.


                                       APS
                          NOTES TO FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NATURE OF OPERATIONS We are Arizona's  largest  electric  utility,  with 799,000
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.

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 Arizona  Corporation  Commission
(ACC) and the Federal Energy  Regulatory  Commission  (FERC).  The  accompanying
financial statements reflect the rate-making  policies of these commissions.  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.

Our major  regulatory  assets are  deferred  income taxes (see Note 10) and rate
synchronization  cost deferrals (see "Rate  Synchronization  Cost  Deferrals" in
this Note).  These items,  combined  with  miscellaneous  regulatory  assets and
liabilities,  amounted to  approximately  $900  million at December 31, 1998 and
$1.0 billion at December 31, 1997. Most of these items are included in "Deferred
Debits" on the Balance Sheets. 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  will end June 30,  2004.  We record  the
accelerated  portion of the regulatory asset  amortization,  approximately  $120
million pretax in 1998 and 1997 and $60 million pretax in 1996, in  depreciation
and amortization expense on the Statements of Income.

                                       35
<PAGE>
                                       APS
                          NOTES TO 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.

Although  rules have been  proposed  for  transitioning  generation  services to
competition,  there are many unresolved issues. We continue to apply SFAS No. 71
to our generation operations. If rate recovery of regulatory assets is no longer
probable,  whether due to competition or regulatory action, we would be required
to write off the remaining balance as an extraordinary charge to expense.

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

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 13 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 1996 through 1998 the rates, as prescribed by our regulators,  ranged from
a low of 1.51% to a high of 20%. The  weighted-average  rate for 1998 was 3.32%.
We depreciate non-utility property and equipment over the estimated useful lives
of the related assets, ranging from 3 to 50 years.

CAPITALIZED  INTEREST In 1997 we began capitalizing  interest in accordance with
SFAS No. 34,  "Capitalization of Interest Cost." Capitalized interest represents
the cost of debt funds  used to finance  construction  of utility  plant.  Plant
construction costs,  including capitalized interest, are recovered in authorized
rates 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 for 1998 was 6.88% and for 1997 was
7.25%.

Prior to 1997 we  accrued  an  allowance  for  funds  used  during  construction
(AFUDC).  AFUDC  represented  the cost of debt and equity  funds used to finance
construction  of utility plant.  AFUDC did not represent  current cash earnings.
AFUDC has been calculated using a composite rate of 7.75% for 1996.

REVENUES We record  electric  operating  revenues on the  accrual  basis,  which
includes  estimated amounts for service rendered but unbilled at the end of each
accounting period.

RATE  SYNCHRONIZATION  COST DEFERRALS As authorized by the ACC,  operating costs
(excluding  fuel) and financing  costs of Palo Verde Units 2 and 3 were deferred
from the commercial  operation dates (September 1986 for Unit 2 and January 1988
for Unit 3) until the date the units were  included in a rate order  (April 1988
for Unit 2 and December 1991 for Unit 3).  Beginning July 1, 1996, the deferrals
are being amortized over an eight-year period in

                                       36
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

accordance  with the 1996  regulatory  agreement  (see Note 3). Prior to July 1,
1996, the deferrals were amortized over thirty-five  year periods.  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 the number of thermal units that we produce within
the current period. This provides us with 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. In addition, Note 13 has information on nuclear decommissioning costs.

REACQUIRED DEBT COSTS When we incur gains or losses on debt that we retire prior
to maturity, we amortize those gains and losses over the remaining original life
of the debt. In accordance with the 1996 regulatory  agreement (see Note 3), the
ACC  accelerated our  amortization  of the regulatory  asset for reacquired debt
costs to 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 debt  instruments  that will mature in three months
or less.

RECLASSIFICATIONS We have reclassified certain prior year amounts for comparison
purposes with 1998.

2. ACCOUNTING MATTERS

In 1998 we adopted SFAS No. 130, "Reporting Comprehensive Income." This standard
changes the reporting of certain items  previously  reported in the common stock
equity section of the balance  sheet.  The effects of adopting SFAS No. 130 were
not material to our financial statements.

In November 1998, the Financial  Accounting  Standards  Board's  Emerging Issues
Task Force  issued  EITF 98-10,  "Accounting  for  Contracts  Involved in Energy
Trading and Risk Management Activities," which is effective for us in 1999. 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. We have evaluated the impact
of this  rule  and  believe  the  effects  are  not  material  to our  financial
statements.

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 2000.  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.

                                       37
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

3. REGULATORY MATTERS

ELECTRIC INDUSTRY RESTRUCTURING

STATE In December  1996,  the ACC adopted rules that provide a framework for the
introduction of retail electric  competition in Arizona.  The rules, as amended,
became  effective on August 10, 1998,  and on December 10, 1998, the ACC adopted
the amended rules without any modifications that would have a significant impact
on us. We believe that certain  provisions of the 1996 ACC rules and the amended
rules are  deficient  and we have filed  lawsuits  to protect  our legal  rights
regarding the 1996 rules and the amended  rules.  These lawsuits are pending but
two related  cases filed by other  utilities  have been  partially  decided in a
manner adverse to those utilities' positions.

On January 11,  1999,  the ACC issued an order which  stayed the amended  rules,
granted  reconsideration  of the  decision  to make  the  rules  permanent,  and
directed the hearing  division of the ACC to  establish a  procedural  order for
further action on these rules.  The order also granted  waivers from  compliance
with the rules for us, and all affected utilities.

On February 5, 1999, the ACC Hearing Division issued recommendations for changes
to the amended rules. The recommended  changes to the amended rules were further
modified by a Procedural Order of the ACC Hearing Division dated March 12, 1999.
The recommended rules include the following major provisions:

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

          +    Each  utility  must  make at least  20% of its 1995  retail  peak
               demand available for competitive generation supply.

          +    The rules become effective when the ACC makes a final decision on
               each utility's stranded costs and unbundled rates (Final Decision
               Date) or January 1, 2001, whichever comes first.

          +    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.
               Customers  with single  premise  loads of 40 kilowatts or greater
               may aggregate loads to meet this one megawatt requirement.

          +    When effective, residential customers will be phased in at 1 1/4%
               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 with separate  pricing
               for electric services provided for noncompetitive services.

          +    ACC  shall  allow  a  reasonable   opportunity  for  recovery  of
               unmitigated stranded costs (see "Stranded Costs" below).

                                       38
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

          +    Absent an ACC  waiver,  prior to January 1, 2001,  each  affected
               utility  must  transfer  all  competitive  generation  assets and
               services  either  to  an  unaffiliated  party  or  to a  separate
               corporate affiliate.

          +    Affiliate   transaction   rules   prohibit  a  utility   and  its
               competitive  electric  affiliates  from sharing  certain  assets,
               employees, and information.

If  approved  by the ACC,  the rules  would be subject to the formal  rulemaking
process  under  Arizona  statute.   In  compliance  with  statutory   procedural
requirements,  ACC oral  proceedings  on the matter would be scheduled no sooner
than 30 days after the proposed rules are published by the Secretary of State.

We  cannot  currently  predict  when or if the  amended  rules  will be  further
modified,  when the stay of the  amended  rules will be lifted,  or when  retail
electric competition will be introduced in Arizona.

         STRANDED  COSTS On June 22,  1998,  the ACC issued an Order on stranded
cost  determination  and  recovery.  We believe that certain  provisions  of the
stranded  cost order are  deficient and in August 1998, we filed two lawsuits to
protect our legal rights relating to the order.

On February 5, 1999, the ACC Hearing Division issued recommended  changes to the
June 1998 stranded cost order. These recommended changes were further amended by
an ACC  Procedural Order dated March 12, 1999.  The  recommended  changes to the
stranded cost order would be effective upon approval of the ACC. The recommended
order, as amended on March 12, 1999, allows each affected utility to choose from
five options for the recovery of stranded costs:

          +    Net  Revenues  Lost   Methodology  is  the   difference   between
               generation  revenues under traditional  regulation and generation
               revenues under  competition.  This option  provides for declining
               recovery percentages for stranded costs over a five-year recovery
               period.  Regulatory  assets are to be fully recovered under their
               presently authorized  amortization schedule. In accordance with a
               1996 regulatory  agreement,  the ACC accelerated the amortization
               of  substantially  all of our regulatory  assets to an eight-year
               period that ends June 30, 2004.

          +    Divestiture/Auction Methodology allows a utility to divest all or
               substantially all of its generating assets,  including regulatory
               assets  associated  with  generation,  in  order to  collect  100
               percent of the difference  between net sales price and book value
               of generating  assets  divested over a ten-year  period,  with no
               return on the unamortized balance.

          +    Financial  Integrity  Methodology  allows a  utility  "sufficient
               revenues to meet  minimum  financial  ratios" for a period of ten
               years.

          +    Settlement  Methodology  allows a settlement to be agreed upon by
               the ACC and a utility.

          +    Any combination of the above if shown to be in the best interests
               of all affected parties.

         LEGISLATIVE  INITIATIVES An Arizona joint legislative committee studied
electric utility industry  restructuring issues in 1996 and 1997. In conjunction
with that study, the Arizona legislative counsel prepared memoranda in late 1997
related to the legal  authority of the ACC to  deregulate  the Arizona  electric
utility  industry.  The memoranda raise a question as to the degree to which the
ACC may, under the Arizona Constitution,  deregulate any portion of the electric
utility industry and allow rates to be determined by market forces. This latter

                                       39
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

issue has been subsequently  decided by lower courts in favor of the ACC in four
separate lawsuits, two of which are unrelated.

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 legislature on certain competitive issues.

         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 Agreement contains
the following major components:

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

          +    Both  parties  would amend the Power  Coordination  Agreement  to
               lower the price that we will pay Salt River Project for purchased
               power by approximately $17 million (pretax) during the first full
               year that the Agreement is effective and by lesser annual amounts
               during the next seven years.

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

Certain provisions of the Agreement  (including those relating to the amendments
of the Territorial Agreement and the Power Coordination  Agreement) are affected
by the timing of the  introduction  of  competition.  See "ACC Rules" above.  On
February 18, 1999, the ACC approved the Agreement.

         GENERAL We believe  that  further  ACC  decisions,  legislation  at the
Arizona and federal levels, and perhaps  amendments to the Arizona  Constitution
(which would require a vote of the people) will  ultimately  be required  before
significant  implementation of retail electric competition can lawfully occur in
Arizona. Until the manner of implementation of competition, including addressing
stranded costs, is determined,  we cannot accurately  predict the impact of full
retail  competition  on our  financial  position,  cash  flows,  or  results  of
operation.

                                       40
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

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.

Several  electric  utility  reform  bills  have been  introduced  during  recent
congressional  sessions,  which as currently  written  would allow  consumers to
choose their  electricity  suppliers by 2000 or 2003.  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
substantial restructuring of the electric utility industry can occur.

1996 REGULATORY AGREEMENT

In April 1996, the ACC approved a regulatory agreement between the ACC Staff and
us. The major provisions of this agreement are:

          +    An annual rate  reduction  of  approximately  $48.5  million ($29
               million after income taxes), or 3.4% on average for all customers
               except certain contract customers, effective July 1, 1996.

          +    Recovery of substantially  all of our present  regulatory  assets
               through  accelerated  amortization over an eight-year period that
               will  end  June  30,  2004,  increasing  annual  amortization  by
               approximately  $120 million ($72 million after income taxes). See
               Note 1.

          +    A formula for sharing future cost savings  between  customers and
               shareholders (price reduction  formula),  referencing a return on
               equity (as defined) of 11.25%.

          +    A moratorium on filing for  permanent  rate changes prior to July
               2,  1999,  except  under the price  reduction  formula  and under
               certain other limited circumstances.

          +    Infusion  of $200  million of common  equity  into us by Pinnacle
               West, in annual payments of $50 million starting in 1996.

Based on the price reduction formula, the ACC approved retail price decreases of
approximately  $17.6  million  ($10.5  million  after  income  taxes),  or 1.2%,
effective July 1, 1997, and  approximately $17 million ($10 million after income
taxes),  or 1.1%,  effective  July 1,  1998.  We expect to file with the ACC for
another  retail price  decrease of  approximately  $10.8 million  annually ($6.5
million after income  taxes) to become  effective  July 1, 1999.  The amount and
timing of the price decrease are subject to ACC approval.  This will be the last
price decrease under the 1996 regulatory agreement.

                                       41
<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, 1998 and 1997 are shown below:

<TABLE>
<CAPTION>
                                               NUMBER
                                             OF SHARES            PAR          PAR VALUE          CALL
                                            OUTSTANDING          VALUE        OUTSTANDING         PRICE
                                      -----------------------     PER    ---------------------     PER
                         AUTHORIZED      1998         1997       SHARE      1998        1997     SHARE(A)
                         ----------   ----------   ----------  --------  ---------   ---------  ---------
                                                                         (THOUSANDS OF DOLLARS)
<S>                     <C>           <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      145,559  $  25.00  $   3,476   $   3,639   $ 27.50
 $2.50 ................     105,000       86,440       97,252     50.00      4,322       4,863     51.00
 $2.36 ................     120,000       32,520       38,506     50.00      1,626       1,925     51.00
 $4.35 ................     150,000       62,986       68,386    100.00      6,299       6,839    102.00
 Serial preferred .....   1,000,000
   $2.40 Series A .....                  200,587      234,839     50.00     10,029      11,742     50.50
   $2.625 Series C ....                  214,895      231,572     50.00     10,745      11,579     51.00
   $2.275 Series D ....                   90,691      164,101     50.00      4,534       8,205     50.50
   $3.25 Series E .....                  304,475      312,991     50.00     15,224      15,649     51.00
 Serial preferred .....   4,000,000(b)
   Adjustable rate --
     Series Q .........                  295,851      352,851    100.00     29,585      35,285      (c)
 Serial preferred .....  10,000,000
   $1.8125 Series W ...                       --    1,693,016     25.00         --      42,325
                                      ----------   ----------            ---------   ---------
     Total ............                1,427,475    3,339,073            $  85,840   $ 142,051
                                      ==========   ==========            =========   =========
 Redeemable:
 Serial preferred:
   $10.00 Series U ....                   94,011      291,098  $ 100.00  $   9,401   $  29,110
                                      ==========   ==========            =========   =========
</TABLE>
----------
(a)  The actual  call price per share is the  indicated  amount plus any accrued
     dividends.

(b)  This authorization also covers all outstanding redeemable preferred stock.

(c)  Dividend rate adjusted  quarterly to 2% below that of certain United States
     Treasury  securities,  but in no event less than 6% or greater than 12% per
     annum. Redeemable at par.

                                       42
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

We cannot pay  common  stock  dividends  or  acquire  shares of common  stock if
preferred stock dividends or sinking fund requirements are in arrears.

Redeemable  preferred stock  transactions  during each of the three years in the
period ended December 31, 1998 are as follows:

<TABLE>
<CAPTION>
                                NUMBER OF SHARES                      PAR VALUE
                                  OUTSTANDING                        OUTSTANDING
                          -----------------------------    ------------------------------
                                                               (THOUSANDS OF DOLLARS)
     DESCRIPTION            1998       1997       1996       1998       1997       1996
--------------------      --------   --------   --------   --------   --------   --------
<S>              <C>       <C>        <C>        <C>       <C>        <C>        <C>
Balance, January 1......   291,098    530,000    750,000   $ 29,110   $ 53,000   $ 75,000
 Retirements:
   $10.00 Series U......  (197,087)  (118,902)   (90,000)   (19,709)   (11,890)    (9,000)
   $7.875 Series V......        --   (120,000)  (130,000)        --    (12,000)   (13,000)
                          --------   --------   --------   --------   --------   --------
Balance, December 31....    94,011    291,098    530,000   $  9,401   $ 29,110   $ 53,000
                          ========   ========   ========   ========   ========   ========
</TABLE>
                                       43
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

5. LONG-TERM DEBT

The following table presents long-term debt outstanding:

                                                              DECEMBER 31
                             MATURITY     INTEREST      -----------------------
                             DATES (a)     RATES          1998           1997
                             ---------     -----          ----           ----
                                                        (THOUSANDS  OF DOLLARS)

First mortgage bonds           1998        7.625%       $     --       $100,000
                               1999        7.625%        100,000        100,000
                               2000         5.75%        100,000        100,000
                               2002        8.125%        125,000        125,000
                               2004        6.625%         85,000         85,000
                               2020        10.25%        100,550        109,550
                               2021          9.5%         45,140         45,140
                               2021            9%         72,370         72,370
                               2023         7.25%         91,900         97,150
                               2024         8.75%        121,668        121,918
                               2025            8%         88,300         88,500
                               2028          5.5%         25,000         25,000
                               2028        5.875%        154,000        154,000
Unamortized discount
 and premium                                              (6,482)        (7,033)
Pollution control bonds     2024-2033    Adjustable      456,860        439,990
                                            rate (b)
Collateralized loan         1999-2000      5.375% -       20,000         10,000
                                           6.125%
Unsecured note                 2005         6.25%        100,000            --
Senior notes(c)                1999         6.72%         50,000         50,000
Senior notes(c)                2006         6.75%        100,000        100,000
Debentures                     2025           10%         75,000         75,000
Bank loans                     2003      Adjustable      125,000        150,000
                                           rate (d)
Capitalized lease
 obligation                 1998-2001       7.48% (e)     11,612         15,645
                                                      ----------     ----------
   Total long-term debt                                2,040,918      2,057,230
Less current maturities                                  164,378        104,068
                                                      ----------     ----------
   Total long-term debt less current maturities       $1,876,540     $1,953,162
                                                      ==========     ==========
----------

(a)  This  schedule  does not reflect the timing of  redemptions  that may occur
     prior to maturity.

(b)  The  weighted-average  rate for the years ended December 31, 1998 was 3.39%
     and for December 31, 1997 was 3.62%.  Changes in short-term  interest rates
     would affect the costs associated with this debt.

                                       44
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

(c)  We issued $150 million of first mortgage bonds ("senior note mortgage
     bonds") 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.

(d)  The  weighted-average  rate at December  31, 1998 was 5.69% and at December
     31, 1997 was 6.25%.  Changes in short-term  interest rates would affect the
     costs associated with this debt.

(e)  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:

          +    $164.4 million in 1999
          +    $114.7 million in 2000
          +    $2.5 million in 2001
          +    $125 million in 2002 and
          +    $125 million in 2003.

 First  mortgage  bondholders  have 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, 1998.

6. LINES OF CREDIT

We had committed  lines of credit with various banks of $400 million at December
31,  1998 and 1997,  which were  available  either to support  the  issuance  of
commercial  paper or to be used  for bank  borrowings.  The  commitment  fees at
December  31, 1998 and 1997 for these  lines of credit  ranged from .07% to .15%
per annum.  We had  long-term  bank  borrowings of $125 million  outstanding  at
December 31, 1998, and $150 million outstanding at December 31, 1997.

Our commercial paper borrowings  outstanding were $178.8 million at December 31,
1998,  and $130.8 million at December 31, 1997.  The weighted  average  interest
rate on commercial  paper borrowings was 6.21% on December 31, 1998 and 6.27% on
December 31, 1997. 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, 1998 and
1997 due to their  short  maturities.  We hold  investments  in debt and  equity
securities for purposes other than trading.  The December 31, 1998 and 1997 fair
values of these 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.

                                       45
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

The  carrying  value  of our  long-term  debt  (excluding  a  capitalized  lease
obligation) was $2.03 billion on December 31, 1998, with an estimated fair value
of $2.11 billion. On December 31, 1997, the carrying value of our long-term debt
(excluding a capitalized lease obligation) was $2.04 billion,  with an estimated
fair value of $2.08 billion. The fair value estimates are based on quoted market
prices of the same or similar issues.

8. JOINTLY-OWNED FACILITIES

We share  ownership of some of our generating and  transmission  facilities with
other companies.  The following table shows our interest in those  jointly-owned
facilities at December 31, 1998.  Our share of operating and  maintaining  these
facilities  is included in the income  statement in operations  and  maintenance
expense.

                                  PERCENT                           CONSTRUCTION
                                 OWNED BY   PLANT IN   ACCUMULATED    WORK IN
                                  COMPANY   SERVICE   DEPRECIATION    PROGRESS
                                 --------   --------  ------------  ------------
                                              (THOUSANDS OF DOLLARS)
Generating Facilities:
 Palo Verde Nuclear Generating
  Station Units 1 and 3           29.1%    $1,821,620   $670,403      $20,152
 Palo Verde Nuclear Generating
  Station Unit 2 (see Note 9)     17.0%       568,184    224,502        9,839
 Four Corners Steam Generating
  Station Units 4 and 5           15.0%       150,165     69,764          312
 Navajo Steam Generating Station
   Units 1, 2, and 3              14.0%       203,356     90,237       25,560(a)
 Cholla Steam Generating Station
   Common Facilities (b)          62.8%(c)     67,513     37,096          267
Transmission Facilities:
 ANPP 500KV System                35.8%(c)     66,547     20,282        1,384
 Navajo Southern System           31.4%(c)     26,918     17,285           21
 Palo Verde-Yuma 500KV System     23.9%(c)     11,376      4,215            -
 Four Corners Switchyards         27.5%(c)      3,071      1,780          143
 Phoenix-Mead System              17.1%(c)     36,324        536            -

----------
(a)  The construction  costs at Navajo are primarily related to the installation
     of scrubbers required by environmental legislation.

(b)  Pacificorp  owns Cholla Unit 4 and we operate the unit for them. The common
     facilities at the Cholla Plant are jointly-owned.

(c)  Weighted average of interests.

                                       46
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

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  $140.2  million  was
deferred and is being  amortized  to  operations  expense  over 29.5 years,  the
original  term of the  leases.  There are  options  to renew the  leases for two
additional  years and to purchase  the property for fair market value at the end
of the lease terms. Consistent with the ratemaking treatment, an amount equal to
the annual lease  payments is included in rent  expense.  A regulatory  asset is
recognized for the difference between lease payments and rent expense calculated
on a straight-line basis.

The average amounts to be paid for the Palo Verde Unit 2 leases are as follows:

YEAR                                        (IN MILLIONS)
----
1999                                           $40.1
2000                                            46.3
2001-2015                                       49.0

In  accordance  with  the  1996  regulatory  agreement  (see  Note  3),  the ACC
accelerated our amortization of the regulatory asset for leases to 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, 1998 was $48.5 million.  Lease expense
was approximately $42 million in each of the years 1996 through 1998.

We have a capital  lease on a  combined  cycle  plant,  which we sold and leased
back. The lease requires  semiannual payments of $2.6 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  $54.4  million;
accumulated amortization at December 31, 1998 was $48.6 million.

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

Approximate miscellaneous lease expense was:

          +    $9.6 million in 1998
          +    $7.8 million in 1997 and
          +    $9.7 million in 1996.

                                       47
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

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

YEAR                         (IN MILLIONS)
----
1999                           $    13
2000                                13
2001                                14
2002                                14
2003                                13
Thereafter                          91
                               -------
Total future commitments       $   158
                               =======

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 are
amortizing  almost  all  of our  investment  tax  credits  (ITCs)  over 5  years
(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 on our Balance Sheet in accordance with SFAS
No. 71. This regulatory asset is for certain  temporary  differences,  primarily
AFUDC equity. We amortize this amount as the differences  reverse.  We have been
able to accelerate the  amortization of the regulatory asset for income taxes to
an  eight-year  period that will end June 30,  2004.  This is a result of a 1996
regulatory   agreement  with  the  ACC.  We  are  including   this   accelerated
amortization  in  depreciation  and  amortization  expense on the  Statements of
Income.

The components of income tax expense are as follows:

                                                  YEAR ENDED DECEMBER 31,
                                            -----------------------------------
                                               1998         1997         1996
                                            ---------    ---------    ---------
                                                  (THOUSANDS OF DOLLARS)
Current:
   Federal ..............................   $ 170,806    $ 187,701    $ 137,531
   State ................................      42,652       48,531       35,777
                                            ---------    ---------    ---------
     Total current ......................     213,458      236,232      173,308
Deferred ................................     (26,374)     (55,278)        (869)
Change in valuation allowance ...........          --           --      (11,848)
Investment tax credit amortization ......     (27,628)     (27,630)     (27,630)
                                            ---------    ---------    ---------
     Total expense ......................   $ 159,456    $ 153,324    $ 132,961
                                            =========    =========    =========

                                       48
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

Multiplying  income before income taxes by the statutory federal income tax rate
does not  equal the  amount  recorded  as  income  tax  expense  because  of the
following:

<TABLE>
<CAPTION>
                                                                  YEAR ENDED DECEMBER 31,
                                                           --------------------------------
                                                             1998        1997        1996
                                                           --------    --------    --------
                                                                  (THOUSANDS OF DOLLARS)
<S>                                                      <C>          <C>          <C>
Federal income tax expense at 35% statutory rate .......   $145,146    $141,686    $131,751
Increases (reductions) in tax expense resulting from:
   Tax under book depreciation .........................     17,848      14,694      19,229
   Investment tax credit amortization ..................    (27,628)    (27,630)    (27,630)
   State income tax -- net of federal income tax benefit     23,024      23,160      20,790
   Change in valuation allowance .......................         --          --     (10,269)

   Other ...............................................      1,066       1,414        (910)
                                                           --------    --------    --------
     Income tax expense ................................   $159,456    $153,324    $132,961
                                                           ========    ========    ========
</TABLE>

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

                                                             DECEMBER 31,
                                                       -----------------------
                                                          1998         1997
                                                       ----------   ----------
                                                        (THOUSANDS OF DOLLARS)
Deferred tax assets:
   Deferred gain on Palo Verde Unit 2 sale/leaseback   $   31,285   $   33,257
   Other ...........................................       74,292       77,412
                                                       ----------   ----------
     Total deferred tax assets .....................      105,577      110,669
                                                       ----------   ----------

Deferred tax liabilities:
   Plant related ...................................    1,112,897    1,096,222
   Regulatory asset for income taxes ...............      161,836      185,084
   Rate synchronization deferrals ..................      122,130      144,908
   Other ...........................................       16,722       26,136
                                                       ----------   ----------
     Total deferred tax liabilities ................    1,413,585    1,452,350
                                                       ----------   ----------

Deferred income taxes -- net .......................   $1,308,008   $1,341,681
                                                       ==========   ==========

11. RETIREMENT PLANS AND OTHER BENEFITS

VOLUNTARY  SEVERANCE PLAN We sponsored a voluntary severance plan in 1996. There
was a pretax charge of $31.7 million in 1996 recorded  mostly as operations  and
maintenance  expense.   This  pretax  charge  included  additional  pension  and
postretirement  benefit  expense.  Employees who  participated  in the plan were
credited  with an  additional  year of age and  service  when their  pension and
postretirement  benefits were calculated.  The additional  expenses  recorded in
1996 for  this  plan  were  $2.3  million  for  pension  and  $5.4  million  for
postretirement benefits.

PENSION  PLAN We sponsor a defined  benefit  pension plan for our  employees.  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 APS
employees. Our employees do not contribute to this plan. Generally, we calculate
the benefits under this

                                       49
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

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, 1998 were mostly domestic and international common stocks and bonds
and real estate. Pension expense,  including administrative and severance costs,
was:

          +    $9.8 million in 1998
          +    $8.7 million in 1997 and
          +    $14.9 million in 1996.

The   following   table  shows  the   components  of  net  pension  cost  before
consideration of amounts capitalized or billed to others and excluding severance
costs of $2.9 million in 1996:

                                                1998        1997        1996
                                              --------    --------    --------
                                                   (THOUSANDS OF DOLLARS)
Service cost -- benefits earned during
  the period................................  $ 24,126    $ 19,881    $ 22,861
Interest cost on projected benefit
  obligation ...............................    50,863      47,824      44,602
Expected return on plan assets .............   (53,883)    (47,422)    (41,958)
Amortization of:
     Transition asset ......................    (3,216)     (3,216)     (3,216)
     Prior service cost ....................     2,063       2,063       1,727
     Net actuarial losses ..................        --          --         721
                                              --------    --------    --------
Net periodic pension cost ..................  $ 19,953    $ 19,130    $ 24,737
                                              ========    ========    ========

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

                                                        1998        1997
                                                      --------    --------
                                                      (THOUSANDS OF DOLLARS)
Funded status -- Pension plan assets less than
  projected benefit obligation ....................   $(38,957)   $(87,208)
Unrecognized net transition asset .................    (23,159)    (26,376)
Unrecognized prior service cost ...................     22,562      24,625
Unrecognized net actuarial losses/(gains) .........    (38,916)     16,989
                                                      --------    --------
Net pension amount recognized in the balance
  sheets...........................................   $(78,470)   $(71,970)
                                                      ========    ========

                                       50
<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 1998 and 1997:

                                                         1998         1997
                                                      ---------    ---------
                                                      (THOUSANDS OF DOLLARS)
Projected pension benefit obligation
  at beginning of year ............................   $ 699,600    $ 601,094
Service cost ......................................      24,126       19,881
Interest cost .....................................      50,863       47,824
Benefit payments ..................................     (29,384)     (29,741)
Plan amendments ...................................          --        5,537
Actuarial losses/(gains) ..........................     (23,976)      55,005
                                                      ---------    ---------
Projected pension benefit obligation
  at end of year...................................   $ 721,229    $ 699,600
                                                      =========    =========

The following  table sets forth the defined benefit pension plan's change in the
fair value of plan assets for the plan years 1998 and 1997:

                                                         1998         1997
                                                      ---------    ---------
                                                      (THOUSANDS OF DOLLARS)
Fair value of pension plan assets
  at beginning of year ............................   $ 612,392    $ 533,444
Actual return on plan assets ......................      85,764       87,583
Employer contributions ............................      13,500       21,106
Benefit payments ..................................     (29,384)     (29,741)
                                                      ---------    ---------
Fair value of pension plan assets
  at end of year ..................................   $ 682,272    $ 612,392
                                                      =========    =========

We made the assumptions below to calculate the pension liability:

   Discount rate ..................................       7.00%        7.25%
   Rate of increase in compensation levels ........       3.50%        4.50%
   Expected long-term rate of return on assets.....      10.00%        9.00%


EMPLOYEE  SAVINGS PLAN BENEFITS We also sponsor a defined  contribution  savings
plan that is  offered  to nearly all APS  employees.  In a defined  contribution
plan, the benefits a participant is to receive result from regular contributions
to a participant  account.  Under this plan, we make matching  contributions  to
participant accounts. We recorded expenses for this plan of:

          +    $3.9 million in 1998
          +    $3.7 million in 1997 and
          +    $3.4 million in 1996.

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,

                                       51
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

retirees  do not make  contributions  to cover a portion of the plan  costs.  We
retain the right to change or eliminate these benefits.

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

          +    $8.7 million for 1998
          +    $9.4 million for 1997 and
          +    $15.8 million for 1996.

The following table shows the components of net periodic  postretirement benefit
costs  before  consideration  of  amounts  capitalized  or billed to others  and
excluding severance costs of $9.6 million in 1996:

                                                   1998       1997       1996
                                                 --------   --------   --------
                                                      (THOUSANDS OF DOLLARS)
Service cost -- benefits earned during
  the period..................................   $  7,676   $  6,865   $  7,974
Interest cost on accumulated benefit
  obligation .................................     15,610     14,315     13,395
Expected return on plan assets ...............    (12,001)    (8,706)    (6,696)
Amortization of:
    Transition obligation ....................      7,652      7,652      8,223
    Net actuarial gains ......................     (2,927)    (2,647)    (1,344)
                                                 --------   --------   --------
Net periodic postretirement benefit cost .....   $ 16,010   $ 17,479   $ 21,552
                                                 ========   ========   ========

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

                                                            1998         1997
                                                         ---------    ---------
                                                         (THOUSANDS OF DOLLARS)
Funded status -- postretirement plan assets less
  than accumulated benefit obligation ................   $ (21,912)   $ (46,435)
Unrecognized net obligation at transition ............     107,134      114,787
Unrecognized net actuarial gains .....................     (86,131)     (78,209)
                                                         ---------    ---------
Net postretirement amount recognized
  in the balance sheets ..............................   $    (909)   $  (9,857)
                                                         =========    =========

                                       52
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

The  following  table sets forth the  postretirement  benefit  plan's  change in
accumulated benefit obligation for the plan years 1998 and 1997:

                                                            1998         1997
                                                         ---------    ---------
                                                         (THOUSANDS OF DOLLARS)

Accumulated postretirement benefit obligation
  at beginning of year ...............................   $ 197,581    $ 179,550
Service cost .........................................       7,676        6,865
Interest cost ........................................      15,610       14,315
Benefit payments .....................................     (10,347)      (6,732)
Actuarial losses .....................................      24,802        3,583
                                                         ---------    ---------
Accumulated postretirement benefit obligation
  at end of year .....................................   $ 235,322    $ 197,581
                                                         =========    =========

The following table sets forth the  postretirement  benefit plan's change in the
fair value of plan assets for the plan years 1998 and 1997:

                                                            1998         1997
                                                         ---------    ---------
                                                         (THOUSANDS OF DOLLARS)
Fair value of postretirement plan assets
  at beginning of year ...............................   $ 151,146    $ 109,763
Actual return on plan assets .........................      47,284       30,846
Employer contributions ...............................      25,327       17,269
Benefit payments .....................................     (10,347)      (6,732)
                                                         ---------    ---------
Fair value of postretirement plan assets
  at end of year .....................................   $ 213,410    $ 151,146
                                                         =========    =========

We made the assumptions below to calculate the postretirement liability:

Discount rate ............................................     7.00%      7.25%
Expected long-term rate of return on assets - after tax ..     8.73%      7.75%
Initial health care cost trend rate - under age 65........     7.50%      8.00%
Initial health care cost trend rate - age 65 and over.....     6.50%      7.00%
Ultimate health care cost trend rate                          
  (reached in the year 2002) .............................     5.00%      5.00%
                                                           
Assuming a 1%  increase  in the health  care cost trend  rate,  the 1998 cost of
postretirement  benefits other than pensions would increase by  approximately $5
million and the  accumulated  benefit  obligation  as of December 31, 1998 would
increase by approximately $37 million.

Assuming a 1%  decrease  in the health  care cost trend  rate,  the 1998 cost of
postretirement  benefits other than pensions would decrease by  approximately $4
million and the  accumulated  benefit  obligations as of December 31, 1998 would
decrease by approximately $32 million.

                                       53
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

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  APS. The United States Supreme Court has refused to grant
review of the D.C.  Circuit's  decision.  In July 1998,  we filed a Petition for
Review regarding DOE's obligation to begin accepting spent nuclear fuel.

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 1998 dollars) over the life of Palo Verde for our share of the costs
related to the on-site interim storage of spent nuclear fuel. Beginning in 1999,
we will accrue these costs as a component of fuel  expense,  meaning the charges
will be accrued as the fuel is burned.  During 1998, we recorded a liability and
a regulatory asset of $35 million for on-site interim nuclear fuel storage costs
related to nuclear  fuel burned prior to 1999.  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 1999  through  2020 that
include required purchase provisions. We estimate our 1999 contract requirements
to be about $132 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.

                                       54
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

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 $62  million at  December  31,  1998 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  1996  regulatory   agreement  (see  Note  3),  the  ACC  began  accelerated
amortization  of our regulatory  asset for coal mine  reclamation  costs 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, 1998 was about $51 million.

CONSTRUCTION  PROGRAM Total capital  expenditures  in 1999 are estimated at $328
million.

13. NUCLEAR DECOMMISSIONING COSTS

We recorded $11.4 million for decommissioning expense in each of the years 1998,
1997,  and 1996.  We estimate it will cost about $1.8 billion  ($452  million in
1998 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 $145.6  million at December 31,
1998 and  $124.6  million  at  December  31,  1997.  We invest  the trust  funds
primarily in  fixed-income  securities  and domestic  stock and classify them as
available for sale.  Realized and  unrealized  gains and losses are reflected in
accumulated depreciation.

In 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 has indicated  that a revised  exposure  draft
will be issued in 1999.

                                       55
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

14. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Quarterly financial information for 1998 and 1997 is as follows:


                               ELECTRIC                             EARNINGS
                               OPERATING   OPERATING      NET          FOR
QUARTER ENDED                  REVENUES    INCOME(a)    INCOME    COMMON STOCK
-------------                  ---------   ---------    ------    ------------
                                          (THOUSANDS OF DOLLARS)
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
1997
   March 31                    $379,021     $61,439     $28,645      $25,019
   June 30                      458,751      99,706      69,493       66,298
   September 30                 632,821     150,892     129,699      126,715
   December 31                  407,960      59,788      23,656       20,658

----------

(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.

                                       56
<PAGE>
                                       APS
                          NOTES TO FINANCIAL STATEMENTS

15. STOCK OPTIONS

Our parent  company,  Pinnacle West Capital  Corporation,  offers  several stock
incentive  plans  for our  officers,  our  parent  company's  officers,  and key
employees.

The plans provide for the granting of new options or awards of up to 3.5 million
shares at a price per  option  not less than fair  market  value on the date the
option is granted. The plans also provide for the granting of any combination of
stock appreciation rights or dividend equivalents.  The awards outstanding under
the  various  incentive  plans  at  December  31,  1998  approximate   1,497,012
non-qualified  stock  options,   158,121  restricted  shares,  and  no  dividend
equivalent shares, incentive stock options, or stock appreciation rights.

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,  "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:

                                             1998          1997          1996
                                           --------      --------      --------
                                                  (THOUSANDS OF DOLLARS)
Net income
   As reported.......................      $255,247      $251,493      $243,471
   Pro forma (fair value method).....      $254,640      $251,142      $243,291

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:

                                              1998          1997          1996
                                             ------        ------       -------
Risk-free interest rate.............          4.54%         5.66%         5.77%
Dividend growth.....................          3.03%         4.50%         4.50%
Volatility..........................         18.80%        15.63%        17.10%
Expected life (months)..............             60            60            58

                                       57
<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.

                                       58
<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 on page 28.

EXHIBITS FILED

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

10.1(a)   --    1999 Management Variable Incentive Plan

10.2(a)   --    1999 Senior Management Variable Incentive Plan

10.3(a)   --    1999 Officers Variable Incentive Plan

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

  3.4          Certificates pursuant to           4.3 to Form S-3               1-4473         9-29-93
               Sections 10-152.01 and             Registration Nos.
               10-016, Arizona Revised            33-33910 and 33-55248 by
               Statutes, establishing Series A    means of September 24,
               through V of the Company's         1993 Form 8-K Report
               Serial Preferred Stock
</TABLE>

                                       59
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  3.5          Certificate pursuant to            4.4 to Form S-3               1-4473         9-29-93
               Section 10-016, Arizona            Registration Nos.
               Revised Statutes, establishing     33-33910 and 33-55248 by
               Series W of the Company's          means of September 24,
               Serial Preferred Stock             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

  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
</TABLE>

                                       60
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  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

  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

</TABLE>

                                       61
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  4.18         Agreement of Resignation,          4.1 to September 25, 1995     1-4473         10-24-95
               Appointment, Acceptance and        Form 8-K Report
               Assignment dated as of
               August 18, 1995 by and
               among the Company, Bank of
               America National Trust and
               Savings Association and The
               Bank of New York

  10.4         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

  10.5         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

  10.6         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

  10.7         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

  10.8         Amendment No. 2 to                 10.6 to 1996 Form 10-K        1-4473         3-28-97
               Decommissioning Trust              Report
               Agreement (PVNGS Unit 3)
               dated as of July 1, 1991
</TABLE>

                                       62
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.9         Amended and Restated               10.1 to Pinnacle West         1-8962         3-26-92
               Decommissioning Trust              1991 Form 10-K Report
               Agreement (PVNGS Unit 2)
               dated as of January 31, 1992,
               among the Company, Mellon
               Bank, N.A., as
               Decommissioning Trustee, and
               State Street Bank and Trust
               Company, as successor to The
               First National Bank of
               Boston, as Owner Trustee
               under two separate Trust
               Agreements, each with a
               separate Equity Participant,
               and as Lessor under two
               separate Facility Leases, each
               relating to an undivided
               interest in PVNGS Unit 2

  10.10        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

  10.11        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

  10.12        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

  10.13        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

  10.14        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
</TABLE>

                                       63
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.15        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

  10.16        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

  10.17        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

  10.18        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

  10.19        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

  10.20        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

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

  10.22        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
</TABLE>

                                       64
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.23        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

  10.24        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

  10.25        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

  10.26        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

  10.27        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

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

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

  10.30        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
</TABLE>

                                       65
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.31        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

  10.32        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

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

                                       66
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.34(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

  10.35(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

  10.36(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

  10.37        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

  10.38        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
</TABLE>

                                       67
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.39        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

  10.40(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

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

  10.42(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

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

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

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

                                       68
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.46(a)     Fifth Amendment to the             10.3 to 1997 Form 10-K        1-4473         3-28-97
               Arizona Public Service             Report
               Company Deferred
               Compensation Plan

  10.47(a)     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

  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              10.7 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

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

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

  10.52(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

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

                                       69
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.54(a)     Letter Agreement, dated April      10.7 to 1988 Form 10-K        1-4473         3-8-89
               3, 1978, between the Company       Report
               and O. Mark DeMichele,
               regarding certain retirement
               benefits granted to Mr.
               DeMichele

  10.55(a)     Letter Agreement dated             10.9 to 1996 Form 10-K        1-4473         3-28-97
               November 27, 1996 between          Report
               the Company and
               George A. Schreiber, Jr.

  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)(d)  Key Executive Employment           10.3 to 1989 Form 10-K        1-4473         3-8-90
               and Severance Agreement            Report
               between the Company and
               certain executive officers of
               the Company

  10.58(a)(d)  Revised form of Key Executive      10.5 to 1993 Form 10-K        1-4473         3-30-94
               Employment and Severance           Report
               Agreement between the
               Company and certain
               executive officers of the
               Company

  10.59(a)(d)  Second revised form of Key         10.9 to 1994 Form 10-K        1-4473         3-30-95
               Executive Employment and           Report
               Severance Agreement between
               the Company and certain
               executive officers of the
               Company

  10.60(a)(d)  Key Executive Employment           10.4 to 1989 Form 10-K        1-4473         3-8-90
               and Severance Agreement            Report
               between the Company and
               certain managers of the
               Company
</TABLE>

                                       70
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.61(a)(d)  Revised form of Key Executive      10.4 to 1993 Form 10-K        1-4473         3-30-94
               Employment and Severance           Report
               Agreement between the
               Company and certain key
               employees of the Company

  10.62(a)(d)  Second revised form of Key         10.8 to 1994 Form 10-K        1-4473         3-30-95
               Executive Employment and           Report
               Severance Agreement between
               the Company and certain key
               employees of the Company

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

  10.66        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

  10.67        Territorial Agreement              10.1 to March 1998            1-4473         5-15-98
               between the Company                Form 10-Q Report
               and Salt River Project
</TABLE>

                                       71
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  10.68        Power Coordination                 10.2 to March 1998            1-4473         5-15-98
               Agreement between                  Form 10-Q Report
               the Company and Salt
               River Project

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

  10.70        Addendum to Memorandum of          10.2 to May 19, 1998          1-4473         6-26-98
               Agreement between the              Form 8-K Report
               Company and Salt River
               Project dated as of May
               19, 1998

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

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

  99.3(c)      Participation Agreement,           28.1 to September 1992        1-4473         11-9-92
               dated as of August 1, 1986,        Form 10-Q Report
               among PVNGS Funding
               Corp., Inc., Bank of America
               National Trust and Savings
               Association, State Street Bank
               and Trust Company, as
               successor to The First
               National Bank of Boston, in
               its individual capacity and as
               Owner Trustee, Chemical
               Bank, in its individual
               capacity and as Indenture
               Trustee, the Company, and
               the Equity Participant named
               therein
</TABLE>

                                       72
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  99.4(c)      Amendment No. 1 dated as 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

  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
</TABLE>

                                       73
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  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

  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
</TABLE>

                                       74
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  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

  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
</TABLE>

                                       75
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  99.14        Amendment No. 2, dated 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

  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
</TABLE>

                                       76
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  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

  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
</TABLE>

                                       77
<PAGE>
<TABLE>
<CAPTION>
Exhibit No.    Description                        Originally Filed as Exhibit:  File No.(b)    Date Effective
-----------    -----------                        ----------------------------  -----------    --------------
<S>            <C>                                <C>                           <C>            <C>
  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>

                                       78
<PAGE>

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

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

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

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

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

REPORTS ON FORM 8-K

     During the quarter  ended  December 31, 1998 and the period ended March 30,
1999, the Company filed the following Report on Form 8-K:

     Report dated  December 1, 1998 relating to an order by the Arizona  Supreme
Court  staying ACC hearings  regarding  our  settlement  agreement  with the ACC
Staff.

     Report dated  December 9, 1998  relating to (1) a Notice of  Withdrawal  of
Settlement  filed by the ACC Staff,  (2) terms of  expiration of a memorandum of
understanding,  (3) ACC adoption of the amended rules,  and (4) issues affecting
the agreement with Salt River Project.

     Report  dated  January 11, 1999  relating to (i) the ACC hearing  officers'
recommended  changes to the amended rules  regarding the  introduction of retail
electric  competition  in Arizona and to the June 1998  stranded  cost order and
(ii) action by the Arizona Supreme Court vacating its order staying ACC hearings
on the proposed  settlement  agreement  and  dismissing  the Attorney  General's
action.

     Report  dated  February  18, 1999  comprised  of Exhibits to the  Company's
Registration Statements  (Registration Nos. 333-27551 and 333-58445) relating to
the Company's offering of $125 million of Notes.

                                       79
<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  30, 1999                             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.
<TABLE>
<CAPTION>
                SIGNATURE                                  TITLE                    DATE
                ---------                                  -----                    ----
<S>                                            <C>                             <C>

             WILLIAM J. POST                    Principal Executive Officer    March 30, 1999
-----------------------------------------              and Director
(William J. Post, Chief Executive Officer)


         GEORGE A SCHREIBER, JR.               Principal Accounting Officer,   March 30, 1999
-----------------------------------------       Principal Financial Officer
       (George A. Schreiber, Jr.)                     and Director


              JACK E. DAVIS                       President and Director       March 30, 1999
-----------------------------------------
             (Jack E. Davis)


            O. MARK DEMICHELE                            Director              March 30, 1999
-----------------------------------------
           (O. Mark DeMichele)


          MICHAEL L. GALLAGHER                           Director              March 30, 1999
-----------------------------------------
         (Michael L. Gallagher)


             MARTHA O. HESSE                             Director              March 30, 1999
-----------------------------------------
            (Martha O. Hesse)


          MARIANNE M. JENNINGS                           Director              March 30, 1999
-----------------------------------------
         (Marianne M. Jennings)


            ROBERT E. KEEVER                             Director              March 30, 1999
-----------------------------------------
           (Robert E. Keever)
</TABLE>
                                       80
<PAGE>
<TABLE>
<S>                                               <C>                          <C>
            ROBERT G. MATLOCK                            Director              March 30, 1999
-----------------------------------------
           (Robert G. Matlock)


           BRUCE J. NORDSTROM                            Director              March 30, 1999
-----------------------------------------
          (Bruce J. Nordstrom)


           JOHN R. NORTON III                            Director              March 30, 1999
-----------------------------------------
          (John R. Norton III)


             DONALD M. RILEY                             Director              March 30, 1999
-----------------------------------------
            (Donald M. Riley)


          QUENTIN P. SMITH, JR.                          Director              March 30, 1999
-----------------------------------------
         (Quentin P. Smith, Jr.)


           WILLIAM L. STEWART                     President and Director       March 30, 1999
-----------------------------------------
          (William L. Stewart)


              RICHARD SNELL                              Director              March 30, 1999
-----------------------------------------
             (Richard Snell)


            DIANNE C. WALKER                             Director              March 30, 1999
-----------------------------------------
           (Dianne C. Walker)


           BEN F. WILLIAMS JR.                           Director              March 30, 1999
-----------------------------------------
         (Ben F. Williams, Jr.)
</TABLE>

                                       81
<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, 1998

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

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












--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>
                                INDEX TO EXHIBITS



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

10.1a     ___    1999 Management Variable Incentive Plan

10.2a     ___    1999 Senior Management Variable Incentive Plan

10.3a     ___    1999 Officers Variable Incentive Plan

23.1      ___    Consent of Deloitte & Touche LLP

27.1      ___    Financial Data Schedule

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

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

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