<SUBMISSION>
<ACCESSION-NUMBER>0000950147-03-000623
<TYPE>10-Q
<PUBLIC-DOCUMENT-COUNT>9
<PERIOD>20030331
<FILING-DATE>20030515
<FILER>
<COMPANY-DATA>
<CONFORMED-NAME>PINNACLE WEST CAPITAL CORP
<CIK>0000764622
<ASSIGNED-SIC>4911
<IRS-NUMBER>860512431
<STATE-OF-INCORPORATION>AZ
<FISCAL-YEAR-END>1231
</COMPANY-DATA>
<FILING-VALUES>
<FORM-TYPE>10-Q
<ACT>34
<FILE-NUMBER>001-08962
<FILM-NUMBER>03700776
</FILING-VALUES>
<BUSINESS-ADDRESS>
<STREET1>400 NORTH FIFTH STREET
<STREET2>.
<CITY>PHOENIX
<STATE>AZ
<ZIP>85004
<PHONE>6023792500
</BUSINESS-ADDRESS>
<MAIL-ADDRESS>
<STREET1>400 NORTH FIFTH STREET
<STREET2>.
<CITY>PHOENIX
<STATE>AZ
<ZIP>85004
</MAIL-ADDRESS>
<FORMER-COMPANY>
<FORMER-CONFORMED-NAME>AZP GROUP INC
<DATE-CHANGED>19870506
</FORMER-COMPANY>
</FILER>
<DOCUMENT>
<TYPE>10-Q
<SEQUENCE>1
<FILENAME>e-9897.txt
<DESCRIPTION>QUARTERLY REPORT FOR THE QTR ENDED 3/31/2003
<TEXT>
                       Securities and Exchange Commission
                             Washington, D.C. 20549

                                    FORM 10-Q

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

     For the quarterly period ended March 31, 2003

                                       OR

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

     For the transition period from ____________________ to ____________________

                          Commission file number 1-8962

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


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


400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona         85072-3999
       (Address of principal executive offices)                  (Zip Code)


       Registrant's telephone number, including area code: (602) 250-1000


              (Former name, former address and former fiscal year,
                          if changed since last report)

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 whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).

                                 Yes [X] No [ ]

Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.

               Number of shares of common stock, no par value,
               outstanding as of May 9, 2003: 91,254,179
<PAGE>
                                    Glossary

ACC - Arizona Corporation Commission

ACC Staff - Staff of the Arizona Corporation Commission

ADEQ - Arizona Department of Environmental Quality

ALJ - Administrative Law Judge

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

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

CC&N - Certificate of Convenience and Necessity

Citizens - Citizens Communications Company

Company - Pinnacle West Capital Corporation

CPUC - California Public Utility Commission

EITF - the FASB's Emerging Issues Task Force

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

ERMC -Energy Risk Management Committee

FASB - Financial Accounting Standards Board

FERC - United States Federal Energy Regulatory Commission

FIN - FASB Interpretation

Financing Order - ACC order issued on April 4, 2003 relating to APS' request to
    provide financing or credit support to Pinnacle West Energy or the Company

Fitch - Fitch, Inc.

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

Interim Financing Order - Order issued by the ACC on November 22, 2002 relating
    to APS' request to provide financing or credit support to the Company

IRS - United States Internal Revenue Service

ISO - California Independent System Operator

Moody's - Moody's Investors Service

MW - megawatt, one million watts

MWh - megawatt-hours, one million watts per hour

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

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

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

NRC - United States Nuclear Regulatory Commission

OCI - other comprehensive income

Palo Verde - Palo Verde Nuclear Generating Station

PG&E - PG&E Corp.

Pinnacle West - Pinnacle West Capital Corporation, the Company

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

PX - California Power Exchange

Rules - ACC retail electric competition rules
<PAGE>
SCE - Southern California Edison Company

SEC - United States Securities and Exchange Commission

SFAS - Statement of Financial Accounting Standards

SNWA - Southern Nevada Water Authority

SPE - special-purpose entity

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

SunCor - SunCor Development Company, a subsidiary of the Company

System - non-trading energy related activities

T&D - transmission and distribution

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

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

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

2002 10-K - the Company's Annual Report on Form 10-K for the fiscal year ended
    December 31, 2002

VIE - variable interest entity

                                        2
<PAGE>
                          PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

                        PINNACLE WEST CAPITAL CORPORATION
                   CONDENSED CONSOLIDATED STATEMENTS OF INCOME
                                   (unaudited)
                    (in thousands, except per share amounts)

<TABLE>
<CAPTION>
                                                                Three Months Ended
                                                                     March 31,
                                                             -------------------------
                                                                2003           2002
                                                             ----------     ----------
<S>                                                          <C>            <C>
Operating Revenues
  Regulated electricity segment                              $  384,960     $  380,241
  Marketing and trading segment                                 162,743         75,815
  Real estate segment                                            40,688         39,511
  Other revenues                                                 15,571          4,277
                                                             ----------     ----------
    Total                                                       603,962        499,844
                                                             ----------     ----------

Operating Expenses
  Regulated electricity segment purchased power and fuel         74,671         61,531
  Marketing and trading segment purchased power and fuel        143,645         35,785
  Operations and maintenance                                    133,117        117,430
  Real estate operations segment                                 40,159         36,646
  Depreciation and amortization                                 105,398         99,656
  Taxes other than income taxes                                  28,496         26,758
  Other expenses                                                  9,221          3,302
                                                             ----------     ----------
    Total                                                       534,707        381,108
                                                             ----------     ----------
Operating Income                                                 69,255        118,736
                                                             ----------     ----------
Other
  Other income (Note 16)                                          5,721          5,161
  Other expense (Note 16)                                        (4,197)        (5,089)
                                                             ----------     ----------
    Total                                                         1,524             72
                                                             ----------     ----------
Interest Expense
  Interest charges                                               47,851         44,519
  Capitalized interest                                           (9,979)       (13,859)
                                                             ----------     ----------
    Total                                                        37,872         30,660
                                                             ----------     ----------
Income From Continuing Operations Before Income Taxes            32,907         88,148
Income Taxes                                                     12,754         34,897
                                                             ----------     ----------
Income From Continuing Operations                                20,153         53,251
Income From Discontinued Operations
 - Net of Income Tax Expense of $3,375 and $332                   5,145            506
                                                             ----------     ----------
Net Income                                                   $   25,298     $   53,757
                                                             ==========     ==========

Weighted-Average Common Shares Outstanding - Basic               91,256         84,735

Weighted-Average Common Shares Outstanding - Diluted             91,359         84,884

Earnings Per Weighted-Average Common Share Outstanding
  Income From Continuing Operations - Basic                  $     0.22     $     0.63
  Net Income - Basic                                               0.28           0.63
  Income From Continuing Operations - Diluted                      0.22           0.63
  Net Income - Diluted                                             0.28           0.63

Dividends Declared Per Share                                 $    0.425     $     0.40
</TABLE>

See Notes to Condensed Consolidated Financial Statements.

                                        3
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   CONDENSED CONSOLIDATED STATEMENTS OF INCOME
                                   (unaudited)
                    (in thousands, except per share amounts)

<TABLE>
<CAPTION>
                                                                          Twelve Months Ended
                                                                               March 31,
                                                                     ----------------------------
                                                                         2003            2002
                                                                     ------------    ------------
<S>                                                                  <C>             <C>
Operating Revenues
  Regulated electricity segment                                      $  2,017,742    $  2,529,522
  Marketing and trading segment                                           412,859         468,750
  Real estate segment                                                     202,258         176,084
  Other revenues                                                           73,231          14,505
                                                                     ------------    ------------
    Total                                                               2,706,090       3,188,861
                                                                     ------------    ------------

Operating Expenses
  Regulated electricity segment purchased power and fuel                  512,683       1,092,767
  Marketing and trading segment purchased power and fuel                  301,899         218,588
  Operations and maintenance                                              600,225         522,275
  Real estate operations segment                                          189,438         159,100
  Depreciation and amortization                                           429,824         422,778
  Taxes other than income taxes                                           109,690         102,523
  Other expenses                                                          110,878          12,717
                                                                     ------------    ------------
    Total                                                               2,254,637       2,530,748
                                                                     ------------    ------------
Operating Income                                                          451,453         658,113
                                                                     ------------    ------------
Other
  Other income (Note 16)                                                   16,226          27,096
  Other expense (Note 16)                                                 (33,519)        (32,864)
                                                                     ------------    ------------
    Total                                                                 (17,293)         (5,768)
                                                                     ------------    ------------
Interest Expense
  Interest charges                                                        190,844         177,592
  Capitalized interest                                                    (39,869)        (51,294)
                                                                     ------------    ------------
    Total                                                                 150,975         126,298
                                                                     ------------    ------------
Income From Continuing Operations Before Income Taxes                     283,185         526,047
Income Taxes                                                              110,085         207,634
                                                                     ------------    ------------
Income From Continuing Operations                                         173,100         318,413
Income From Discontinued Operations
 - Net of Income Tax Expense of $8,916 and $332                            13,594             506
Cumulative Effect of a Change in Accounting for Derivatives
 - Net of Income Tax Benefit of $8,099                                         --         (12,446)
Cumulative Effect of a Change in Accounting for Trading Activities
 - Net of Income Tax Benefit of $43,123                                   (65,745)             --
                                                                     ------------    ------------
Net Income                                                           $    120,949    $    306,473
                                                                     ============    ============

Weighted-Average Common Shares Outstanding - Basic                         86,509          84,719

Weighted-Average Common Shares Outstanding - Diluted                       86,627          84,910

Earnings Per Weighted-Average Common Share Outstanding
  Income From Continuing Operations - Basic                          $       2.00    $       3.76
  Net Income - Basic                                                         1.40            3.62
  Income From Continuing Operations - Diluted                                2.00            3.75
  Net Income - Diluted                                                       1.40            3.61

Dividends Declared Per Share                                         $       1.65    $       1.55
</TABLE>

See Notes to Condensed Consolidated Financial Statements.

                                        4
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                      CONDENSED CONSOLIDATED BALANCE SHEETS
                             (dollars in thousands)
                                   (unaudited)
                                     ASSETS

                                                         March 31,  December 31,
                                                           2003         2002
                                                        ----------   ----------
Current Assets
  Cash and cash equivalents                             $   67,289   $   77,566
  Trust fund for bond redemption                            87,225           --
  Customer and other receivables--net                      340,156      373,196
  Accrued utility revenues                                  57,306       72,915
  Materials and supplies (at average cost)                  91,106       91,652
  Fossil fuel (at average cost)                             32,922       28,185
  Deferred income taxes                                      4,094        4,094
  Assets from risk management and trading activities       106,348       59,162
  Real estate assets held for sale                              --       46,475
  Other current assets                                      89,428      103,978
                                                        ----------   ----------
     Total current assets                                  875,874      857,223
                                                        ----------   ----------

Investments and Other Assets
  Real estate investments--net                             386,983      382,719
  Assets from risk management and trading activities -
    long-term                                              100,209      122,336
  Other assets                                             227,882      229,891
                                                        ----------   ----------
     Total investments and other assets                    715,074      734,946
                                                        ----------   ----------

Property, Plant and Equipment
  Plant in service and held for future use               9,179,261    9,058,900
  Less accumulated depreciation and amortization         3,344,900    3,474,325
                                                        ----------   ----------
     Total                                               5,834,361    5,584,575
  Construction work in progress                            860,190      777,542
  Intangible assets, net of accumulated amortization       122,721      109,815
  Nuclear fuel, net of accumulated amortization             12,232        7,466
                                                        ----------   ----------
     Net property, plant and equipment                   6,829,504    6,479,398
                                                        ----------   ----------

Deferred Debits
  Regulatory assets                                        219,344      241,045
  Other deferred debits                                    115,125      113,194
                                                        ----------   ----------
     Total deferred debits                                 334,469      354,239
                                                        ----------   ----------

Total Assets                                            $8,754,921   $8,425,806
                                                        ==========   ==========

See Notes to Condensed Consolidated Financial Statements.

                                        5
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                      CONDENSED CONSOLIDATED BALANCE SHEETS
                             (dollars in thousands)
                                   (unaudited)
                             LIABILITIES AND EQUITY

<TABLE>
<CAPTION>
                                                               March 31,      December 31,
                                                                  2003            2002
                                                              ------------    ------------
<S>                                                           <C>             <C>
Current Liabilities
  Accounts payable                                            $    300,849    $    354,218
  Accrued taxes                                                    108,016          71,107
  Accrued interest                                                  42,763          53,018
  Short-term borrowings                                            207,667         102,183
  Current maturities of long-term debt                             485,794         280,888
  Customer deposits                                                 45,893          42,190
  Real estate liabilities held for sale                                 --          29,451
  Liabilities from risk management and trading activities           93,074          70,667
  Other current liabilities                                         77,626          63,847
                                                              ------------    ------------
     Total current liabilities                                   1,361,682       1,067,569
                                                              ------------    ------------

Long-Term Debt Less Current Maturities                           2,644,449       2,869,241
                                                              ------------    ------------

Deferred Credits and Other
  Liabilities from risk management and trading activities -
    long-term                                                       52,143          75,642
  Deferred income taxes                                          1,209,950       1,209,074
  Unamortized gain - sale of utility plant                          58,340          59,484
  Pension liability                                                199,456         183,880
  Liability for asset retirement (Note 13)                         223,147              --
  Other                                                            320,048         274,763
                                                              ------------    ------------
     Total deferred credits and other                            2,063,084       1,802,843
                                                              ------------    ------------

Commitments and Contingencies (Note 12)

Common Stock Equity
  Common stock, no par value                                     1,738,689       1,737,258
  Treasury stock                                                    (4,236)         (4,358)
                                                              ------------    ------------
  Total common stock                                             1,734,453       1,732,900
                                                              ------------    ------------
  Accumulated other comprehensive loss:
    Minimum pension liability adjustment                           (71,233)        (71,264)
    Derivative instruments                                          (8,565)        (20,020)
                                                              ------------    ------------
  Total accumulated other comprehensive loss                       (79,798)        (91,284)
                                                              ------------    ------------
  Retained earnings                                              1,031,051       1,044,537
                                                              ------------    ------------
     Total common stock equity                                   2,685,706       2,686,153
                                                              ------------    ------------

Total Liabilities and Equity                                  $  8,754,921    $  8,425,806
                                                              ============    ============
</TABLE>

See Notes to Condensed Consolidated Financial Statements.

                                        6
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (unaudited)
                             (dollars in thousands)

<TABLE>
<CAPTION>
                                                                 Three Months Ended
                                                                      March 31,
                                                              ------------------------
                                                                 2003          2002
                                                              ----------    ----------
<S>                                                           <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations                             $   20,153    $   53,251
  Items not requiring cash:
    Depreciation and amortization                                105,398        99,656
    Nuclear fuel amortization                                      7,726         7,484
    Deferred income taxes                                         (9,675)      (10,434)
    Change in mark-to-market                                      (6,008)       (3,090)
  Changes in current assets and liabilities:
    Customer and other receivables                                33,040        53,815
    Accrued utility revenues                                      15,609        12,423
    Materials, supplies and fossil fuel                           (4,191)          476
    Other current assets                                          16,234        (2,937)
    Accounts payable                                             (55,049)     (117,731)
    Accrued taxes                                                 36,909        41,735
    Accrued interest                                             (10,255)       (6,448)
    Other current liabilities                                     17,482        24,872
  Change in real estate investments                               (4,277)       (7,841)
  Increase in regulatory assets                                   (2,152)       (2,096)
  Change in risk management and trading - assets                  11,334        (8,862)
  Change in risk management and trading - liabilities            (12,370)        6,229
  Change in customer advances                                     (1,334)      (24,767)
  Change in pension liability                                     15,576         7,521
  Change in other long-term assets                                 6,278        (9,710)
  Change in other long-term liabilities                            1,006        22,275
                                                              ----------    ----------
Net cash flow provided by operating activities                   181,434       135,821
                                                              ----------    ----------

CASH FLOWS FROM INVESTING ACTIVITIES
  Capital expenditures                                          (174,324)     (219,923)
  Trust fund for bond redemption                                 (87,225)     (121,668)
  Proceeds from sale of assets from discontinued operations       25,150            --
  Capitalized interest                                            (9,979)      (13,859)
  Other                                                            8,238        26,706
                                                              ----------    ----------
Net cash flow used for investing activities                     (238,140)     (328,744)
                                                              ----------    ----------

CASH FLOWS FROM FINANCING ACTIVITIES
  Issuance of long-term debt                                      18,500       603,430
  Short-term borrowings and payments--net                        105,484      (253,462)
  Dividends paid on common stock                                 (38,783)      (33,888)
  Repayment of long-term debt                                    (40,325)     (133,749)
  Other                                                            1,553         2,416
                                                              ----------    ----------
Net cash flow provided by financing activities                    46,429       184,747
                                                              ----------    ----------
Net Cash Flow                                                    (10,277)       (8,176)
Cash and Cash Equivalents at Beginning of Period                  77,566        28,619
                                                              ----------    ----------
Cash and Cash Equivalents at End of Period                    $   67,289    $   20,443
                                                              ==========    ==========

Supplemental disclosure of cash flow information:
  Cash paid during the period for:
    Interest paid, net of amounts capitalized                 $   46,439    $   35,212
    Income taxes paid                                         $       --    $   30,557
</TABLE>

See Notes to Condensed Consolidated Financial Statements.

                                        7
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION

              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.   The condensed consolidated financial statements include the accounts of
Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy
Services, SunCor and El Dorado (principally NAC). All significant intercompany
accounts and transactions between the consolidated companies have been
eliminated. We have reclassified certain prior year amounts to conform to the
current year presentation (see Notes 10 and 19.)

2.   Our unaudited condensed consolidated financial statements reflect all
adjustments which we believe are necessary for the fair presentation of our
financial position and results of operations for the periods presented. These
adjustments are of a normal recurring nature with the exception of the
cumulative effect of a change in accounting for derivatives, the cumulative
effect of a change in accounting for trading activities (see Note 10), asset
retirement obligations (see Note 13) and real estate discontinued operations
(see Note 19). We suggest that these condensed consolidated financial statements
and notes to condensed consolidated financial statements be read along with the
consolidated financial statements and notes to consolidated financial statements
included in our 2002 10-K.

3.   Weather conditions cause significant seasonal fluctuations in our revenues.
In addition, trading and wholesale marketing activities can have significant
impacts on our results for interim periods. Consequently, results for interim
periods do not necessarily represent results to be expected for the year.

4.   In March 2003, APS deposited monies with its first mortgage bond trustee to
redeem the entire $33 million of outstanding First Mortgage Bonds, 8% Series due
2025, and the entire $54 million of outstanding First Mortgage Bonds, 7.25%
Series due 2023. On April 7, 2003, APS redeemed $33 million of its First
Mortgage Bonds, 8% Series due 2025. APS will redeem $54 million of its First
Mortgage Bonds, 7.25% Series due 2023, on August 1, 2003.

     On May 12, 2003, APS issued $500 million of debt as follows: $300 million
aggregate principal amount of its 4.650% Notes due 2015 and $200 million
aggregate principal amount of its 5.625% Notes due 2033. Also on May 12, 2003,
APS made a $500 million loan to Pinnacle West Energy, and Pinnacle West Energy
distributed the net proceeds of that loan to us to fund our repayment of a
portion of the debt incurred to finance the construction of the following
Pinnacle West Energy power plants: Redhawk Units 1 and 2, West Phoenix Units 4
and 5, and Saguaro Unit 3. See "ACC Financing Orders" in Note 5 for additional
information. With Pinnacle West Energy's distribution to us, on May 12, 2003, we
repaid the outstanding balance ($167 million) under a credit facility. We used a
portion of the remaining proceeds to repay our short-term debt, with the balance
being temporarily invested pending the planned optional repayment of our $250
million Floating Rate Notes due 2003.

                                       8
<PAGE>
5.   Regulatory Matters

ELECTRIC INDUSTRY RESTRUCTURING

STATE

     OVERVIEW

     On September 10, 2002, the ACC issued the Track A Order, which, among other
things, directed APS not to transfer its generation assets to Pinnacle West
Energy, as previously required under the Rules and the 1999 Settlement
Agreement. See "Track A Order" below. The Track A Order and legal challenges to
the Rules have raised considerable uncertainty about the status and pace of
retail electric competition in Arizona.

     On March 14, 2003, the ACC issued the Track B Order, which requires APS to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. See "Track B Order" below.

     On April 4, 2003, the ACC issued the Financing Order authorizing APS to
lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of
Pinnacle West Energy debt, or a combination of both, not to exceed $500 million
in the aggregate. See "ACC Financing Orders" below. On May 12, 2003, APS issued
$500 million of debt pursuant to the Financing Order and made a $500 million
loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds
of that loan to us to fund the repayment of certain of our debt. See Note 4.

     As required by the 1999 Settlement Agreement, on or before June 30, 2003,
APS will file a general rate case with the ACC. The general rate case will also
address the implementation of retail rate adjustment mechanisms that were the
subject of ACC hearings in April 2003. See "APS General Rate Case and Retail
Rate Adjustment Mechanisms" below.

     1999 SETTLEMENT AGREEMENT

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

     o    APS has reduced, and will reduce, rates for standard-offer service for
          customers with loads less than three MW in a series of annual retail
          electricity price reductions of 1.5% on July 1 for each of the years
          1999 to 2003 for a total of 7.5%. Based on the price reductions
          authorized in the 1999 Settlement Agreement, there were retail price
          decreases of approximately $24 million ($14 million after taxes),
          effective July 1, 1999; approximately $28 million ($17 million after
          taxes), effective July 1, 2000; approximately $27 million ($16 million
          after taxes), effective July 1, 2001; and approximately $28 million
          ($17 million after taxes), effective July 1, 2002. The final price
          reduction is to be implemented July 1, 2003. For customers having
          loads of three MW or greater, standard-offer rates have been reduced
          in varying annual increments that total 5% in the years 1999 through
          2002.

                                       9
<PAGE>
     o    Unbundled rates being charged by APS for competitive direct access
          service (for example, distribution services) became effective upon
          approval of the 1999 Settlement Agreement, retroactive to July 1,
          1999, and also became subject to annual reductions beginning January
          1, 2000, that vary by rate class, through January 1, 2004.

     o    There will be a moratorium on retail price changes for standard-offer
          and unbundled competitive direct access services until July 1, 2004,
          except for the price reductions described above and certain other
          limited circumstances. Neither the ACC nor APS will be prevented from
          seeking or authorizing rate changes prior to July 1, 2004 in the event
          of conditions or circumstances that constitute an emergency, such as
          an inability to finance on reasonable terms; material changes in APS'
          cost of service for ACC-regulated services resulting from federal,
          tribal, state or local laws; regulatory requirements; or judicial
          decisions, actions or orders.

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

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

     o    Prior to the 1999 Settlement Agreement, APS was recovering
          substantially all of its regulatory assets through July 1, 2004,
          pursuant to a 1996 regulatory agreement. In addition, the 1999
          Settlement Agreement states that APS has demonstrated that its
          allowable stranded costs, after mitigation and exclusive of regulatory
          assets, are at least $533 million net present value (in 1999 dollars).
          APS will not be allowed to recover $183 million net present value (in
          1999 dollars) of the above amounts. The 1999 Settlement Agreement
          provides that APS will have the opportunity to recover $350 million
          net present value (in 1999 dollars) through a competitive transition
          charge that will remain in effect through December 31, 2004, at which

                                       10
<PAGE>
          time it will terminate. The costs subject to recovery under the
          adjustment clause described above will be decreased or increased by
          any over/under-recovery due to sales volume variances.

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

     RETAIL ELECTRIC COMPETITION RULES

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

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

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

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

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

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

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

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

                                       11
<PAGE>
     On November 27, 2000, a Maricopa County, Arizona, Superior Court judge
issued a final judgment holding that the Rules are unconstitutional and unlawful
in their entirety due to failure to establish a fair value rate base for
competitive electric service providers and because certain of the Rules were not
submitted to the Arizona Attorney General for certification. The judgment also
invalidates all ACC orders authorizing competitive electric service providers,
including APS Energy Services, to operate in Arizona. We do not believe the
ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was
not at issue in the consolidated cases before the judge. Further, the ACC made
findings related to the fair value of APS' property in the order approving the
1999 Settlement Agreement. The ACC and other parties aligned with the ACC have
appealed the ruling to the Arizona Court of Appeals, as a result of which the
Superior Court's ruling is automatically stayed pending further judicial review.
That appeal is still pending. In a similar appeal concerning the issuance of
competitive telecommunications CC&N's, the Arizona Court of Appeals invalidated
rates for competitive carriers due to the ACC's failure to establish a fair
value rate base for such carriers. That decision was upheld by the Arizona
Supreme Court.

     PROVIDER OF LAST RESORT OBLIGATION

     Although the Rules allow retail customers to have access to competitive
providers of energy and energy services, APS is the "provider of last resort"
for standard-offer, full-service customers under rates that have been approved
by the ACC. These rates are established until at least July 1, 2004. The 1999
Settlement Agreement allows APS to seek adjustment of these rates in the event
of emergency conditions or circumstances, such as the inability to secure
financing on reasonable terms; material changes in APS' cost of service for
ACC-regulated services resulting from federal, tribal, state or local laws;
regulatory requirements; or judicial decisions, actions or orders. Energy prices
in the western wholesale market vary and, during the course of the last two
years, have been volatile. At various times, prices in the spot wholesale market
have significantly exceeded the amount included in APS' current retail rates. In
the event of shortfalls due to unforeseen increases in load demand or generation
or transmission outages, APS may need to purchase additional supplemental power
in the wholesale spot market. Unless APS is able to obtain an adjustment of its
rates under the emergency provisions of the 1999 Settlement Agreement, there can
be no assurance that APS would be able to fully recover the costs of this power.
See "APS General Rate Case and Retail Rate Adjustment Mechanisms" below for a
discussion of retail rate adjustment mechanisms that were the subject of ACC
hearings in March 2003.

     TRACK A ORDER

     On September 10, 2002, the ACC issued the Track A Order, in which the ACC,
among other things:

                                       12
<PAGE>
     o    reversed its decision, as reflected in the Rules, to require APS to
          transfer its generation assets either to an unrelated third party or
          to a separate corporate affiliate; and

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

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

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

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

          o    the appropriate treatment of the $234 million pretax asset
               write-off agreed to by APS as part of the 1999 Settlement
               Agreement; and

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

     o    Upon the ACC's issuance of a final decision that is no longer subject
          to appeal approving APS' request to provide $500 million of financing
          or credit support to Pinnacle West Energy or the Company, with
          appropriate conditions, APS' appeals of the Track A Order would be
          limited to the issues described in the preceding bullet points, each
          of which would be presented to the ACC for consideration prior to any
          final judicial resolution. As noted below, the ACC issued the
          Financing Order on April 4, 2003. The Financing Order is final and no
          longer subject to appeal. As a result, APS' appeals of the Track A
          Order will be limited to the issues described in the preceding bullet
          points.

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

                                       13
<PAGE>
April 22, 2003, the Notice of Claim was deemed denied with respect to the ACC
and the Arizona Attorney General, and APS, Pinnacle West and Pinnacle West
Energy may now pursue the claim in court.

     TRACK B ORDER

     On March 14, 2003, the ACC issued the Track B Order, which requires APS to
solicit bids for certain estimated capacity and energy requirements for periods
beginning July 1, 2003. For 2003, APS will be required to solicit competitive
bids for about 2,500 megawatts of capacity and about 4,600 gigawatt-hours of
energy, or approximately 20% of APS' total retail energy requirements. The bid
amounts are expected to increase in 2004 and 2005 based largely on growth in
APS' retail load and APS' retail energy sales. The Track B Order also confirmed
that it was "not intended to change the current rate base status of [APS']
existing assets."

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

     APS issued requests for proposals in March 2003 and by May 6, 2003, APS
entered into contracts to meet all or a portion of its requirements for the
years 2003 through 2006 as follows.

     (1)  Pinnacle West Energy agreed to provide 1,700 MW in July through
          September of 2003 and in June through September of 2004, 2005 and
          2006, by means of a unit contingent contract.

     (2)  PPL EnergyPlus, LLC agreed to provide 112 MW in July through September
          of 2003 and 150 MW in June through September of 2004 and 2005, by
          means of a unit contingent contract.

     (3)  Panda Gila River LP agreed to provide 450 MW in October of 2003 and
          2004 and May of 2004 and 2005, and 225 MW from November 2003 through
          April 2004 and from November 2004 through April 2005, by means of firm
          call options.

                                       14
<PAGE>
     ACC FINANCING ORDERS

     On April 4, 2003, the ACC issued the Financing Order authorizing APS to
lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of
Pinnacle West Energy debt, or a combination of both, not to exceed $500 million
in the aggregate (the "APS Loan"), subject to the following principal
conditions:

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

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

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

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

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

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

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

     o    certain waivers of the ACC's affiliated interest rules previously
          granted to APS and its affiliates will be temporarily withdrawn and,
          during the term of the APS Loan, neither Pinnacle West nor Pinnacle
          West Energy may reorganize or restructure, acquire or divest assets,
          or form, buy or sell affiliates (each, a "Covered Transaction"), or
          pledge or otherwise encumber the Pinnacle West Energy assets without
          prior ACC approval, except that the foregoing restrictions will not
          apply to the following categories of Covered Transactions:

          o    Covered Transactions less than $100 million, measured on a
               cumulative basis over the calendar year in which the Covered
               Transactions are made;

                                       15
<PAGE>
          o    Covered Transactions by SunCor of less than $300 million through
               2005, consistent with SunCor's anticipated accelerated asset
               sales activity during those years;

          o    Covered Transactions related to the payment of ongoing
               construction costs for Pinnacle West Energy's (a) West Phoenix
               Unit 5, located in Phoenix, with an expected commercial operation
               date in mid-2003, and (b) Silverhawk plant, located near Las
               Vegas, with an expected commercial operation date in mid-2004;
               and

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

     The ACC also ordered the ACC staff to conduct an inquiry into our and our
affiliates' compliance with the retail electric competition and related rules
and decisions.

     No party filed an application for reconsideration of the Financing Order.
As a result, the Financing Order is final and not subject to appeal.

     On May 12, 2003, APS issued $500 million of debt pursuant to the Financing
Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy
distributed the net proceeds of that loan to us to fund the repayment of certain
of our debt. See Note 4.

     On November 22, 2002, the ACC issued an order (the "Interim Financing
Order") approving APS' request to permit APS to (a) make short-term advances to
Pinnacle West in the form of an inter-affiliate line of credit in the amount of
$125 million, or (b) guarantee $125 million of Pinnacle West's short-term debt,
subject to certain conditions.

     APS GENERAL RATE CASE AND RETAIL RATE ADJUSTMENT MECHANISMS

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

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

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

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

     The general rate case will also address the implementation of rate
adjustment mechanisms that were the subject of ACC hearings in April 2003. The

                                       16
<PAGE>
rate adjustment mechanisms, which were authorized as a result of the 1999
Settlement Agreement, would allow APS to recover several types of costs, the
most significant of which are power supply costs (fuel and purchased power
costs) and costs associated with complying with the Rules. We assume that the
ACC will make a decision in this general rate case by the end of 2004.

FEDERAL

     In July 2002, the FERC adopted a price mitigation plan that constrains the
price of electricity in the wholesale spot electricity market in the western
United States. The FERC has adopted a price cap of $250 per MWh for the period
subsequent to October 31, 2002. Sales at prices above the cap must be justified
and are subject to potential refund.

     On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for
Standard Market Design for wholesale electric markets. Voluminous comments and
reply comments were filed on virtually every aspect of the proposed rule. On
April 28, 2003, the FERC issued an additional white paper on the proposed
Standard Market Design. The white paper makes several changes to the proposed
Standard Market Design, including a greater emphasis on flexibility for regional
needs. The FERC invited comments on the white paper, but has not yet set a due
date for filing comments. We are reviewing the proposed rulemaking and cannot
currently predict what, if any, impact there may be to the Company if the FERC
adopts the proposed rule or any modifications proposed in the comments.

GENERAL

     The regulatory developments and legal challenges to the Rules discussed in
this Note have raised considerable uncertainty about the status and pace of
retail electric competition in Arizona. Although some very limited retail
competition existed in APS' service area in 1999 and 2000, there are currently
no active retail competitors providing unbundled energy or other utility
services to APS' customers. As a result, we cannot predict when, and the extent
to which, additional competitors will re-enter APS' service territory. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete in the new
regulatory environment.

6.   Nuclear Insurance

     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 $300 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, APS could be
assessed retrospective premium adjustments. The maximum assessment per reactor
under the program for each nuclear incident is approximately $88 million,
subject to an annual limit of $10 million per incident. Based on APS' interest
in the three Palo Verde units, APS' maximum potential assessment per incident
for all three units is approximately $77 million, with an annual payment
limitation of approximately $9 million.

     The Palo Verde participants maintain "all risk" (including nuclear hazards)
insurance for property damage to, and decontamination of, property at Palo Verde

                                       17
<PAGE>
in the aggregate amount of $2.75 billion, a substantial portion of which must
first be applied to stabilization and decontamination. APS has also secured
insurance against portions of any increased cost of generation or purchased
power and business interruption resulting from a sudden and unforeseen outage of
any of the three units. The insurance coverage discussed in this and the
previous paragraph is subject to certain policy conditions and exclusions.

7.   Business Segments

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

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

     o    our marketing and trading segment, which consists of our competitive
          energy business activities, including wholesale marketing and trading
          and APS Energy Services' commodity-related energy services. In early
          2003, we moved our marketing and trading division from Pinnacle West
          to APS for future marketing and trading activities (existing wholesale
          contracts will remain at Pinnacle West) as a result of the ACC's Track
          A Order prohibiting the previously required transfer of APS'
          generating assets to Pinnacle West Energy; and

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

     The amounts in our other segment include activity principally related to
NAC in the periods ended March 31, 2003 (see Note 12), as well as the parent
company and other subsidiaries. Financial data for the Company's business
segments follows (dollars in millions):

                                       18
<PAGE>
                                     Three Months Ended     Twelve Months Ended
                                          March 31,              March 31,
                                     -------------------   --------------------
                                       2003       2002       2003        2002
                                     --------   --------   --------    --------
Operating Revenues:
     Regulated electricity           $    385   $    380   $  2,018    $  2,530
     Marketing and trading                163         76        413         469
     Real estate                           41         40        202         176
     Other                                 15          4         73          14
                                     --------   --------   --------    --------
         Total                       $    604   $    500   $  2,706    $  3,189
                                     ========   ========   ========    ========

Income From Continuing Operations:
     Regulated electricity           $      8   $     31   $    147    $    179
     Marketing and trading                  8         20         46         133
     Real estate (a)                        1          1          9           4
     Other                                  3          1        (29)          1
                                     --------   --------   --------    --------
         Total                       $     20   $     53   $    173    $    317
                                     ========   ========   ========    ========

(a)  Excludes income from discontinued operations for the three months ended
     March 31 of $5 million (after tax) in 2003 and $1 million (after tax) in
     2002. Excludes income from discontinued operations for the twelve months
     ended March 31 of $14 million (after tax) in 2003 and $1 million (after
     tax) in 2002. See Note 19 for further discussion of our real estate
     activities.

                                                 As of         As of
                                                March 31,   December 31,
                                                  2003          2002
                                                --------      --------
          Assets:
            Regulated electricity               $  8,033      $  7,589
            Marketing and trading                    250           301
            Real estate                              448           504
            Other                                     24            32
                                                --------      --------
               Total                            $  8,755      $  8,426
                                                ========      ========

8.   Accounting Matters

     In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This statement amends and
clarifies financial accounting and reporting for derivative instruments and for
hedging activities under SFAS No. 133. The provisions of SFAS No. 149 that
relate to previously issued SFAS No. 133 derivatives implementation guidance
should continue to be applied in accordance with the effective dates of the
original implementation guidance. In general, other provisions are applied
prospectively to contracts entered into or modified after June 30, 2003, and for

                                       19
<PAGE>
hedging relationships designated after June 30, 2003. We are currently
evaluating the impacts of the new standard on our financial statements.

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

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

     See the following Notes for other new accounting standards:

     o    Note 9 for a new interpretation (FIN No. 46) related to VIEs;

     o    Note 10 for a new EITF issue (EITF 02-3) related to accounting for
          energy trading contracts;

     o    Note 13 for a new accounting standard (SFAS No. 143) on asset
          retirement obligations;

     o    Note 15 for a new accounting standard (SFAS No. 148) on stock-based
          compensation; and

     o    Note 17 for a new interpretation (FIN No. 45) on guarantees.

9.   Variable Interest Entities

     In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities." FIN No. 46 requires that we consolidate a VIE if we have a
majority of the risk of loss from the VIE's activities or we are entitled to
receive a majority of the VIE's residual returns or both. A VIE is a
corporation, partnership, trust or any other legal structure that either does
not have equity investors with voting rights or has equity investors that do not
provide sufficient financial resources for the entity to support its activities.
FIN No. 46 is effective immediately for any VIE created after January 31, 2003
and is effective July 1, 2003 for VIEs created before February 1, 2003.

                                       20
<PAGE>
     In 1986, APS entered into agreements with three separate SPE lessors in
order to sell and lease back interests in Palo Verde Unit 2. The leases are
accounted for as operating leases in accordance with GAAP. Based on our
preliminary assessment of FIN No. 46, we do not believe we will be required to
consolidate the Palo Verde SPEs. However, we continue to evaluate the
requirements of the new guidance to determine what impact, if any, it will have
on our financial statements.

     APS is exposed to losses under the Palo Verde sale-leaseback agreements
upon the occurrence of certain events that APS does not consider to be
reasonably likely to occur. Under certain circumstances (for example, the NRC
issuing specified violation orders with respect to Palo Verde or the occurrence
of specified nuclear events), APS would be required to assume the debt
associated with the transactions, make specified payments to the equity
participants, and take title to the leased Unit 2 interests, which, if
appropriate, may be required to be written down in value. If such an event had
occurred as of March 31, 2003, APS would have been required to assume
approximately $285 million of debt and pay the equity participants approximately
$200 million.

10.  Derivative Instruments and Energy Trading Activities

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

     For the twelve months ended March 31, 2002, we recorded a $12 million after
tax charge in net income and a $8 million after tax credit in common stock
equity (as a component of other comprehensive income (loss)), both as cumulative
effects of a change in accounting for derivatives, as required by SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The charge
primarily resulted from electricity option contracts. The credit resulted from
unrealized gains on cash flow hedges.

     We adopted the EITF 02-3 guidance for all contracts in the fourth quarter
of 2002. In 2002, we recorded a $66 million after tax charge in net income as a
cumulative effect adjustment for the previously recorded accumulated unrealized
mark-to-market on energy trading contracts that did not meet the accounting
definition of a derivative. Our energy trading contracts that are derivatives
are accounted for at fair value under SFAS No. 133. Contracts that do not meet
the definition of a derivative are accounted for on an accrual basis with the
associated revenues and costs recorded at the time the contracted commodities
are delivered or received. Additionally, all gains and losses (realized and
unrealized) on energy trading contracts that qualify as derivatives are included
in marketing and trading segment revenues on the Condensed Consolidated
Statements of Income on a net basis. Derivative instruments used for non-trading
activities are accounted for in accordance with SFAS No. 133.

                                       21
<PAGE>
     EITF 02-3 requires that derivatives held for trading purposes, whether
settled financially or physically, be reported in the income statement on a net
basis. Conversely, all non-trading contracts and derivatives are to be reported
gross on the income statement.

     The changes in derivative fair value of our system positions included in
the Condensed Consolidated Statements of Income for the three and twelve months
ended March 31, 2003 and 2002 are comprised of the following (dollars in
thousands):

<TABLE>
<CAPTION>
                                                        Three Months Ended          Twelve Months Ended
                                                              March 31,                  March 31,
                                                      ------------------------    ------------------------
                                                         2003          2002          2003          2002
                                                      ----------    ----------    ----------    ----------
<S>                                                   <C>           <C>           <C>           <C>
Gains (losses) on the ineffective portion of
    derivatives qualifying for hedge accounting (a)   $    2,778    $   (2,548)   $   16,524    $   (6,155)
Losses from the discontinuance of cash flow hedges            --           (44)       (8,776)       (3,561)
Losses from non-hedge derivatives                           (106)         (855)       (3,575)       (6,864)
Prior period mark-to-market losses realized upon
    delivery of commodities                               10,443         3,813        14,635        23,368
                                                      ----------    ----------    ----------    ----------
Total pretax gain                                     $   13,115    $      366    $   18,808    $    6,788
                                                      ==========    ==========    ==========    ==========
</TABLE>

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

     As of March 31, 2003, the maximum length of time over which we are hedging
our exposure to the variability in future cash flows for forecasted transactions
is approximately six years. During the twelve months ending March 31, 2004, we
estimate that a net loss of $3 million before income taxes will be reclassified
from accumulated other comprehensive loss as an offset to the effect on earnings
of market price changes for the related hedged transactions.

     The mark-to-market related to our risk management and trading activities
are presented in two categories, consistent with our business segments:

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

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

     The following table summarizes our assets and liabilities from risk
management and trading activities at March 31, 2003 and December 31, 2002
(dollars in thousands):

                                       22
<PAGE>
March 31, 2003

<TABLE>
<CAPTION>
                         Current                      Current          Other         Net Asset/
                         Assets       Investments    Liabilities    Liabilities     (Liability)
                       ----------     -----------    -----------    -----------     -----------
<S>                    <C>            <C>            <C>             <C>             <C>
Mark-to-Market:
    Marketing
    and Trading        $   23,849     $   39,743     $   (6,479)     $   (1,242)     $   55,871
    System                 82,499          8,205        (86,595)        (26,890)        (22,781)
Emission
    allowances
     - at cost                 --         52,261             --         (24,011)         28,250
                       ----------     ----------     ----------      ----------      ----------
Total                  $  106,348     $  100,209     $  (93,074)     $  (52,143)     $   61,340
                       ==========     ==========     ==========      ==========      ==========
</TABLE>

December 31, 2002

<TABLE>
<CAPTION>
                         Current                      Current          Other         Net Asset/
                         Assets       Investments    Liabilities    Liabilities     (Liability)
                       ----------     -----------    -----------    -----------     -----------
<S>                    <C>            <C>            <C>             <C>             <C>
Mark-to-Market:
    Marketing
    and Trading        $   17,640     $   51,771     $   (9,848)     $   (2,583)     $   56,980
    System                 41,522          6,971        (60,819)        (36,678)        (49,004)
Emission
    allowances
    - at cost                  --         63,594             --         (36,381)         27,213
                       ----------     ----------     ----------      ----------      ----------
Total                  $   59,162     $  122,336     $  (70,667)     $  (75,642)     $   35,189
                       ==========     ==========     ==========      ==========      ==========
</TABLE>

     Cash or collateral required to serve as collateral against our open
positions on energy-related contracts is included in investments and other
assets and current liabilities on the Condensed Consolidated Balance Sheet. No
collateral was provided at March 31, 2003. Collateral provided was $5 million at
December 31, 2002. Collateral held was $23 million at March 31, 2003 and $22
million at December 31, 2002.

11.  Comprehensive Income

     Components of comprehensive income for the three and twelve months ended
March 31, 2003 and 2002, are as follows (dollars in thousands):

                                       23
<PAGE>
<TABLE>
<CAPTION>
                                                   Three Months Ended        Twelve Months Ended
                                                       March 31,                  March 31,
                                                ------------------------   ------------------------
                                                   2003          2002         2003          2002
                                                ----------    ----------   ----------    ----------
<S>                                             <C>           <C>          <C>           <C>
Net income                                      $   25,298    $   53,757   $  120,949    $  306,473
                                                ----------    ----------   ----------    ----------
Other comprehensive income (loss):
  Minimum pension liability adjustment, net
    of tax                                              31            --      (70,267)         (966)
  Cumulative effect of a change in accounting
    for derivatives,
    net of tax                                          --            --           --         7,801
  Unrealized gain (loss) on derivative
    instruments, net of tax (a)                     15,806        26,826       32,920       (72,200)
  Reclassification of realized (gain) loss to
    income, net of tax (b)                          (4,351)          990       (5,702)       (8,809)
                                                ----------    ----------   ----------    ----------
Total other comprehensive income (loss)             11,486        27,816      (43,049)      (74,174)
                                                ----------    ----------   ----------    ----------
Comprehensive income                            $   36,784    $   81,573   $   77,900    $  232,299
                                                ==========    ==========   ==========    ==========
</TABLE>

(a)  These amounts primarily include unrealized gains and losses on contracts
     used to hedge our forecasted gas requirements to serve Native Load.
(b)  These amounts primarily include the reclassification of unrealized gains
     and losses to realized for contracted commodities delivered during the
     period.

12.  Commitments and Contingencies

CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST

     In July 2001, the FERC ordered an expedited fact-finding hearing to
calculate refunds for spot market transactions in California during a specified
time frame. This order calls for a hearing, with findings of fact due to the
FERC after the ISO and PX provide necessary historical data. The FERC directed
an ALJ to make findings of fact with respect to: (1) the mitigated price in each
hour of the refund period; (2) the amount of refunds owed by each supplier
according to the methodology established in the order; and (3) the amount
currently owed to each supplier (with separate quantities due from each entity)
by the CAISO, the California Power Exchange, the investor-owned utilities and
the State of California.

     APS was a seller and a purchaser in the California markets at issue, and to
the extent that refunds are ordered, APS should be a recipient as well as a
payor of such amounts. On December 12, 2002, the ALJ issued Proposed Findings of
Fact with respect to the refunds. On March 26, 2003, the FERC adopted the great
majority of the proposed findings, revising only the calculation of natural gas
prices for the final determination of mitigated prices in the California
markets. Sellers who may actually have paid more for natural gas than the proxy
prices adopted by the FERC have 40 days in which to submit necessary data to the
FERC, after which a technical conference will be held. Finalization of refund
amounts is expected in mid-2003. Subsequent to the foregoing refund decision by

                                       24
<PAGE>
the FERC, the California parties filed a request for rehearing asking the FERC
to expand the time period and transactions covered by the refund proceeding and
provide for approximately $3 billion in additional refunds relating to sales by
all sellers in the California markets. APS does not anticipate material changes
in its exposure and still believes, subject to the finalization of the revised
proxy prices, that it will be entitled to a net refund.

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

     The FERC also ordered an evidentiary proceeding to discuss and evaluate
possible refunds for the Pacific Northwest. The FERC required that the record
establish the volume of the transactions, the identification of the net sellers
and net buyers, the price and terms and conditions of the sales contracts and
the extent of potential refunds. On September 24, 2001, an ALJ concluded that
prices in the Pacific Northwest during the period December 25, 2000 through June
20, 2001 were the result of a number of factors in addition to price signals
from the California markets, including the shortage of supply, excess demand,
drought and increased natural gas prices. Under these circumstances, the ALJ
ultimately concluded that the prices in the Pacific Northwest were not
unreasonable or unjust and refunds should not be ordered in this proceeding. On
December 19, 2002, the FERC opened a new discovery period to permit the parties
to offer additional evidence for the period January 1, 2000 through June 20,
2001. Additional evidence has been submitted and a FERC decision on the newly
submitted evidence is expected soon. Based on public comments from the FERC, it
is anticipated that this case will be sent back to the ALJ for further
proceedings on spot market and balance of month transactions.

     Although the FERC has not yet made a final ruling in the Pacific Northwest
matter nor calculated the specific refund amounts due in California, we do not
expect that the resolution of these issues, as to the amounts alleged in the
proceedings, will have a material adverse impact on our financial position,
results of operations or liquidity.

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

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

                                       25
<PAGE>
     We are closely monitoring developments in the California energy market and
the potential impact of these developments on us and our subsidiaries. Based on
our evaluations, we previously reserved $10 million before income taxes for our
credit exposure related to the California energy situation, $5 million of which
was recorded in the fourth quarter of 2000 and $5 million of which was recorded
in the first quarter of 2001. Our evaluations took into consideration our range
of exposure of approximately zero to $38 million before income taxes and review
of likely recovery rates in bankruptcy situations.

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

     CALIFORNIA ENERGY MARKET LITIGATION On March 19, 2002, the State of
California filed a complaint with the FERC alleging that wholesale sellers of
power and energy, including the Company, failed to properly file rate
information at the FERC in connection with sales to California from 2000 to the
present. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER EXCHANGE ET AL., Docket
No. EL02-71-000. The complaint requests the FERC to require the wholesale
sellers to refund any rates that are "found to exceed just and reasonable
levels." This complaint has been dismissed by the FERC and the State of
California is now appealing the matter to the Ninth Circuit Court of Appeals. In
addition, the State of California and others have filed various claims, which
have now been consolidated, against several power suppliers to California
alleging antitrust violations. WHOLESALE ELECTRICITY ANTITRUST CASES I AND II,
Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005
and 4204-00006. Two of the suppliers who were named as defendants in those
matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke
Energy and Trading, LLP (and other Duke entities), filed cross-claims against
various other participants in the PX and ISO markets, including APS, attempting
to expand those matters to such other participants. APS has not yet filed a
responsive pleading in the matter, but APS believes the claims by Reliant and
Duke as they relate to APS are without merit.

     APS was also named in a lawsuit regarding wholesale contracts in
California. JAMES MILLAR, ET AL. V. ALLEGHENY ENERGY SUPPLY, ET AL., United
States District Court in and for the District of Northern California, Case No.
C02-2855 EMC. The complaint alleges basically that the contracts entered into
were the result of an unfair and unreasonable market. The PX has filed a lawsuit
against the State of California regarding the seizure of forward contracts and
the State has filed a cross complaint against APS and numerous other PX
participants. CAL PX V. THE STATE OF CALIFORNIA Superior Court in and for the
County of Sacramento, JCCP No. 4203. Various preliminary motions are being filed
and we cannot currently predict the outcome of this matter. The "United States
Justice Foundation" is suing numerous wholesale energy contract suppliers to
California, including us, as well as the California Department of Water

                                       26
<PAGE>
Resources, based upon an alleged conflict of interest arising from the
activities of a consultant for Edison International who also negotiated
long-term contracts for the California Department of Water Resources.
MCCLINTOCK, ET AL. V. YUDHRAJA, Superior Court in and for the County of Los
Angeles, Case No. GC 029447. The California Attorney General has indicated that
an investigation by his office did not find evidence of improper conduct by the
consultant. We believe the claims against APS and us in the lawsuits mentioned
in this paragraph are without merit and will have no material adverse impact on
our financial position, results of operations or liquidity.

POWER SERVICE AGREEMENT

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

EL DORADO'S INVESTMENT IN NAC

     Through our unregulated wholly-owned subsidiary, El Dorado, we own a
majority interest in NAC, a company that develops, markets and contracts for the
manufacture of cask designs for spent nuclear fuel storage and transportation.
Prior to the third quarter of 2002, our investment in NAC was accounted for
under the equity method and our share of NAC's earnings and losses was recorded
in other income or expense in our Condensed Consolidated Statements of Income.
Beginning in the third quarter of 2002, we fully consolidated NAC's financial
statements after acquiring a controlling interest in NAC as a result of
increased voting representation on NAC's Board of Directors. During the second
and third quarters of 2002, we recorded cumulative losses of approximately $21
million before tax ($13 million after tax, $0.15 per share) related to NAC,
primarily as a result of expected losses under contracts with two customers,
including a contract between NAC and Maine Yankee Atomic Power Company (Maine
Yankee).

     On January 15, 2003, Maine Yankee notified NAC of its intention to
terminate its contract with NAC. We recorded additional NAC losses of
approximately $38 million before tax ($23 million after tax, or $0.27 per share)
in the fourth quarter of 2002, the substantial majority of which relate to the
termination of the Maine Yankee contract. As a result, in 2002, we recorded NAC
losses of approximately $59 million before tax ($35 million after tax, or $0.42
per share).

     On March 4, 2003, Maine Yankee filed suit against Pinnacle West, NAC and a
surety company in federal court in Portland, Maine. MAINE YANKEE

                                       27
<PAGE>
ATOMIC POWER COMPANY V. UNITED STATES FIRE INSURANCE COMPANY, Civil Action
Docket No. 03-58-PC, United States District Court, District of Maine. The
lawsuit and a related arbitration proceeding initiated by NAC were dismissed in
April 2003 as part of a settlement among the parties. We reversed $5 million of
loss reserves in the first quarter of 2003 related to NAC's contract settlement.
We believe we have reserved our exposure with respect to NAC's contracts in all
material respects and, as a result, we consider these charges non-recurring. We
do not expect material losses for the year 2003 related to NAC.

13.  Asset Retirement Obligations

     On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides accounting requirements for the
recognition and measurement of liabilities associated with the retirement of
tangible long-lived assets. The standard requires that these liabilities be
recognized at fair value as incurred and capitalized as part of the related
tangible long-lived assets. Accretion of the liability due to the passage of
time is an operating expense and the capitalized cost is depreciated over the
useful life of the long-lived asset. Prior to January 1, 2003 we accrued asset
retirement obligations over the life of the related asset through depreciation
expense.

     APS has asset retirement obligations for its Palo Verde nuclear facilities
and certain other generation, transmission and distribution assets. The Palo
Verde asset retirement obligation primarily relates to final plant
decommissioning. This obligation is based on the NRC's requirements for disposal
of radiated property or plant and agreements APS reached with the ACC for final
decommissioning of the plant. The non-nuclear generation asset retirement
obligations primarily relate to requirements for removing portions of those
plants at the end of the plant life or lease term. Some of our transmission and
distribution assets have asset retirement obligations because they are subject
to right of way and easement agreements that require final removal. These
agreements have a history of uninterrupted renewal that we expect will continue
for the foreseeable future. As a result, APS cannot reasonably estimate the fair
value of the asset retirement obligation related to such distribution and
transmission assets. The asset retirement obligations associated with our
non-regulated assets are immaterial.

     On January 1, 2003, APS recorded a liability of $219 million for its asset
retirement obligations, including the accretion impacts; a $67 million increase
in the carrying amount of the associated assets; and a net reduction of $192
million in accumulated depreciation related primarily to the reversal of
previously recorded accumulated decommissioning and other removal costs related
to these obligations. Additionally, APS recorded a net regulatory liability of
$40 million for the asset retirement obligations related to its regulated
assets. This regulatory liability represents the difference between the amount
currently being recovered in regulated rates and the amount calculated under
SFAS No. 143. APS believes it can recover in regulated rates the transition
costs and ongoing current period costs calculated in accordance with SFAS No.
143. The adoption of SFAS No. 143 did not have a material impact on our net
income for the quarter ended March 31, 2003.

     In accordance with SFAS No. 71, APS will continue to accrue for removal
costs for its regulated assets, even if there is no legal obligation for
removal. At March 31, 2003, accumulated depreciation shown on our Condensed
Consolidated Balance Sheets included approximately $360 million of estimated
future removal costs that are not considered legal obligations.

                                       28
<PAGE>
     The following schedule shows the change in our asset retirement obligations
during the three-month period ended March 31, 2003 (dollars in millions):

          Balance at January 1, 2003                            $  219
               Changes attributable to:
                 Liabilities incurred                               --
                 Liabilities settled                                --
                 Accretion expense                                   4
                 Estimated cash flow revisions                      --
                                                                ------
          Balance at March 31, 2003                             $  223
                                                                ======

     The following schedule shows the change in our pro forma liability for the
periods ended December 31, 2002 and 2001, as if we had recorded an asset
retirement obligation based on the guidance in SFAS No. 143 (dollars in
millions):

                                                         2002       2001
                                                        ------     ------
     Balance at beginning of year                       $  204     $  190
          Accretion expense                                 15         14
                                                        ------     ------
     Balance at end of year                             $  219     $  204
                                                        ======     ======

     The pro forma effects on net income for 2002 and 2001 are immaterial.

     To fund the costs APS expects to incur to decommission the plant, APS
established external decommissioning trusts in accordance with NRC regulations.
APS invests the trust funds primarily in fixed income securities and domestic
stock and classifies them as available for sale. The following table shows the
cost and fair value of APS' nuclear decommissioning trust fund assets which are
reported in investments and other assets on the Condensed Consolidated Balance
Sheets at March 31, 2003 and December 31, 2002 (dollars in millions):

                                                    March 31,    December 31,
                                                       2003         2002
                                                      ------       ------
     Trust fund assets - at cost
          Fixed income securities                     $  115       $  113
          Domestic stock                                  70           68
                                                      ------       ------
     Total                                            $  185       $  181
                                                      ======       ======

     Trust fund assets - at fair value
          Fixed income securities                     $  124       $  117
          Domestic stock                                  80           77
                                                      ------       ------
     Total                                            $  204       $  194
                                                      ======       ======

                                       29
<PAGE>
14.  Intangible Assets

     The Company's gross intangible assets (which are primarily software) were
$233 million at March 31, 2003 and $214 million at December 31, 2002. The
related accumulated amortization was $110 million at March 31, 2003 and $104
million at December 31, 2002. Amortization expense for the three months ended
March 31 was $6 million in 2003 and $4 million in 2002. Amortization expense for
the twelve months ended March 31 was $23 million in 2003 and $21 million in
2002. Estimated amortization expense on existing intangible assets over the next
five years is $27 million in 2003, $26 million in 2004, $25 million in 2005, $22
million in 2006 and $14 million in 2007.

15.  Stock-Based Compensation

     In 2002, we began applying the fair value method of accounting for
stock-based compensation, as provided for in SFAS No. 123, "Accounting for
Stock-Based Compensation." In accordance with the transition requirements of
SFAS No. 123, as amended by SFAS No. 148 "Accounting for Stock-Based
Compensation - Transition and Disclosure," we applied the fair value method
prospectively, beginning with 2002 stock grants. In prior years, we recognized
stock compensation expense based on the intrinsic value method allowed in
Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued
to Employees."

     The following chart compares our net income, stock compensation expense and
earnings per share to what those items would have been if we had recorded stock
compensation expense based on the fair value method for all stock grants through
March 31, 2003 (dollars in thousands, except per share amounts):

                                     Three Months Ended     Twelve Months Ended
                                          March 31,               March 31,
                                    --------------------    --------------------
                                      2003        2002        2003        2002
                                    --------    --------    --------    --------
Net Income:
  As reported                       $ 25,298    $ 53,757    $120,949    $306,473
  Pro forma (fair value method)       24,998      53,385     119,626     304,382
Stock compensation expense
  (net of tax):
  As reported                            152          --         452          --
  Pro forma (fair value method)          300         372       1,323       2,091

Earnings per share - basic:
  As reported                       $   0.28    $   0.63    $   1.40    $   3.62
  Pro forma (fair value method)     $   0.27    $   0.63    $   1.38    $   3.59
Earnings per share - diluted:
  As reported                       $   0.28    $   0.63    $   1.40    $   3.61
  Pro forma (fair value method)     $   0.27    $   0.63    $   1.38    $   3.58

                                       30
<PAGE>
16.  Other Income and Other Expense

     The following table provides detail of other income and other expense for
the three and twelve months ended March 31, 2003 and 2002 (dollars in
thousands):

<TABLE>
<CAPTION>
                                        Three Months Ended          Twelve Months Ended
                                              March 31,                   March 31,
                                      ------------------------    ------------------------
                                         2003          2002          2003          2002
                                      ----------    ----------    ----------    ----------
<S>                                   <C>           <C>           <C>           <C>
Other income:
   Environmental insurance recovery   $       --    $       --    $       --    $   12,350
   Investment gains - net                  1,279         2,039            --            --
   Interest income                           713         1,178         3,957         7,371
   SunCor joint venture earnings           3,244           916         9,605         3,423
   Miscellaneous                             485         1,028         2,664         3,952
                                      ----------    ----------    ----------    ----------
 Total other income                   $    5,721    $    5,161    $   16,226    $   27,096
                                      ==========    ==========    ==========    ==========
 Other expense:
   Investment losses - net (a)        $       --    $       --    $  (11,198)   $   (4,138)
   Non-operating costs - SunCor               --            --            --        (7,000)
   Non-operating costs (b)                (3,538)       (3,882)      (19,086)      (16,362)
   Miscellaneous                            (659)       (1,207)       (3,235)       (5,364)
                                      ----------    ----------    ----------    ----------
 Total other expense                  $   (4,197)   $   (5,089)   $  (33,519)   $  (32,864)
                                      ==========    ==========    ==========    ==========
</TABLE>

(a)  Primarily related to El Dorado's investment in NAC in 2002 (see Note 12).
(b)  As defined by the FERC, includes below-the-line non-operating utility costs
     (primarily community relations and environmental compliance).

17.  Guarantees

     On January 1, 2003 we adopted FIN No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others." FIN No. 45 elaborates on the disclosures to be made by
a guarantor in its financial statements about its obligations under certain
guarantees. It also clarifies that a guarantor is required to recognize, at
inception of a guarantee, a liability for the fair value of the obligation
undertaken in issuing the guarantee. The disclosure provisions are effective for
the year ended December 31, 2002. The initial recognition and measurement
provisions of FIN No. 45 are effective on a prospective basis to guarantees
issued or modified after December 31, 2002.

     We have issued parental guarantees and letters of credit and obtained
surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees
related to Pinnacle West Energy primarily consist of equipment and performance
guarantees related to our generation construction program, transmission service
guarantees for West Phoenix Units 4 and 5 and long-term service agreement
guarantees for new power plants. Our credit support instruments enable APS
Energy Services to provide commodity energy and energy-related products and
enable El Dorado to support the activities of NAC. SunCor has a debt guarantee
on behalf of an affiliated joint venture. Non-performance or payment under the

                                       31
<PAGE>
original contract by our unregulated subsidiaries would require us to perform
under the guarantee or surety bond. No liability is currently recorded on the
Condensed Consolidated Balance Sheets related to Pinnacle West's guarantees on
behalf of its subsidiaries. Our guarantees have no recourse (except NAC) or
collateral provisions to allow us to recover amounts paid under the guarantee.
The amounts and approximate terms of our guarantees and surety bonds for each
subsidiary at March 31, 2003 are as follows (dollars in millions):

<TABLE>
<CAPTION>
                               Guarantees             Surety Bonds         Letters of Credit
                          --------------------    --------------------    --------------------
                                       Term                    Term                    Term
                          Amount    (in years)    Amount    (in years)    Amount    (in years)
                          ------    ----------    ------    ----------    ------    ----------
<S>                       <C>      <C>            <C>      <C>            <C>        <C>
Parental:
  Pinnacle West Energy     $106         1 to 2     $ --             --     $ 37       1 to 2
  APS Energy  Services       82    less than 2       49    less than 1       --           --
  El Dorado (all NAC)        44         1 to 3       --             --        5            1
SunCor guarantees            33              1       --             --       --           --
                           ----                    ----                    ----
Total                      $265                    $ 49                    $ 42
                           ====                    ====                    ====
</TABLE>

     At March 31, 2003, we had entered into approximately $37 million of letters
of credit which support various construction agreements. These letters of credit
expire in 2003 and 2004. We intend to provide from either existing or new
facilities for the extension, renewal or substitution of the letters of credit
to the extent required.

     APS has entered into various agreements that require letters of credit for
financial assurance purposes. At March 31, 2003, approximately $200 million of
letters of credit were outstanding to support existing pollution control bonds
of approximately $200 million. The letters of credit are available to fund the
payment of principal and interest of such debt obligations. These letters of
credit have expiration dates in 2003. APS has also entered into approximately
$113 million of letters of credit to support certain equity lessors in the Palo
Verde sale-leaseback transactions. These letters of credit expire in 2005.
Additionally, APS has approximately $5 million of letters of credit related to
counterparty collateral requirements and approximately $5 million of letters of
credit related to workers' compensation expiring in 2003. APS intends to provide
from either existing or new facilities for the extension, renewal or
substitution of the letters of credit to the extent required.

     In conjunction with our financing agreements, including our sale-leaseback
transactions, we generally provide indemnifications relating to liabilities
arising from or related to the agreements, except with certain limited
exceptions depending on the particular agreement. APS has also provided
indemnifications to the equity participants and other parties in the Palo Verde
sale-leaseback transactions with respect to certain tax matters. Generally, a
maximum obligation is not explicitly stated in the indemnification and
therefore, the overall maximum amount of the obligation under such
indemnifications cannot be reasonably estimated. Based on historical experience
and evaluation of the specific indemnities, we do not believe that any material
loss related to such indemnifications is likely and therefore no related
liability has been recorded.

                                       32
<PAGE>
18.  Earnings Per Share

     The following table presents earnings per weighted average common share
outstanding for the three and twelve months ended March 31, 2003 and 2002:

                                        Three Months Ended   Twelve Months Ended
                                             March 31,            March 31,
                                         ----------------     -----------------
                                          2003      2002       2003       2002
                                         ------    ------     ------     ------
Basic earnings per share:
  Income from continuing operations      $ 0.22    $ 0.63     $ 2.00     $ 3.76
  Income from discontinued operations      0.06        --       0.16         --
  Cumulative effect of change in
    accounting for derivatives               --        --         --      (0.14)
  Cumulative effect of change in
    accounting for trading activities        --        --      (0.76)        --
                                         ------    ------     ------     ------
Earnings per share - basic               $ 0.28    $ 0.63     $ 1.40     $ 3.62
                                         ======    ======     ======     ======

Diluted earnings per share:
  Income from continuing operations      $ 0.22    $ 0.63     $ 2.00     $ 3.75
  Income from discontinued operations      0.06        --       0.16         --
  Cumulative effect of change in
    accounting for derivatives               --        --         --      (0.14)
  Cumulative effect of change in
    accounting for trading activities        --        --      (0.76)        --
                                         ------    ------     ------     ------
Earnings per share - diluted             $ 0.28    $ 0.63     $ 1.40     $ 3.61
                                         ======    ======     ======     ======

     The following table reconciles average common shares outstanding - basic to
average common shares outstanding - diluted that are used in the earnings per
share calculation in the Condensed Consolidated Statements of Income for the
three and twelve months ended March 31, 2003 and 2002 (in thousands):

                                      Three Months Ended     Twelve Months Ended
                                           March 31,               March 31,
                                      ------------------     -------------------
                                       2003        2002       2003         2002
                                      ------      ------     ------       ------
Average common shares
  outstanding - basic                 91,256      84,735     86,509       84,719
Dilutive shares                          103         149        118          191
                                      ------      ------     ------       ------
Average common shares
  outstanding - diluted               91,359      84,884     86,627       84,910
                                      ======      ======     ======       ======

     Options to purchase 2,245,211 shares for the three month period ended March
31, 2003 and 1,991,119 shares for the twelve month period ended March 31, 2003
were outstanding but were not included in the computation of earnings per share
because the options' exercise prices were greater than the average market price
of the common shares. Options to purchase shares of common stock that were not
included in the computation of diluted earnings per share were 1,075,100 shares

                                       33
<PAGE>
for the three months ended March 31, 2002 and 635,761 shares for the twelve
months ended March 31, 2002.

19.  Real Estate Activities - Discontinued Operations

     On January 1, 2002 we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." Among other things, SFAS No. 144 prescribes
accounting for discontinued operations and defines certain real estate
activities as discontinued operations.

     In the first quarter of 2003, SunCor sold its water utility company, which
resulted in an after tax gain of $5 million ($8 million pretax). The gain on the
sale and operating income in the current and prior periods are classified as
discontinued operations in our Condensed Consolidated Statements of Income.

     In the second quarter of 2002, SunCor sold a retail center, but maintained
a significant continuing involvement through a management contract. In the first
quarter of 2003, this management contract was canceled. As a result, the gain on
the 2002 sale and the operating income related to this property have been
reclassified as discontinued operations. The income from discontinued operations
of $14 million (after income taxes) in the twelve months ended March 31, 2003
primarily reflects this sale and the sale of the water utility company.

     The following chart provides a summary of the real estate segment's
earnings (after income taxes) for the three and twelve months ended March 31,
2003 and 2002 (dollars in millions):

                                       Three Months Ended    Twelve Months Ended
                                            March 31,              March 31,
                                       ------------------    -------------------
                                        2003        2002      2003         2002
                                       ------      ------    ------       ------
Income from continuing operations      $    1      $    1    $    9       $    4
Income from discontinued operations         5           1        14            1
                                       ------      ------    ------       ------
     Net income                        $    6      $    2    $   23       $    5
                                       ======      ======    ======       ======

                                       34
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS.

INTRODUCTION

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

     o    the changes in our earnings for the three and twelve months ended
          March 31, 2003 and 2002;

     o    our capital needs, liquidity and capital resources;

     o    our business outlook and major factors that affect our financial
          outlook (see Note 5 and "Business Outlook" below); and

     o    our management of market risks.

     We suggest this section be read along with the 2002 10-K. Throughout this
Item, we refer to specific "Notes" in the Notes to Condensed Consolidated
Financial Statements in this report. These Notes add further details to the
discussion. Operating statistics for the three and twelve months ended March 31,
2003 and 2002 are available on our website (www.pinnaclewest.com) and in our
Current Report on Form 8-K dated March 31, 2003.

OVERVIEW OF OUR BUSINESS

     The Company owns all of the outstanding common stock of APS. APS is an
electric utility that provides either retail or wholesale electric service to
substantially all of the state of Arizona, with the major exceptions of the
Tucson metropolitan area and about one-half of the Phoenix metropolitan area.
Electricity is delivered through a distribution system owned by APS. APS also
generates, sells and delivers electricity to wholesale customers in the western
United States. APS does not distribute any products. The marketing and trading
segment sells, in the wholesale market, APS and Pinnacle West Energy generation
output that is not needed for APS' Native Load, which includes loads for retail
customers and traditional cost-of-service wholesale customers.

     Our other major subsidiaries are:

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

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

                                       35
<PAGE>
     o    SunCor, a developer of residential, commercial and industrial real
          estate projects in Arizona, New Mexico and Utah; and

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

EARNINGS CONTRIBUTIONS BY SUBSIDIARY AND BUSINESS SEGMENT

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

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

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

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

     The following tables summarize net income and segment details for the three
and twelve months ended March 31, 2003 and the comparable prior periods for
Pinnacle West and each of our subsidiaries (dollars in millions):

<TABLE>
<CAPTION>
                                                       Regulated         Marketing and
                                      Total           Electricity           Trading          Real Estate (a)         Other
THREE MONTHS ENDED              ----------------    ----------------    ----------------    ----------------    ----------------
    MARCH 31,                    2003      2002      2003      2002      2003      2002      2003      2002      2003      2002
                                ------    ------    ------    ------    ------    ------    ------    ------    ------    ------
<S>                             <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>
Arizona Public Service (b)(c)   $   16    $   32    $   13    $   31    $    3    $    1    $   --    $   --    $   --    $   --
Pinnacle West Energy (b)             5         1         6         1        (1)       --        --        --        --        --
APS Energy Services (d)              8         2        --        --         6         1        --        --         2         1
SunCor                               1         1        --        --        --        --         1         1        --        --
El Dorado (d)                        3        --        --        --        --        --        --        --         3        --
Parent company (c)                 (13)       17       (11)       (1)       --        18        --        --        (2)       --
                                ------    ------    ------    ------    ------    ------    ------    ------    ------    ------
Income from continuing
  operations                        20        53         8        31         8        20         1         1         3         1
Income from discontinued
  operations - net of tax            5         1        --        --        --        --         5         1        --        --
                                ------    ------    ------    ------    ------    ------    ------    ------    ------    ------
Net income                      $   25    $   54    $    8    $   31    $    8    $   20    $    6    $    2    $    3    $    1
                                ======    ======    ======    ======    ======    ======    ======    ======    ======    ======
</TABLE>

                                       36
<PAGE>
<TABLE>
<CAPTION>
                                                       Regulated         Marketing and
                                      Total           Electricity           Trading          Real Estate (a)         Other
TWELVE MONTHS ENDED             ----------------    ----------------    ----------------    ----------------    ----------------
     MARCH 31,                   2003      2002      2003      2002      2003      2002      2003      2002      2003      2002
                                ------    ------    ------    ------    ------    ------    ------    ------    ------    ------
<S>                             <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>       <C>
Arizona Public Service (b)(c)   $  183    $  248    $  179    $  166    $    4    $   82    $   --    $   --    $   --    $   --
Pinnacle West Energy (b)(f)        (14)       19       (16)       19         2        --        --        --        --        --
APS Energy Services (d)             34        --        --        --        28        (2)       --        --         6         2
SunCor                               9         4        --        --        --        --         9         4        --        --
El Dorado (d)                      (52)       --        --        --        --        --        --        --       (52)       --
Parent company (c)                  13        46       (16)       (6)       12        53        --        --        17        (1)
                                ------    ------    ------    ------    ------    ------    ------    ------    ------    ------
Income from continuing
  operations                       173       317       147       179        46       133         9         4       (29)        1
Income from discontinued
  operations - net of tax           14         1        --        --        --        --        14         1        --        --
Cumulative effect of
  change in accounting -
  net of tax (g) (h)               (66)      (12)       --        --       (66)      (12)       --        --        --        --
                                ------    ------    ------    ------    ------    ------    ------    ------    ------    ------
Net income (loss)               $  121    $  306    $  147    $  179    $  (20)   $  121    $   23    $    5    $  (29)   $    1
                                ======    ======    ======    ======    ======    ======    ======    ======    ======    ======
</TABLE>

(a)  See "Real Estate Activities" discussion below and Note 19.

(b)  Consistent with APS' October 2001 ACC filing, APS entered into agreements
     with its affiliates to buy power through June 2003. The agreements reflect
     a price based on the fully-dispatchable dedication of the Pinnacle West
     Energy generating assets to APS' Native Load customers. See "Track B Order"
     in Note 5 for information about our competitive solicitation process for
     certain estimated capacity and energy requirements beginning July 1, 2003.

(c)  In early 2003, we moved our marketing and trading division from Pinnacle
     West to APS for future marketing and trading activities (existing wholesale
     contracts will remain at Pinnacle West) as a result of the ACC's Track A
     Order prohibiting the previously required transfer of APS' generating
     assets to Pinnacle West Energy.

(d)  APS Energy Services' net income prior to 2003 and El Dorado's net income
     are primarily reported before income taxes. The income tax expense or
     benefit for these subsidiaries was recorded at the parent company.

(e)  Primarily includes activities related to El Dorado in the twelve months
     ended March 31, 2003, principally El Dorado's investment in NAC. For the
     twelve months ended March 31, 2003, we recorded a pretax loss of $55
     million related to NAC contracts with two customers. See Note 12.

(f)  In the fourth quarter of 2002, Pinnacle West Energy recorded a charge
     related to the cancellation of Redhawk Units 3 and 4 of approximately $30
     million after income taxes ($49 million pretax).

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

                                       37
<PAGE>
(h)  APS recorded a $12 million after tax charge in June 2001 for the cumulative
     effect of a change in accounting for derivatives related to the adoption of
     SFAS No. 133, "Accounting for Derivative Instruments and Hedging
     Activities."

RESULTS OF OPERATIONS

     GENERAL

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

     OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 2003 COMPARED WITH
     THREE-MONTH PERIOD ENDED MARCH 31, 2002

     Our consolidated net income for the three months ended March 31, 2003 was
$25 million compared with $54 million for the prior year. Included in 2003
income is $5 million of after tax income related primarily to SunCor's sale of
its water utility company accounted for as discontinued operations in our real
estate segment (see "Real Estate Activities" below).

     Our income from continuing operations for the three months ended March 31,
2003 was $20 million compared with $53 million for the comparable period in the
prior year. The period-to-period decrease of $33 million was primarily due to:

     o    lower earnings contributions from our marketing and trading
          activities, reflecting lower liquidity and higher price volatility in
          the wholesale power markets in the western United States, partially
          offset by lower mark-to-market reversals due to the adoption of EITF
          02-3 ($17 million, after tax);

     o    higher depreciation, operations and maintenance, and interest expenses
          related to new power plants in service ($10 million, after tax);

     o    higher operating costs primarily related to the timing of power plant
          overhauls and higher pension and other postretirement benefit costs
          ($7 million, after tax);

     o    decreased earnings contributions from our regulated electricity
          activities, reflecting retail electricity price decreases, the effects
          of milder weather and higher replacement power cost for plant outages,
          partially offset by retail customer growth, ($5 million, after tax);
          and

     o    other miscellaneous factors ($2 million, after tax).

                                       38
<PAGE>
     The above decreases were partially offset by:

     o    higher competitive retail sales in California by APS Energy Services
          ($5 million, after tax); and

     o    the settlement of an NAC contract dispute involving Maine Yankee
          Atomic Power Company (see Note 12) ($3 million, after tax).

     For additional details, see the following discussion.

                                       39
<PAGE>
     The major factors that increased (decreased) income from continuing
operations were as follows (dollars in millions):

<TABLE>
<CAPTION>
                                                                                   Increase
                                                                                  (Decrease)
                                                                                  ----------
<S>                                                                               <C>
Regulated electricity segment gross margin:
     Increased purchased power and fuel costs due to higher hedged gas
       and power prices                                                            $     (8)
     Higher retail sales volumes due to customer growth, excluding
       weather effects                                                                    7
     Change in mark-to-market for hedged natural gas and purchased
       power costs for future delivery                                                    8
     Effects of milder weather on retail sales                                           (6)
     Retail electricity price reductions effective July 1, 2002                          (5)
     Higher replacement power costs from plant outages due to higher
       market prices and more unplanned outages                                          (4)
                                                                                   --------
          Net decrease in regulated electricity segment gross margin                     (8)
                                                                                   --------
Marketing and trading segment gross margin:
     Increase in generation sales other than Native Load due to
       higher sales volumes, partially offset by lower unit margins                       1
     Lower realized wholesale margins net of related mark-to-market
       reversals due to lower prices, partially offset by higher volumes                (12)
     More competitive retail sales in California by APS Energy Services                   8
     Lower mark-to-market reversals due to the adoption of EITF 02-3                      8
     Lower mark-to-market gains for future delivery due to lower market
       liquidity and higher price volatility                                            (26)
                                                                                   --------
          Net decrease in marketing and trading segment gross margin                    (21)
                                                                                   --------
Net decrease in regulated electricity and marketing and trading segments'
  gross margins                                                                         (29)
Lower real estate segment gross margin primarily due to lower land sales
  (See "Real Estate Activities" below and Note 19)                                       (2)
Higher other gross margin primarily due to NAC's settlement of a contract
  dispute (see Note 12)                                                                   5
Higher operations and maintenance expense related to increased operating
  costs related to the timing of power plant overhauls, increased pension
  and other postretirement benefit costs and new power plants in service                (16)
Higher depreciation primarily related to new power plants and increased
  plant balances, partially offset by lower regulatory asset amortization                (6)
Higher net interest expense primarily due to higher debt balances and lower
  capitalized interest                                                                   (7)
                                                                                   --------
     Net decrease in income from continuing operations before income                    (55)
       taxes
Lower income taxes primarily due to lower income                                         22
                                                                                   --------
     Net decrease in income from continuing operations                             $    (33)
                                                                                   ========
</TABLE>

                                       40
<PAGE>
REGULATED ELECTRICITY SEGMENT GROSS MARGIN

     Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $5 million higher in the three months
ended March 31, 2003, compared with the same period in the prior year as a
result of:

     o    increased revenues related to traditional wholesale sales as a result
          of higher sales volumes and higher prices ($1 million);
     o    increased revenues related to retail load hedge management wholesale
          sales, primarily as a result of higher prices ($3 million);
     o    decreased retail revenues related to milder weather ($11 million);
     o    increased retail revenues related to customer growth, excluding
          weather effects ($14 million);
     o    decreased retail revenues related to a reduction in retail electricity
          prices ($5 million); and
     o    other miscellaneous factors ($3 million, net increase).

     Regulated electricity segment purchased power and fuel costs were $13
million higher in the three months ended March 31, 2003, compared with the same
period in the prior year as a result of:

     o    increased costs related to traditional wholesale sales as a result of
          higher sales volumes and higher prices ($1 million);
     o    increased costs related to retail load hedge management wholesale
          sales, primarily as a result of higher prices ($3 million);
     o    decreased costs related to the effects of milder weather on retail
          sales ($5 million);
     o    increased costs related to retail sales growth, excluding weather
          effects ($7 million);
     o    increased replacement power costs for power plant outages due to
          higher market prices and more unplanned outages ($4 million); and
     o    other miscellaneous factors ($3 million, net increase).

MARKETING AND TRADING SEGMENT GROSS MARGIN

     Marketing and trading segment revenues were $87 million higher in the three
months ended March 31, 2003, compared with the same period in the prior year as
a result of:

     o    increased revenues from generation sales other than Native Load
          primarily due to higher prices and higher sales volumes ($36 million);
     o    higher realized wholesale revenues net of related mark-to-market
          reversals primarily due to higher volumes ($41 million);
     o    increased revenues from higher competitive retail sales in California
          by APS Energy Services ($30 million);
     o    higher revenues related to the adoption of EITF 02-3 ($8 million); and
     o    lower mark-to-market gains for future delivery primarily as a result
          of lower market liquidity and higher price volatility ($28 million).

                                       41
<PAGE>
     Marketing and trading segment purchased power and fuel costs were $108
million higher in the three months ended March 31, 2003, compared to the same
period in the prior year as a result of:

     o    increased fuel costs related to generation sales other than Native
          Load primarily because of higher natural gas prices and higher sales
          volumes ($35 million);
     o    increased purchased power costs related to other realized marketing
          activities in the current period primarily due to higher volumes and
          higher prices ($53 million);
     o    increased purchased power costs related to higher competitive retail
          sales in California by APS Energy Services ($22 million); and
     o    change in mark-to-market fuel costs for future delivery ($2 million
          decrease).

OTHER INCOME STATEMENT ITEMS

     The decrease in real estate segment gross margin of $2 million was
primarily due to lower land sales. In addition, as discussed in "Real Estate
Activities" below and Note 19, SunCor had an $8 million ($5 million after tax)
gain on the sale of its water utility company which was reported as income from
discontinued operations in the three months ended March 31, 2003.

     The increase in other gross margin of $5 million was primarily due to NAC's
settlement of a contract dispute involving Maine Yankee Atomic Power Company.
See Note 12.

     The increase in operations and maintenance expense of $16 million was due
to increased operating costs related to the timing of power plant overhauls,
increased pension and other postretirement benefit costs, new power plants in
service and other costs.

     The increase in depreciation and amortization expense of $6 million
primarily related to increased plant balances and new power plants, partially
offset by lower regulatory asset amortization.

     Net interest expense increased $7 million primarily because of higher debt
balances related to our generation construction program and lower capitalized
interest on our generation construction program due to completion of Redhawk
Units 1 and 2 in mid-2002.

     OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2003 COMPARED WITH
     TWELVE-MONTH PERIOD ENDED MARCH 31, 2002

     Our consolidated net income for the twelve months ended March 31, 2003 was
$121 million compared with $306 million for the prior year. Included in the 2003
period was a $66 million after tax charge for the cumulative effect of a change
in accounting for trading activities for the early adoption of EITF 02-3 on
October 1, 2002 and $14 million of after tax income related to certain
discontinued operations in our real estate segment (see "Real Estate Activities"
below). Included in the 2002 period was a $12 million after tax charge for the
cumulative effect of a change in accounting for derivatives, as required by SFAS
No. 133.

                                       42
<PAGE>
     Our income from continuing operations for the twelve months ended March 31,
2003 was $173 million compared with $317 million for the prior year. The
period-to-period decrease of $144 million was primarily due to:

     o    lower earnings contributions from our marketing and trading
          activities, reflecting lower liquidity and lower price volatility in
          the wholesale power markets in the western United States, partially
          offset by lower mark-to-market reversals due to the adoption of EITF
          02-3 ($104 million, after tax);

     o    losses related to our investment in NAC ($32 million, after tax);

     o    higher operations and maintenance expenses related to the Redhawk
          Units 3 and 4 cancellation charge and 2002 severance costs, partially
          offset by lower generation reliability costs ($32 million, after tax);

     o    higher depreciation, operations and maintenance, and interest expenses
          related to new power plants in service ($27 million, after tax);

     o    higher pension and other postretirement benefit costs ($7 million,
          after tax); and

     o    miscellaneous factors, net ($4 million, after tax).

     The above decreases were partially offset by:

     o    increased earnings contributions from our regulated electricity
          activities, reflecting lower replacement power costs for power plant
          outages, retail customer growth and higher average usage per customer,
          partially offset by the effects of milder weather and retail
          electricity price decreases ($41 million, after tax); and

     o    higher competitive retail sales in California by APS Energy Services
          ($21 million, after tax).

     For additional details, see the following discussion.

                                       43
<PAGE>
     The major factors that increased (decreased) income from continuing
operations were as follows (dollars in millions):

<TABLE>
<CAPTION>
                                                                                   Increase
                                                                                  (Decrease)
                                                                                  ----------
<S>                                                                               <C>
Regulated electricity segment gross margin:
     Lower replacement power costs from plant outages due to lower
       market prices and fewer unplanned outages                                   $     74
     Higher retail sales volumes due to customer growth and higher
       average usage, excluding weather effects                                          43
     Effects of milder weather on retail sales                                          (40)
     Retail electricity price reductions effective July 1, 2001 and July 1, 2002        (27)
     2001 charges related to purchase power contracts with Enron                         13
     Increased purchased power and fuel costs due to higher hedged gas
       and power prices                                                                  (4)
     Change in mark-to-market for hedged natural gas and purchased
       power costs for future delivery                                                   15
     Miscellaneous factors, net                                                          (6)
                                                                                   --------
          Net increase in regulated electricity segment gross margin                     68
                                                                                   --------
Marketing and trading segment gross margin:
     Decrease in generation sales other than Native Load due to
       lower market prices, partially offset by higher sales volumes                    (19)
     Lower realized wholesale margins net of related mark-to-market
       reversals due to lower prices, partially offset by higher volumes                (68)
     More competitive retail sales in California by APS Energy Services                  35
     Lower mark-to-market reversals due to the adoption of EITF 02-3                     16
     Lower mark-to-market gains for future delivery due to lower market
       liquidity and lower price volatility                                            (103)
                                                                                   --------
          Net decrease in marketing and trading segment gross margin                   (139)
                                                                                   --------
Net decrease in regulated electricity and marketing and trading segments'
  gross margins                                                                         (71)
Lower real estate segment gross margin primarily due to commercial and
  property management sales, partially offset by higher home and land sales
  (see "Real Estate Activities" below and Note 19)                                       (4)
Lower other gross margin primarily related to NAC losses (see Note 12)                  (40)
Higher operations and maintenance expense related primarily to a $47 million
  write-off of Redhawk Units 3 and 4 and 2002 severance costs of
  approximately $36 million, partially offset by lower generation
  reliability costs                                                                     (78)
Higher depreciation primarily related to increased plant balances and new
  power plants, partially offset by lower regulatory asset amortization                  (7)
Higher taxes other than income taxes due to increased property taxes on
  higher property balances                                                               (7)
Lower other income primarily due to a 2001 insurance recovery of
  environmental remediation costs                                                       (11)
Higher net interest expense primarily due to higher debt balances and lower
  capitalized interest                                                                  (25)
Miscellaneous factors, net                                                                1
                                                                                   --------
     Net decrease in income from continuing operations before income
       taxes                                                                           (242)
Lower income taxes primarily due to lower income                                         98
                                                                                   --------
     Net decrease in income from continuing operations                             $   (144)
                                                                                   ========
</TABLE>

                                       44
<PAGE>
REGULATED ELECTRICITY SEGMENT GROSS MARGIN

     Regulated electricity segment revenues related to our regulated retail and
wholesale electricity businesses were $512 million lower in the twelve months
ended March 31, 2003, compared with the same period in the prior year as a
result of:

     o    decreased revenues related to traditional wholesale sales as a result
          of lower prices and lower sales volumes ($39 million);
     o    decreased revenues related to retail load hedge management wholesale
          sales, primarily as a result of lower prices and lower sales volumes
          ($449 million);
     o    decreased retail revenues related to milder weather ($63 million);
     o    increased retail revenues related to customer growth and higher
          average usage, excluding weather effects ($67 million);
     o    decreased retail revenues related to reductions in retail electricity
          prices ($27 million); and
     o    other miscellaneous factors ($1 million net decrease).

     Regulated electricity segment purchased power and fuel costs were $580
million lower in the twelve months ended March 31, 2003, compared with the same
period in the prior year as a result of:

     o    decreased costs related to traditional wholesale sales as a result of
          lower prices and lower sales volumes ($39 million);
     o    decreased costs related to retail load hedge management wholesale
          sales, primarily as a result of lower prices and lower sales volumes
          ($445 million);
     o    charges in 2001 related to purchased power contracts with Enron and
          its affiliates ($13 million net decrease);
     o    decrease in mark-to-market for hedged natural gas and purchased power
          costs for future delivery ($15 million);
     o    decreased costs related to the effects of milder weather on retail
          sales ($23 million);
     o    increased costs related to retail sales growth, excluding weather
          effects ($24 million);
     o    decreased replacement power costs for power plant outages due to lower
          market prices and fewer unplanned outages ($74 million); and
     o    miscellaneous factors ($5 million net increase).

MARKETING AND TRADING SEGMENT GROSS MARGIN

     Marketing and trading segment revenues were $56 million lower in the twelve
months ended March 31, 2003, compared with the same period in the prior year as
a result of:

     o    increased revenues from generation sales other than Native Load
          primarily due to higher sales volumes, partially offset by lower
          market prices ($17 million);

                                       45
<PAGE>
     o    lower realized wholesale revenues net of related mark-to-market
          reversals primarily due to lower prices partially offset by higher
          volumes ($112 million);
     o    increased revenues from higher competitive retail sales in California
          by APS Energy Services ($124 million);
     o    higher revenues related to the adoption of EITF 02-3 ($16 million);
          and
     o    lower mark-to-market gains for future delivery primarily as a result
          of lower market liquidity and lower price volatility ($101 million).

     Marketing and trading segment purchased power and fuel costs were $83
million higher in the twelve months ended March 31, 2003, compared to the same
period in the prior year as a result of:

     o    increased fuel costs related to generation sales other than Native
          Load primarily because of higher sales volumes ($36 million);
     o    decreased purchased power costs related to other realized marketing
          activities in the current period primarily due to lower prices
          partially offset by higher volumes ($44 million);
     o    increased purchased power costs related to higher competitive retail
          sales in California by APS Energy Services ($89 million); and
     o    change in mark-to-market fuel costs for future delivery ($2 million
          increase).

OTHER INCOME STATEMENT ITEMS

     The decrease in real estate segment gross margin of $4 million was
primarily due to lower commercial and property management sales partially offset
by higher home and land sales activities. In addition, as discussed in "Real
Estate Activities" below and Note 19, SunCor had a $23 million ($14 million
after tax) gain on the sale of its water utility company and a retail center
which was reported as income from discontinued operations in the twelve months
ended March 31, 2003.

     The decrease in other gross margin of $40 million was primarily due to
losses on El Dorado's investment in NAC. Losses for the twelve month period
ended March 31, 2003 totaled approximately $55 million on a pretax basis and
were primarily related to NAC contracts with two customers ($47 million was
recorded in other gross margin and $8 million was recorded in other expense). We
reversed $5 million of loss reserves in the first quarter of 2003 related to
NAC's contract settlement. We believe we have reserved our exposure with respect
to these contracts in all material respects and, as a result, we consider these
charges to be non-recurring. See Note 12.

     The increase in operations and maintenance expense of $78 million was due
to a $47 million write-off related to the cancellation of Redhawk Units 3 and 4,
severance costs of $36 million related to a 2002 voluntary workforce reduction,
increased pension and other postretirement benefit costs of $12 million and
other costs of $13 million, partially offset by lower costs related to
generation reliability, plant outages and maintenance costs of $30 million.

                                       46
<PAGE>
     The increase in depreciation and amortization expense of $7 million
primarily related to increased plant balances and new power plants, partially
offset by lower regulatory amortization.

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

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

     Net interest expense increased $25 million primarily because of higher debt
balances related to our generation construction program and lower capitalized
interest on our generation construction program due to completion of Redhawk
Units 1 and 2 in mid-2002.

REAL ESTATE ACTIVITIES

     As discussed in our 2002 10-K, we have undertaken an aggressive effort to
accelerate asset sales activities to approximately double SunCor's annual
earnings in 2003 to 2005 compared with the $19 million in earnings recorded in
2002.

     Certain components of SunCor's real estate sales activities, which are
included in the real estate segment, may be required to be reported as
discontinued operations on our Consolidated Statements of Income in accordance
with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets." Among other things, SFAS No. 144 prescribes accounting for discontinued
operations and defines certain real estate activities as discontinued
operations. We adopted SFAS No. 144 effective January 1, 2002 and determined
that activities that would have required discontinued operations reporting in
2002, 2001 and 2000 were immaterial. We currently estimate that 20% to 40% of
SunCor's net income in 2003 will be reported in discontinued operations;
however, this ultimately depends on the specific properties sold.

     In the first quarter of 2003, SunCor sold its water utility company, which
resulted in an after tax gain of $5 million ($8 million pretax). The gain on the
sale and operating income in the current and prior periods are classified as
discontinued operations on our Condensed Consolidated Statements of Income.

     In the second quarter of 2002, SunCor sold a retail center, but maintained
a significant continuing involvement through a management contract. In the first
quarter of 2003, this management contract was canceled. As a result, the gain on
the 2002 sale and the operating income related to this property have been
reclassified as discontinued operations. The income from discontinued operations
of $14 million (after income taxes) in the twelve months ended March 31, 2003
primarily reflects this sale and the sale of the water utility company.

     The following chart provides a summary of SunCor's earnings (after income
taxes) for the three and twelve months ended March 31, 2003 and the comparable
prior periods (dollars in millions):

                                       47
<PAGE>
                                     Three Months Ended     Twelve Months Ended
                                          March 31,               March 31,
                                     ------------------     -------------------
                                      2003        2002       2003         2002
                                     ------      ------     ------       ------
Income from continuing
     operations                      $    1      $    1     $    9       $    4
Income from discontinued
     operations                           5           1         14            1
                                     ------      ------     ------       ------
Net income                           $    6      $    2     $   23       $    5
                                     ======      ======     ======       ======

LIQUIDITY AND CAPITAL RESOURCES

     CAPITAL EXPENDITURE REQUIREMENTS

     The following table summarizes the actual capital expenditures for the
three months ended March 31, 2003 and estimated capital expenditures for the
next three years (dollars in millions):

                                    Three Months             Estimated
                                   Ended March 31,   --------------------------
                                        2003          2003      2004      2005
                                       ------        ------    ------    ------
APS
     Delivery                          $   73        $  273    $  275    $  329
     Generation (a)                        35           123        99       164
     Other                                  1             5         5         5
                                       ------        ------    ------    ------
     Subtotal                             109           401       379       498
Pinnacle West Energy (a) (b)               61           268        31        20
SunCor (c)                                 15            64        23        20
Other (d)                                   5            17        13        14
                                       ------        ------    ------    ------
     Total                             $  190        $  750    $  446    $  552
                                       ======        ======    ======    ======

(a)  As discussed in Note 5 under "APS General Rate Case and Retail Rate
     Adjustment Mechanisms," as part of its 2003 general rate case, APS intends
     to seek rate base treatment of certain power plants in Arizona currently
     owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West
     Phoenix Units 4 and 5 and Saguaro Unit 3).
(b)  See "Capital Resources and Cash Requirements - Pinnacle West Energy" below
     for further discussion of Pinnacle West Energy's generation construction
     program. These amounts do not include an expected reimbursement in 2004 by
     SNWA of about $100 million, assuming SNWA exercises its option to purchase
     a 25% interest in the Silverhawk project at that time.
(c)  Consists primarily of capital expenditures for land development and retail
     and office building construction reflected in the "Change in real estate
     investments" in the Condensed Consolidated Statements of Cash Flows.
(d)  Primarily related to the parent company and APS Energy Services.

     Delivery capital expenditures are comprised of T&D infrastructure additions
and upgrades, capital replacements, new customer construction and related
information systems and facility costs. Examples of the types of projects

                                       48
<PAGE>
included in the forecast include T&D lines and substations, line extensions to
new residential and commercial developments and upgrades to customer information
systems. In addition, APS began several major transmission projects in 2001.
These projects are periodic in nature and are driven by strong regional customer
growth. APS expects to spend about $105 million on major transmission projects
during the 2003 to 2005 time frame, and these amounts are included in
"APS-Delivery" in the table above.

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

     Replacement of the steam generators in Palo Verde Unit 2 is presently
scheduled for completion during the fall outage of 2003. The Palo Verde owners
have approved the manufacture of two additional sets of steam generators. We
expect that these generators will be installed in Units 1 and 3 in the 2005 to
2007 time frame. Our portion of steam generator expenditures for Units 1, 2 and
3 is approximately $145 million, which will be spent from 2003 through 2008. In
2003 through 2005, $94 million of the costs are included in the generation
capital expenditures table above and would be funded with internally-generated
cash or external financings.

     CAPITAL RESOURCES AND CASH REQUIREMENTS

     CONTRACTUAL OBLIGATIONS The following table summarizes actual contractual
requirements for the three months ended March 31, 2003 and estimated contractual
commitments for the next five years and thereafter (dollars in millions):

                                       49
<PAGE>
<TABLE>
<CAPTION>
                                       Actual
                                      --------
                                       Three
                                       Months                              Estimated
                                       Ended     ---------------------------------------------------------------
                                      March 31,                                                          There-
                                        2003       2003       2004       2005       2006       2007      after
                                      --------   --------   --------   --------   --------   --------   --------
<S>                                   <C>        <C>        <C>        <C>        <C>        <C>        <C>
Long-term debt payments:
  APS                                 $     --   $     --   $    205   $    400   $     84   $     --   $  1,518
  Pinnacle West                             --        275        215         --        300         --         --
  SunCor                                    33         --        106         --          3         --          2
  El Dorado                                 --          1          1          1         --         --         --
                                      --------   --------   --------   --------   --------   --------   --------
Total long-term debt payments               33        276        527        401        387         --      1,520
Capital lease payments                       1          5          5          4          3          3          6
Operating lease payments                     5         70         66         64         63         63        478
Purchase power and fuel commitments         64        202         85         28         31         17        162
                                      --------   --------   --------   --------   --------   --------   --------
Total contractual commitments         $    103   $    553   $    683   $    497   $    484   $     83   $  2,166
                                      ========   ========   ========   ========   ========   ========   ========
</TABLE>

     OFF-BALANCE SHEET ARRANGEMENTS

     In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities." FIN No. 46 requires that we consolidate a VIE if we have a
majority of the risk of loss from the VIE's activities or we are entitled to
receive a majority of the VIE's residual returns or both. A VIE is a
corporation, partnership, trust or any other legal structure that either does
not have equity investors with voting rights or has equity investors that do not
provide sufficient financial resources for the entity to support its activities.
FIN No. 46 is effective immediately for any VIE created after January 31, 2003
and is effective July 1, 2003 for VIEs created before February 1, 2003.

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

     APS is exposed to losses under the Palo Verde sale-leaseback agreements
upon the occurrence of certain events that APS does not consider to be
reasonably likely to occur. Under certain circumstances (for example, the NRC
issuing specified violation orders with respect to Palo Verde or the occurrence
of specified nuclear events), APS would be required to assume the debt
associated with the transactions, make specified payments to the equity
participants and take title to the leased Unit 2 interests, which, if
appropriate, may be required to be written down in value. If such an event had
occurred as of March 31, 2003, APS would have been required to assume
approximately $285 million of debt and pay the equity participants approximately
$200 million.

                                       50
<PAGE>
     GUARANTEES

     We and certain of our subsidiaries have issued guarantees and letters of
credit in support of our unregulated businesses. We have also obtained surety
bonds on behalf of APS Energy Services. We have not recorded any liability on
our Condensed Consolidated Balance Sheets with respect to these obligations. See
Note 17 for additional information regarding guarantees.

     CREDIT RATINGS

     The ratings of securities of Pinnacle West and APS as of May 12, 2003 are
shown below and are considered to be "investment-grade" ratings. The ratings
reflect the respective views of the rating agencies, from which an explanation
of the significance of their ratings may be obtained. There is no assurance that
these ratings will continue for any given period of time. The ratings may be
revised or withdrawn entirely by the rating agencies, if, in their respective
judgments, circumstances so warrant. Any downward revision or withdrawal may
adversely affect the market price of Pinnacle West's or APS' securities and
serve to increase those companies' cost of and access to capital. All of
Pinnacle West's and APS' credit ratings remain investment grade.

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

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

OUTLOOK                             Stable          Stable         Negative (a)

(a)  This rating affects all of the above debt ratings with the exception of our
     commercial paper rating.

     DEBT PROVISIONS

     Pinnacle West's and APS' significant debt covenants related to their
respective financing arrangements include a debt-to-total-capitalization ratio
and an interest coverage test. Pinnacle West and APS are in compliance with such
covenants and each anticipates it will continue to meet all the significant
covenant requirement levels. The ratio of debt to total capitalization cannot
exceed 65% for both the Company and APS. At March 31, 2003, the ratios are
approximately 55% and 49% for the parent company and APS, respectively. The
provisions regarding interest coverage require a minimum cash coverage of two
times the interest requirements for both the Company and APS. The coverages are
approximately 4 times for the parent company, 5 times for the APS bank
agreements and 14 times for the APS mortgage indenture. Failure to comply with

                                       51
<PAGE>
such covenant levels would result in an event of default which, generally
speaking, would require the immediate repayment of the debt subject to the
covenants.

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

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

     PINNACLE WEST (PARENT COMPANY)

     Our primary cash needs are for dividends to our shareholders; equity
infusions into our subsidiaries, primarily Pinnacle West Energy; and interest
payments and optional and mandatory repayments of principal on our long-term
debt (see the table above for our contractual requirements, including our debt
repayment obligations, but excluding optional repayments). The level of our
common dividends and future dividend growth will be dependent on a number of
factors including, but not limited to, payout ratio trends, free cash flow and
financial market conditions.

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

     On November 22, 2002, the ACC issued the Interim Financing Order, which
permits APS to (a) make short-term advances to Pinnacle West in the form of an
inter-affiliate line of credit in the amount of $125 million, or (b) guarantee
$125 million of Pinnacle West's short-term debt, subject to certain conditions.
As of March 31, 2003, there were no borrowings outstanding under this financing
arrangement.

     On April 4, 2003, the ACC issued the Financing Order, which permits APS to
lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of
Pinnacle West Energy debt, or a combination of both, not to exceed $500 million
in the aggregate. See "ACC Financing Orders" in Note 5 for additional
information.

     On May 12, 2003, APS issued $500 million of debt as follows: $300 million
aggregate principal amount of its 4.650% Notes due 2015 and $200 million
aggregate principal amount of its 5.625% Notes due 2033. Also on May 12, 2003,
APS made a $500 million loan to Pinnacle West Energy, and Pinnacle West Energy
distributed the net proceeds of that loan to us to fund our repayment of a
portion of the debt incurred to finance the construction of the following
Pinnacle West Energy power plants: Redhawk Units 1 and 2, West Phoenix Units 4
and 5, and Saguaro Unit 3. See "ACC Financing Orders" in Note 5 for additional
information. With Pinnacle West Energy's distribution to us, on May 12, 2003, we
repaid the outstanding balance ($167 million) under a credit facility. We used a
portion of the remaining proceeds to repay our short-term debt, with the balance
being temporarily invested pending the planned optional repayment of our $250
million Floating Rate Notes due 2003.

                                       52
<PAGE>
     As part of a multi-employer pension plan sponsored by Pinnacle West, we
contribute at least the minimum amount required under IRS regulations, but no
more than the maximum tax-deductible amount. The minimum required funding takes
into consideration the value of the fund assets and our pension obligation. We
elected to contribute cash to our pension plan in each of the last five years;
our minimum required contributions during each of those years was zero.
Specifically, we contributed $27 million for 2002, $24 million for 2001, $44
million for 2000, $25 million for 1999 and $14 million for 1998. APS and other
subsidiaries fund their share of the pension contribution, of which APS
represents approximately 90% of the total funding amounts described above. The
assets in the plan are mostly domestic common stocks, bonds and real estate. We
currently forecast a pension contribution in 2003 of approximately $50 million,
all or part of which may be required. If the fund performance continues to
decline as a result of a continued decline in equity markets, larger
contributions may be required in future years.

     APS

     APS' capital requirements consist primarily of capital expenditures and
optional and mandatory redemptions of long-term debt. See "Business Outlook -
Regulatory Matters" below and Notes 4 and 5 for discussion of the $500 million
financing arrangement between APS and Pinnacle West Energy authorized by the ACC
pursuant to the Financing Order and APS' related issuance of $500 million of
debt. See "Pinnacle West (Parent Company)" above and Note 5 for discussion of a
$125 million interim financing arrangement between APS and Pinnacle West.

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

     In March 2003, APS deposited monies with its first mortgage bond trustee to
redeem the entire $33 million of outstanding First Mortgage Bonds, 8% Series due
2025 and the entire $54 million of outstanding First Mortgage Bonds, 7.25%
Series due 2023. On April 7, 2003, APS redeemed $33 million of its First
Mortgage Bonds, 8% Series due 2025. APS will redeem $54 million of its First
Mortgage Bonds, 7.25% Series due 2023, on August 1, 2003.

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

                                       53
<PAGE>
     PINNACLE WEST ENERGY

     The costs of Pinnacle West Energy's construction of generating capacity
from 2000 through 2004 are expected to be about $1.4 billion. This does not
reflect an expected reimbursement in 2004 by SNWA of about $100 million of
Pinnacle West Energy's cumulative capital expenditures in the Silverhawk
project, assuming SNWA exercises its option to purchase a 25% interest in the
project. Pinnacle West Energy is currently funding its capital requirements
through capital infusions from Pinnacle West, which finances those infusions
through debt and equity financings and internally-generated cash. See the
capital expenditures table above for actual capital expenditures in the three
months ended March 31, 2003 and projected capital expenditures for the next
three years.

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

     o    A 650 MW combined cycle expansion of the West Phoenix Power Plant in
          Phoenix. The 120 MW West Phoenix Unit 4 began commercial operation in
          June 2001. The 530 MW West Phoenix Unit 5 is expected to begin
          commercial operation in mid-2003.

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

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

     See Notes 4 and 5 and "Pinnacle West (Parent Company)" above for a
discussion of the $500 million financing arrangement between APS and Pinnacle
West Energy authorized by the ACC pursuant to the Financing Order.

     OTHER SUBSIDIARIES

     During the past three years, SunCor funded its cash requirements with cash
from operations and its own external financings. SunCor's capital needs consist
primarily of capital expenditures for land development and retail and office
building construction. See the capital expenditures table above for actual
capital expenditures in the three months ended March 31, 2003 and projected
capital expenditures for the next three years. SunCor expects to fund its
capital requirements with cash from operations and external financings.

     We expect SunCor to make cash distributions to the parent company of $80 to
$100 million annually in 2003 through 2005 due to anticipated accelerated asset
sales activity. See "Real Estate Activities" above and Note 19.

                                       54
<PAGE>
     El Dorado funded its cash requirements during the past three years,
primarily for NAC in 2002, with cash infused by the parent company and with cash
from operations. El Dorado expects minimal capital requirements over the next
three years.

     APS Energy Services' cash requirements during the past three years were
funded with cash infusions from the parent company. APS Energy Services' capital
expenditures and other cash requirements are increasingly funded by operations,
with some funding from cash infused by Pinnacle West. See the capital
expenditures table above regarding APS Energy Services' actual capital
expenditures for the three months ended March 31, 2003 and projected capital
expenditures for the next three years.

     CRITICAL ACCOUNTING POLICIES

     In preparing the financial statements in accordance with GAAP, management
must often make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses and related disclosures at the date of
the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from
those estimates. Our most critical accounting policies include the impacts of
regulatory accounting and the determination of the appropriate accounting for
our pension and other postretirement benefits, derivatives and mark-to-market
accounting. There have been no changes to our critical accounting policies since
our 2002 10-K except for the discussion contained herein related to SFAS No. 143
(see Note 13). See "Critical Accounting Policies" in Item 7 of the 2002 10-K for
further details about our critical accounting policies.

BUSINESS OUTLOOK

     In this section we discuss a number of factors affecting our business
outlook.

     REGULATORY MATTERS

     See "Electric Industry Restructuring - State" in Note 5 for a discussion of
ACC regulatory matters, including the implementation of the Track B competitive
procurement process and APS' upcoming general rate case.

                                       55
<PAGE>
     WHOLESALE POWER MARKET CONDITIONS

     The marketing and trading division, which we moved to APS in early 2003 for
future marketing and trading activities (existing wholesale contracts will
remain at Pinnacle West) as a result of the ACC's Track A Order prohibiting APS'
transfer of generating assets to Pinnacle West Energy, focuses primarily on
managing APS' purchased power and fuel risks in connection with its costs of
serving retail customer demand. Additionally, the marketing and trading
division, subject to specified parameters, markets, hedges and trades in
electricity, fuels and emission allowances and credits. Our future earnings will
be affected by the strength or weakness of the wholesale power market.

     GENERATION CONSTRUCTION PLAN

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

     FACTORS AFFECTING OPERATING REVENUES

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

     CUSTOMER GROWTH Customer growth in APS' service territory averaged about
3.6% a year for the three years 2000 through 2002; we currently expect customer
growth to average about 3.5% per year from 2003 to 2005. We currently estimate
that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in
2003 through 2005, before the retail effects of weather variations. The customer
and sales growth referred to in this paragraph applies to energy delivery
customers.

     RETAIL RATE REDUCTIONS. As part of the 1999 Settlement Agreement, APS
agreed to a series of annual retail electricity price reductions of 1.5% on July
1 for each of the years 1999 to 2003 for a total of 7.5%. The final price
reduction is to be implemented July 1, 2003. See "1999 Settlement Agreement" in
Note 5 for further information.

     OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS

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

     OPERATIONS AND MAINTENANCE EXPENSES Operations and maintenance expenses are
expected to be affected by sales mix and volumes, power plant additions and

                                       56
<PAGE>
operations, inflation, outages, higher trending pension and other postretirement
benefit costs and other factors. In July 2002, we implemented a voluntary
workforce reduction as part of our cost reduction program. We recorded $36
million before taxes in voluntary severance costs in the second half of 2002.

     DEPRECIATION AND AMORTIZATION EXPENSES Depreciation and amortization
expenses are expected to be affected by net additions to existing utility plant
and other property, changes in regulatory asset amortization and our generation
construction program. West Phoenix Unit 4 was placed in service in June 2001.
Redhawk Units 1 and 2 and the new Saguaro Unit 3 began commercial operations in
July 2002. West Phoenix Unit 5 is expected to be on line in mid-2003 and
Silverhawk is expected to be in service in mid-2004. The regulatory assets to be
recovered under the 1999 Settlement Agreement are currently being amortized as
follows (dollars in millions):

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

     PROPERTY TAXES Taxes other than income taxes consist primarily of property
taxes, which are affected by tax rates and the value of property in-service and
under construction. The average property tax rate for APS, which currently owns
the majority of our property, was 9.7% of assessed value for 2002 and 9.3% for
2001. We expect property taxes to increase primarily due to our generation
construction program and our additions to existing facilities.

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

     RETAIL COMPETITION The regulatory developments and legal challenges to the
Rules discussed in Note 5 have raised considerable uncertainty about the status
and pace of retail electric competition in Arizona. Although some very limited
retail competition existed in APS' service area in 1999 and 2000, there are
currently no active retail competitors providing unbundled energy or other
utility services to APS' customers. As a result, we cannot predict when, and the
extent to which, additional competitors will re-enter APS' service territory.

     SUBSIDIARIES In the case of SunCor, we are undertaking an aggressive effort
to accelerate asset sales activities to approximately double SunCor's annual
earnings in 2003 to 2005 compared to the $19 million in earnings recorded in
2002. A portion of these sales have been, and additional amounts may be required
to be, reported as discontinued operations on the Condensed Consolidated
Statements of Income. See "Real Estate Activities" above and Note 19 for further
discussion.

                                       57
<PAGE>
     The annual earnings contribution from APS Energy Services is expected to be
positive over the next several years due primarily to a number of retail
electricity contracts in California. APS Energy Services' had pretax earnings of
$28 million in 2002.

     El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. In addition, we do not expect material losses for the
year 2003 related to NAC.

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

RISK FACTORS

     Exhibit 99.4, which is hereby incorporated by reference, contains a
discussion of risk factors involving the Company.

FORWARD-LOOKING STATEMENTS

     This document contains forward-looking statements based on current
expectations and we assume no obligation to update these statements or make any
further statements on any of these issues, except as required by applicable law.
Because actual results may differ materially from expectations, we caution
readers not to place undue reliance on these statements. A number of factors
could cause future results to differ materially from historical results or from
results or outcomes currently expected or sought by us. These factors include
the ongoing restructuring of the electric industry, including the introduction
of retail electric competition in Arizona and decisions impacting wholesale
competition; the outcome of regulatory and legislative proceedings relating to
the restructuring; state and federal regulatory and legislative decisions and
actions, including price caps and other market constraints imposed by the FERC;
regional economic and market conditions, including the California energy
situation and completion of generation and transmission construction in the
region, which could affect customer growth and the cost of power supplies; the
cost of debt and equity capital and access to capital markets; weather
variations affecting local and regional customer energy usage; the effect of
conservation programs on energy usage; power plant performance; the successful
completion of our generation construction program; regulatory issues associated
with generation construction, such as permitting and licensing; our ability to
compete successfully outside traditional regulated markets (including the
wholesale market); our ability to manage our marketing and trading activities
and the use of derivative contracts in our business; technological developments
in the electric industry; the performance of the stock market, which affects the
amount of our required contributions to our pension plan and nuclear
decommissioning trust funds; the strength of the real estate market in SunCor's
market areas, which include Arizona, New Mexico and Utah; and other
uncertainties, all of which are difficult to predict and many of which are
beyond our control.

ITEM 3. MARKET RISKS

     Our operations include managing market risks related to changes in interest
rates, commodity prices and investments held by the nuclear decommissioning
trust fund and our pension plans.

                                       58
<PAGE>
COMMODITY PRICE RISK

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

     We adopted the EITF 02-3 guidance for all contracts in the fourth quarter
of 2002. Our energy trading contracts that are derivatives are accounted for at
fair value under SFAS No. 133. Contracts that do not meet the definition of a
derivative are accounted for on an accrual basis with the associated revenues
and costs recorded at the time the contracted commodities are delivered or
received. Additionally, all gains and losses (realized and unrealized) on energy
trading contracts that qualify as derivatives are included in marketing and
trading segment revenues on the Condensed Consolidated Statements of Income on a
net basis. Derivative instruments used for non-trading activities are accounted
for in accordance with SFAS No. 133. See Note 10 for details on the change in
accounting for energy trading contracts.

     Both non-trading and trading derivatives are classified as assets and
liabilities from risk management and trading activities in the Condensed
Consolidated Balance Sheets. For non-trading derivative instruments that qualify
for hedge accounting treatment, changes in the fair value of the effective
portion are recognized in common stock equity (as a component of accumulated
other comprehensive income (loss)). Non-trading derivatives, or any portion
thereof, that are not effective hedges are adjusted to fair value through
income. Gains and losses related to non-trading derivatives that qualify as cash
flow hedges of expected transactions are recognized in revenue or purchased
power and fuel expense as an offset to the related item being hedged when the
underlying hedged physical transaction impacts earnings. If it becomes probable
that a forecasted transaction will not occur, we discontinue the use of hedge
accounting and recognize in income the unrealized gains and losses that were
previously recorded in other comprehensive income (loss). In the event a
non-trading derivative is terminated or settled, the unrealized gains and losses
remain in other comprehensive income (loss) and are recognized in income when
the underlying transaction impacts earnings.

     Derivatives associated with trading activities are adjusted to fair value
through income. Derivative commodity contracts for the physical delivery of
purchase and sale quantities transacted in the normal course of business are
exempt from the requirements of SFAS No. 133 under the normal purchase and sales
exception and are not reflected on the balance sheet at fair value. Most of our
non-trading electricity purchase and sales agreements qualify as normal
purchases and sales and are exempted from recognition in the financial
statements until the electricity is delivered.

                                       59
<PAGE>
     Our assets and liabilities from risk management and trading activities are
presented in two categories consistent with our business segments:

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

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

     The following tables show the changes in mark-to-market of our system and
marketing and trading derivative positions for the three months ended March 31,
2003 and 2002 (dollars in millions):

<TABLE>
<CAPTION>
                                    Three Months Ended        Three Months Ended
                                      March 31, 2003            March 31, 2002
                                  ----------------------    ----------------------
                                              Marketing                 Marketing
                                   System    and Trading     System    and Trading
                                  --------   -----------    --------   -----------
<S>                               <C>          <C>          <C>          <C>
Mark-to-market of net
  positions at beginning
  of period                       $    (49)    $     57     $   (107)    $    138
Change in mark-to-market
  gains (losses) for future
  period deliveries                      5           (8)          (1)          25
Changes in cash flow hedges
  recorded in OCI                       13           13           44           --
Ineffective portion of changes
  in fair value recorded in
  earnings                               2            1           (2)          --
Mark-to-market losses/(gains)
  realized during the period             6           (7)           5          (22)
                                  --------     --------     --------     --------
Mark-to-market of net
  positions at end of period      $    (23)    $     56     $    (61)    $    141
                                  ========     ========     ========     ========
</TABLE>

     The Company no longer reports non-derivative energy contracts or physical
inventories at fair value. Since July 1, 2002, the Company has not recognized a
dealer profit or unrealized gain or loss at the inception of a derivative unless
the fair value of that instrument (in its entirety) is evidenced by quoted
market prices or current market transactions. Prior to the change in our policy,
we recorded net gains at inception of $8 million in the three months ended March
31, 2002. These amounts included a reasonable marketing margin. No net gains at
inception were recorded in the three months ended March 31, 2003.

     The tables below show the maturities of our system and marketing and
trading derivative positions at March 31, 2003 by the type of valuation that is
performed to calculate the fair value of the contract (dollars in millions). See
"Critical Accounting Policies - Mark-to-Market Accounting" in Item 7 of our 2002
10-K for more discussion on our valuation methods.

                                       60
<PAGE>
<TABLE>
<CAPTION>
SYSTEM
                                                                                                 Total
                                                                                     Years       fair
Source of Fair Value      2003        2004        2005        2006        2007     thereafter    value
--------------------    --------    --------    --------    --------    --------   ----------   --------
<S>                     <C>         <C>         <C>         <C>         <C>         <C>         <C>
Prices actively
  quoted                $     --    $    (11)   $     --    $     --    $     --    $     --    $    (11)
Prices provided by
  other external
  sources                     (3)         (9)         --          --          --          --         (12)
Prices based on
  models and other
  valuation methods           --          --          --          --          --          --          --
                        --------    --------    --------    --------    --------    --------    --------
Total by maturity       $     (3)   $    (20)   $     --    $     --    $     --    $     --    $    (23)
                        ========    ========    ========    ========    ========    ========    ========
</TABLE>

MARKETING AND TRADING

<TABLE>
<CAPTION>
                                                                                                 Total
                                                                                     Years       fair
Source of Fair Value      2003        2004        2005        2006        2007     thereafter    value
--------------------    --------    --------    --------    --------    --------   ----------   --------
<S>                     <C>         <C>         <C>         <C>         <C>         <C>         <C>
Prices actively
  quoted                $     19    $      4    $      6    $      4    $      3    $      7    $     43
Prices provided by
  other external
  sources                     (4)         11           4          (4)         --          --           7
Prices based on
  models
  and other valuation
  methods                     (3)          2           1           8           3          (5)          6
                        --------    --------    --------    --------    --------    --------    --------
Total by maturity       $     12    $     17    $     11    $      8    $      6    $      2    $     56
                        ========    ========    ========    ========    ========    ========    ========
</TABLE>

     The table below shows the impact  hypothetical price movements of 10% would
have  on the  market  value  of our  risk  management  and  trading  assets  and
liabilities  included on the Condensed  Consolidated Balance Sheets at March 31,
2003 and 2002 (dollars in millions).

                                       61
<PAGE>
<TABLE>
<CAPTION>
                                           March 31, 2003           March 31, 2002
                                             Gain (Loss)              Gain (Loss)
                                       ----------------------    ----------------------
                                       Price Up    Price Down    Price Up    Price Down
Commodity                                 10%          10%          10%          10%
---------                              --------    ----------    --------    ----------
<S>                                     <C>          <C>          <C>          <C>
  Mark-to-market changes
    reported in earnings (a):
    Electricity                         $    --      $     1      $    (2)     $     2
    Natural gas                              (3)           3           (1)           1
    Other                                     1           --            1           (1)
  Mark-to-market changes
    reported in OCI (b):
    Electricity                              32          (32)          --           --
    Natural gas                              23          (22)          26          (24)
                                        -------      -------      -------      -------
    Total                               $    53      $   (50)     $    24      $   (22)
                                        =======      =======      =======      =======
</TABLE>

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

CREDIT RISK

     We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We have risk management and trading contracts with many
counterparties, including two counterparties for which a worst case exposure
represents approximately 40% of our $207 million of risk management and trading
assets as of March 31, 2003. Our risk management process assesses and monitors
the financial exposure of these and all other counterparties. Despite the fact
that the great majority of trading counterparties are rated as investment grade
by the credit rating agencies, including the counterparties noted above, there
is still a possibility that one or more of these companies could default,
resulting in a material impact on consolidated earnings for a given period.
Counterparties in the portfolio consist principally of major energy companies,
municipalities and local distribution companies. We maintain credit policies
that we believe minimize overall credit risk to within acceptable limits.
Determination of the credit quality of our counterparties is based upon a number
of factors, including credit ratings and our evaluation of their financial
condition. In many contracts, we employ collateral requirements and standardized
agreements that allow for the netting of positive and negative exposures
associated with a single counterparty. Valuation adjustments are established
representing our estimated credit losses on our overall exposure to
counterparties. See "Critical Accounting Policies - Mark-to Market Accounting"
in Item 7 of our 2002 10-K for more discussion on our valuation methods.

                                       62
<PAGE>
ITEM 4. CONTROLS AND PROCEDURES

     As of a date within 90 days of the date of this report (the "Evaluation
Date"), we carried out an evaluation, under the supervision and with the
participation of our management, including our Chief Executive Officer, and our
Senior Vice President and Chief Financial Officer, of the effectiveness of the
design and operation of our disclosure controls and procedures, as defined in
Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934, as amended
(the "Exchange Act"). Based upon this evaluation, our Chief Executive Officer,
and our Senior Vice President and Chief Financial Officer, concluded that, as of
the Evaluation Date, our disclosure controls and procedures were adequate to
ensure that information required to be disclosed by us in the reports filed or
submitted by us under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the SEC's rules and forms.

     There were no significant changes in our internal controls or in other
factors that could significantly affect these controls subsequent to the date of
the evaluation, including any corrective actions with regard to significant
deficiencies and internal weaknesses.

                                       63
<PAGE>
                           PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

     See Note 12 of Notes to Condensed Consolidated Financial Statements in Part
1, Item 1 of this report for a discussion of the settlement of the NAC
litigation.

ITEM 5. OTHER INFORMATION

CONSTRUCTION AND FINANCING PROGRAMS

     See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
a discussion of construction and financing programs of the Company and its
subsidiaries.

REGULATORY MATTERS

     See Note 5 of Notes to Condensed Consolidated Financial Statements in Part
I, Item 1 of this report for a discussion of regulatory developments.

ENVIRONMENTAL MATTERS

     The EPA had previously advised APS that the EPA considers APS to be a
"potentially responsible party" in the Indian Bend Wash Superfund Site, South
Area. See "Environmental Matters - Superfund" in Part I, Item 1 of the 2002
10-K. APS, the EPA, the United States Department of Justice, the Attorney
General for the State of Arizona, and ADEQ have reached an agreement (in the
form of a Consent Decree) to settle this matter. UNITED STATES OF AMERICA AND
STATE OF ARIZONA, EX REL. V. ARIZONA PUBLIC SERVICE COMPANY, Civil Action No.
CIV03-767PHXPGR, In the United States District Court for the District of
Arizona. Under the terms of the proposed Consent Decree, APS will pay $2.72
million. Following the expiration of a thirty (30) day comment period, the
Department of Justice will move for the Consent Decree to be approved by the
Court, if appropriate in light of any public comment.

                                       64
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

     (a)  Exhibits

          Exhibit No.    Description
          -----------    -----------
             10.1        Employment Agreement dated February 27, 2003 between
                         APS and James M. Levine

             10.2        Third Supplemental Indenture dated as of November 1,
                         2002

             10.3        Third Amendment to the Pinnacle West Capital
                         Corporation, Arizona Public Service Company, SunCor
                         Development Company and El Dorado Investment Company
                         Deferred Compensation Plan

             12.1        Ratio of Earnings to Fixed Charges

             99.1        Certification of William J. Post, the Registrant's
                         principal executive officer, pursuant to Section 906
                         of the Sarbanes-Oxley Act of 2002

             99.2        Certification of Donald E. Brandt, the Registrant's
                         principal financial officer, pursuant to Section 906
                         of the Sarbanes-Oxley Act of 2002

             99.3        ACC Decision No. 65796 dated April 4, 2003 (Financing
                         Order)

             99.4        Pinnacle West Risk Factors

                                       65
<PAGE>
     In addition, 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>
                                                Originally Filed                          Date
Exhibit No.     Description                        as Exhibit:          File No.(a)     Effective
-----------     -----------                        -----------          -----------     ---------
<S>             <C>                           <C>                         <C>            <C>
3.1             Articles of Incorporation     19.1 to the Company's       1-8962         11-14-88
                restated as of July 29,       September 30, 1988
                1988                          Form 10-Q Report
</TABLE>

----------
(a)  Reports filed under File No. 1-8962 were filed in the office of the
     Securities and Exchange Commission located in Washington, D.C.

<TABLE>
<S>             <C>                           <C>                         <C>            <C>
3.2             Bylaws, amended as of         3.1 to the Company's        1-8962         11-14-02
                September 18, 2002            September 30, 2002
                Form 10-Q Report
</TABLE>

     (b)  Reports on Form 8-K

     During the quarter ended March 31, 2003, and the period from April 1
through May 14, 2003, we filed the following reports on Form 8-K:

     Report dated December 31, 2002 regarding an ACC ALJ's recommended Track B
order and exhibits comprised of financial information and earnings variance
explanations.

     Report dated January 15, 2003 regarding NAC losses and Pinnacle West's
earnings outlook.

     Report dated February 27, 2003 regarding the ACC Track B decision.

     Report dated March 11, 2003 regarding an ACC ALJ's recommended approval,
subject to certain conditions, of APS' financing application.

     Report dated March 27, 2003, regarding ACC approval of the financing
application.

     Report dated March 31, 2003 containing exhibits comprised of financial
information, earnings variance explanations and an earnings news release.

     Report dated May 6, 2003 regarding the Track B Order and asset retirement
obligations.

     Report dated May 13, 2003 comprised of slides presented at analyst
meetings.

                                       66
<PAGE>
                                   SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the
Company has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

                                        PINNACLE WEST CAPITAL CORPORATION
                                        (Registrant)


Dated: May 14, 2003                     By: Donald E. Brandt
                                            ------------------------------------
                                            Donald E. Brandt
                                            Senior Vice President and Chief
                                            Financial Officer
                                            (Principal Financial Officer
                                            and Officer Duly Authorized
                                            to sign this Report)

                  CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

CERTIFICATIONS

I, William J. Post, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pinnacle West Capital
Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the period presented in this quarterly report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

                                       67
<PAGE>
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: May 14, 2003.

                                        William J. Post
                                        ----------------------------------------
                                        William J. Post
                                        Title: Chairman of the Board and Chief
                                               Executive Officer

                  CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

CERTIFICATIONS

I, Donald E. Brandt, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pinnacle West Capital
Corporation;

                                       68
<PAGE>
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the period presented in this quarterly report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: May 14, 2003.

                                        Donald E. Brandt
                                        ----------------------------------------
                                        Donald E. Brandt
                                        Title: Senior Vice President and Chief
                                               Financial Officer

                                       69

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.1
<SEQUENCE>3
<FILENAME>ex10-1.txt
<DESCRIPTION>EMPLOYMENT AGREEMENT - LEVINE
<TEXT>
                                                                    Exhibit 10.1

February 27, 2003

Jim Levine
4817 N. Greentree Dr. E.
Litchfield Park, AZ  85340

Dear Jim:

As a  supplement  to your  Employment  Agreement  dated  October  11,  2002  the
following  clarifies the benefit items that the Pinnacle West Board has approved
for you:

     o    Pension - Add 5 years of service  effective 1/2002 and each subsequent
          year 3% will be added to the  percent of average  monthly  wage you'll
          receive until the 70% benefit is reached:

          -    18  years of  service  in 2002  (3%x10  - 30% + 2%x8 = 16%),  46%
               pension benefit

          -    2002     +5 years at 2%     46%
          -    2002     +3%                49%
          -    2003     +3%                52%
          -    2004     +3%                55%  age 55
          -    2005     +3%                58%
          -    2006     +3%                61%
          -    2007     +3%                64%
          -    2008     +3%                67%
          -    2009     +3%                70%  age 60

     o    Additional  years of service will count towards the percentage of your
          premium costs for retiree medical coverage.

If you have any questions, please feel free to contact me.

                                        Sincerely,

                                        William J. Post

WP/DO/ch
cc: Armando Flores

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.2
<SEQUENCE>4
<FILENAME>ex10-2.txt
<DESCRIPTION>3RD SUPPLEMENTAL INDENTURE DTD 11/1/02
<TEXT>
                                                                    Exhibit 10.2

                         ARIZONA PUBLIC SERVICE COMPANY

                                       TO

                              THE BANK OF NEW YORK

                                     TRUSTEE



                          Third Supplemental Indenture

                          Dated as of November 1, 2002

                                       To

                                    Indenture

                          Dated as of November 15, 1996



              5.05% Senior Notes (Maricopa 2002 Series A) Due 2029
<PAGE>
     THIRD SUPPLEMENTAL INDENTURE, dated as of November 1, 2002, between Arizona
Public Service Company, a corporation duly organized and existing under the laws
of the State of Arizona  (herein  called the  "Company"),  having its  principal
office at 400 North Fifth Street,  Phoenix,  Arizona 85004,  and The Bank of New
York, a New York banking  corporation,  as Trustee (herein called the "Trustee")
under the  Indenture  dated as of November  15, 1996 between the Company and the
Trustee (the "Indenture").

                             RECITALS OF THE COMPANY

     The Company has  executed  and  delivered  the  Indenture to the Trustee to
provide for the issuance  from time to time of its Senior  Notes (the  "Notes"),
said Notes to be issued in one or more series as in the Indenture provided.

     The Company  has  executed  and  delivered  to the  Trustee two  indentures
supplemental  to the Indenture,  the First  Supplemental  Indenture  dated as of
November 15, 1996, and the Second  Supplemental  Indenture  dated as of April 1,
1997 (collectively, the "Supplemental Indentures").

     Pursuant to the terms of the Indenture,  the Company desires to provide for
the  establishment  of a new series of its Notes to be known as its 5.05% Senior
Notes  (Maricopa  2002  Series A) Due 2029  (herein  called the "Series A Senior
Notes"),  the form and  substance  of such Series A Senior  Notes and the terms,
provisions,  and conditions thereof to be set forth as provided in the Indenture
and this Third Supplemental Indenture.

     The Company has entered into a Loan Agreement, dated as of November 1, 2002
(as amended  from time to time,  the "Loan  Agreement")  between the Company and
Maricopa County,  Arizona Pollution Control Corporation (the "Issuer"),  and the
Issuer has issued the Maricopa County,  Arizona  Pollution  Control  Corporation
Pollution  Control Revenue  Refunding Bonds (Arizona Public Service Company Palo
Verde  Project) 2002 Series A in the aggregate  principal  amount of $90,000,000
(the "Series A Pollution  Control Bonds") under that certain Indenture of Trust,
dated as of  November  1,  2002 (as  amended  from time to time,  the  "Maricopa
Indenture")  between the Issuer and The Bank of New York,  as Trustee  (together
with its  successors in such  capacity,  the "Maricopa  Trustee") and loaned the
proceeds  thereof to the Company  (the  "Loan") to pay a portion of the costs of
refunding through  redemption of $45,000,000  aggregate  principal amount of the
Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue
Refunding  Bonds (Arizona Public Service Company Palo Verde Project) 1994 Series
A and $45,000,000  aggregate  principal amount of the Maricopa  County,  Arizona
Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona
Public Service Company Palo Verde Project) 1994 Series B.

     All things  necessary  to make this Third  Supplemental  Indenture  a valid
agreement of the Company,  and to make the Series A Senior Notes,  when executed
by the  Company  and  authenticated  and  delivered  by the  Trustee,  the valid
obligations of the Company, have been done.

          NOW, THEREFORE, THIS THIRD SUPPLEMENTAL INDENTURE WITNESSETH:

     For and in  consideration  of the premises and the purchase of the Series A
Senior Notes by the Holders  thereof,  and for the purpose of setting forth,  as
provided in the  Indenture,  the form and substance of the Series A Senior Notes

<PAGE>
and the terms,  provisions,  and conditions  thereof, it is mutually agreed, for
the equal and proportionate benefit of all Holders of the Series A Senior Notes,
as follows:

                                   ARTICLE ONE

                         GENERAL TERMS AND CONDITIONS OF
                            THE SERIES A SENIOR NOTES

     SECTION  101.  There  shall be and is hereby  authorized  a series of Notes
designated  the "5.05% Senior Notes  (Maricopa 2002 Series A) Due 2029," limited
in aggregate principal amount to $90,000,000, which amount shall be as set forth
in any  Company  Order for the  authentication  and  delivery of Series A Senior
Notes. The Series A Senior Notes shall mature and the principal shall be due and
payable  together with all accrued and unpaid interest  thereon  (subject to the
provisions for prior redemption  hereinafter set forth) on May 1, 2029, shall be
issued in certificated  form, in the form of a single fully registered  Series A
Senior Note without coupons, and shall be registered in the name of the Maricopa
Trustee.

     SECTION 102.  Subject to the provisions  herein,  the Series A Senior Notes
shall bear  interest  from  November  1, 2002 or from the most  recent  Interest
Payment Date (as defined  below) to which  interest has been paid at the rate of
5.05% per annum  (calculated  on the  basis of a 360-day  year of twelve  30-day
months), payable on May 1 and November 1 of each year (each an "Interest Payment
Date"), commencing May 1, 2003, to the holders thereof of record on the April 15
or October 15, as the case may be, next preceding such Interest Payment Date.

     Notwithstanding  the above,  to the extent  required  in Section 4.2 of the
Loan  Agreement at any time,  all payments of interest on each Interest  Payment
Date and of principal on the maturity date of the Series A Senior Notes shall be
due and payable not less than two (2) Business  Days (as defined in the Maricopa
Indenture) prior to each such Interest Payment Date and such maturity date.

     SECTION  103.  The  principal  of and interest on the Series A Senior Notes
shall be payable by the Company to the Maricopa  Trustee as pledgee and assignee
of the Issuer,  at the designated  office of the Maricopa  Trustee,  which shall
initially  be in the City of New York,  in such coin or  currency  of the United
States of America as, at the  respective  times of payment,  is legal tender for
payment of public and private debts.

     SECTION 104. The Company  shall have no  obligation  to make  payments with
respect to the principal and/or interest on the Series A Senior Notes unless and
until,  and only to the extent that,  payments shall be due and payable pursuant
to the Series A Pollution  Control Bonds.  Any provision  hereof to the contrary
notwithstanding,  the Company shall receive a credit  against its  obligation to
make any payment of interest on the Series A Senior  Notes in an amount equal to
the amount, if any, held by the Maricopa Trustee under the Maricopa Indenture on
deposit in the Bond Fund (as defined in the Maricopa Indenture) and available to
make the  corresponding  payment on the Series A  Pollution  Control  Bonds.  In
addition,  the Company shall receive a credit against its obligation to make any
payment of principal  of the Series A Senior  Notes,  whether at maturity,  upon
redemption or otherwise,  in an amount equal to the amount,  if any, held by the

                                       2
<PAGE>
trustee under the Maricopa  Indenture on deposit in said Bond Fund and available
to make the corresponding payment on the Series A Pollution Control Bonds.

     SECTION  105.  In the manner and with the effect  provided in Article 12 of
the Indenture,  the Series A Senior Notes will be subject to redemption prior to
maturity, as follows:

     (a) Series A Senior  Notes are subject to  redemption  prior to maturity in
whole  or in  part,  by lot,  at any  time at a  redemption  price  equal to the
principal  amount thereof plus accrued  interest to the redemption  date, in the
event of the exercise by the Company of its rights to prepay the Loan in full or
in part in accordance with Section 7.2 of the Loan Agreement upon the occurrence
of any of certain  extraordinary  events specified in Section  4.01(a)(1) of the
Maricopa Indenture.

     (b) Series A Senior  Notes are subject to  redemption  prior to maturity in
whole or in part, by lot, on any date on or after November 1, 2012, in the event
of the  exercise  by the  Company of its rights to prepay the Loan in full or in
part in accordance with Section 7.2 of the Loan Agreement and Section 4.01(a)(2)
of the  Maricopa  Indenture at 100% of the  principal  amount of Series A Senior
Notes to be  redeemed,  together  with  accrued  interest  to the date fixed for
redemption

     (c) Series A Senior Notes shall also be  redeemable,  in whole at any time,
prior to maturity by the  application of cash delivered to or deposited with the
Trustee in the event of the  exercise by the Company of its rights to prepay the
Loan in full in  accordance  with Section 7.2 of the Loan  Agreement and Section
4.01(a)(3) of the Maricopa  Indenture,  pursuant to the provisions of Section 87
of the First  Mortgage  (but only if and to the extent such  Section is properly
applicable to bona fide  transactions),  at the principal amount of the Series A
Senior Notes to be redeemed together with accrued interest to the date fixed for
redemption.

     (d) Series A Senior  Notes are  subject to  mandatory  redemption  prior to
maturity  in  whole or in  part,  by lot,  at a  redemption  price  equal to the
principal  amount thereof plus accrued  interest to the redemption date upon the
mandatory  prepayment of the Loan in full or in part in accordance  with Section
7.3 of the Loan Agreement  upon the  occurrence of any of certain  extraordinary
events specified in Section 4.01(b) of the Maricopa Indenture.

     Any notice  given  under the  provisions  of Section  4.03 of the  Maricopa
Indenture  with respect to redemption of all or a part of the Series A Pollution
Control  Bonds  or  Section  7.5 of  the  Loan  Agreement  with  respect  to the
prepayment of all or a part of the Loan will also constitute  sufficient  notice
of the redemption of an amount of the Series A Senior Notes corresponding to the
amount of the Series A Pollution Control Bonds to be redeemed.

     SECTION 106. In all cases that Series A Senior Notes are redeemed  pursuant
to the provisions set forth above, the principal amount of Series A Senior Notes
to be redeemed  shall equal the principal  amount of Series A Pollution  Control
Bonds  concurrently  redeemed  and all  applicable  provisions  of the  Maricopa
Indenture and the Loan Agreement shall be satisfied.

     SECTION 107. The  cancellation  by the Maricopa  Trustee under the Maricopa
Indenture  of Series A Pollution  Control  Bonds  purchased by the Company or of
Series A Pollution Control Bonds redeemed or purchased by the Issuer, with funds

                                       3
<PAGE>
other than payments on Series A Senior  Notes,  shall  constitute  payment of an
amount of the Series A Senior  Notes held by the Maricopa  Trustee  equal to the
aggregate  principal amount of the Series A Pollution Control Bonds so purchased
or redeemed and cancelled.  The Maricopa Trustee is required pursuant to Section
4.05 of the Maricopa  Indenture to notify the Trustee of any such  cancellation,
and,  notwithstanding  the  provisions  of Section  1207 of the  Indenture,  the
Maricopa  Trustee under the Maricopa  Indenture  shall promptly make notation on
the Series A Senior Notes held by it of such  reduction of the principal  amount
thereof.

     SECTION  108.  Upon  payment of the  principal  of and  interest due on the
Series A Pollution  Control  Bonds,  whether at maturity or prior to maturity by
redemption or otherwise,  or upon provision for the payment  thereof having been
made in  accordance  with Article X of the Maricopa  Indenture,  Series A Senior
Notes in a principal  amount equal to the principal amount of Series A Pollution
Control  Bonds so paid or for which such  provision  for  payment  has been made
shall be deemed fully paid,  satisfied and discharged and the obligations of the
Company  thereunder  shall be terminated and such Series A Senior Notes shall be
surrendered to and cancelled by the Trustee.


     SECTION 109. All payments by the Company on the Series A Senior Notes shall
be made at or prior to the opening of business on the due date  thereof.  If the
date for making any payment on the Loan provided in the Loan Agreement is a date
other than the due date for a payment of  principal  or interest on the Series A
Pollution Control Bonds, as described in Section 4.2 of the Loan Agreement,  the
"due  date"  hereunder  will be the date  payment  on the Loan is due under said
Section 4.2.

     SECTION 110. No Series A Senior  Notes shall be issued  except to evidence,
secure and provide for the repayment of the Loan and interest thereon.

     SECTION  111.  Series A Senior  Notes  shall be  nonnegotiable  and will be
nontransferable  except as required to effect assignment to the Maricopa Trustee
under the Maricopa Indenture and to any successor trustee  thereunder.  Upon the
appointment  of a successor  trustee under the Maricopa  Indenture,  the Trustee
shall  authenticate  and the Company  shall issue in the name of said  successor
trustee a new fully registered  Series A Senior Note in the amount of the unpaid
principal amount of the Series A Senior Notes then outstanding, and the Series A
Senior  Notes held by the Maricopa  Trustee who has resigned or been  discharged
shall be surrendered to, and cancelled by, the Trustee.

     The Maricopa  Trustee,  as the holder of the Series A Senior  Notes,  shall
attend  meetings of  bondholders  under the Senior Note Indenture or deliver its
proxy in connection  therewith.  Either at such meeting,  or otherwise  when the
consent of the holders of the  Company's  senior  notes  issued under the Senior
Note Indenture is sought without a meeting,  the Maricopa  Trustee shall vote as
the holder of the Series A Senior Notes, or shall consent with respect  thereto;
PROVIDED,  HOWEVER,  that the  Maricopa  Trustee  shall not vote in favor of, or
consent to, any  modification  of the Senior Note Indenture which is correlative
to a modification  of the Maricopa  Indenture or the Loan Agreement  which would
require the approval of owners of Series A Pollution  Control  Bonds without the

                                       4
<PAGE>
approval  of the  owners of Series A  Pollution  Control  Bonds  which  would be
required for such  correlative  modification of such Maricopa  Indenture or Loan
Agreement.

     SECTION 112. Series A Senior Notes acquired by the Company and submitted to
the Trustee for  cancellation,  or redeemed,  or paid at maturity by the Company
shall forthwith be cancelled by the Trustee.

     SECTION 113. The related series of Senior Note First Mortgage Bonds for the
Series A Senior Notes is the Company's First Mortgage Bonds, Senior Notes Series
C (the "Senior Note Series C Bonds").

     SECTION  114.  When the  obligation  of the Company to make  payments  with
respect to the  principal  of and interest on all or any part of the Senior Note
Series C Bonds shall be satisfied or deemed satisfied pursuant to Section 403 or
Section  501  of the  Indenture  or  pursuant  to  Section  105  of  this  Third
Supplemental  Indenture,  the Trustee shall, upon written request of the Company
and, if applicable,  the receipt of the  certificate of the Expert  described in
Section 404(b) of the Indenture (if such certificate is then required by Section
404(b) of the Indenture),  deliver to the Company without charge therefor all of
the Senior Note Series C Bonds so satisfied or deemed  satisfied,  together with
such  appropriate  instruments  of  transfer  or  release  as may be  reasonably
requested  by the  Company.  All Senior  Note  Series C Bonds  delivered  to the
Company in accordance with this Section 114 shall be delivered by the Company to
the First Mortgage Trustee for cancellation.

                                   ARTICLE TWO

                              ADDITIONAL COVENANTS

     SECTION  201. (a) From and after the Release Date and so long as any Series
A Senior Note is Outstanding,  the Company will not issue,  assume, or guarantee
any Debt secured by any mortgage,  security  interest,  pledge,  or lien (herein
referred to as a "mortgage")  of or upon any Operating  Property of the Company,
whether owned at the date of the Indenture or thereafter acquired,  and will not
permit to exist any Debt secured by a mortgage on any Operating Property created
on or prior to the Release Date, without in any such case effectively  securing,
on the later to occur of the issuance, assumption, or guarantee of any such Debt
or the Release Date, the  Outstanding  Series A Senior Notes  (together with, if
the Company shall so  determine,  any other Note or Debt of or guaranteed by the
Company  ranking senior to, or equally with, the Notes) equally and ratably with
such Debt; provided,  however, that the foregoing restriction shall not apply to
Debt secured by any of the following:

     (1)  mortgages on any property existing at the time of acquisition thereof;

     (2)  mortgages  on  property  of a  corporation  existing  at the time such
          corporation is merged into or consolidated with the Company, or at the
          time of a sale,  lease, or other disposition of the properties of such
          corporation or a division  thereof as an entirety or  substantially as

                                       5
<PAGE>
          an entirety to the Company, provided that such mortgage as a result of
          such merger,  consolidation,  sale, lease, or other disposition is not
          extended to property owned by the Company immediately prior thereto;

     (3)  mortgages on property to secure all or part of the cost of  acquiring,
          constructing,  developing,  or substantially  repairing,  altering, or
          improving such property, or to secure indebtedness incurred to provide
          funds for any such purpose or for  reimbursement  of funds  previously
          expended for any such purpose,  provided such mortgages are created or
          assumed  contemporaneously with, or within eighteen (18) months after,
          such  acquisition  or  completion  of  construction,  development,  or
          substantial  repair,  alteration,  or  improvement  or within  six (6)
          months thereafter pursuant to a commitment for financing arranged with
          a lender or investor within such eighteen (18) month period;

     (4)  mortgages  in favor of the  United  States  of  America  or any  State
          thereof,  or any department,  agency, or  instrumentality or political
          subdivision of the United States of America or any State  thereof,  or
          for the benefit of holders of securities issued by any such entity, to
          secure any Debt  incurred for the purpose of financing all or any part
          of the  purchase  price or the cost of  constructing,  developing,  or
          substantially  repairing,  altering, or improving the property subject
          to such mortgages; or

     (5)  any  extension,  renewal or  replacement  (or  successive  extensions,
          renewals,  or  replacements),  in whole or in  part,  of any  mortgage
          referred to in the foregoing clauses (1) to (4), inclusive;  provided,
          however,  that the  principal  amount of Debt secured  thereby and not
          otherwise authorized by said clauses (1) to (4), inclusive,  shall not
          exceed the principal  amount of Debt,  plus any premium or fee payable
          in connection with any such  extension,  renewal,  or replacement,  so
          secured at the time of such extension, renewal, or replacement.

     (b)  Notwithstanding  the provisions of Section 201(a),  from and after the
Release Date and so long as any Series A Senior Note is Outstanding, the Company
may issue,  assume,  or  guarantee  Debt,  or permit to exist  Debt,  secured by
mortgages which would otherwise be subject to the restrictions of Section 201(a)
up to an aggregate  principal amount that, together with the principal amount of
all other  Debt of the  Company  secured  by  mortgages  (other  than  mortgages
permitted by Section  201(a) that would  otherwise  be subject to the  foregoing
restrictions) and the Value of all Sale and Lease-Back Transactions in existence
at such time (other than any Sale and Lease-Back  Transaction that, if such Sale
and  Lease-Back  Transaction  had been a mortgage,  would have been permitted by
Section 201(a), other than Sale and Lease-Back Transactions permitted by Section
202 because the  commitment  by or on behalf of the  purchaser  was  obtained no
later than  eighteen  (18) months after the later of events  described in (i) or

                                       6
<PAGE>
(ii) of Section 202, and other than Sale and Lease-Back Transactions as to which
application  of amounts have been made in accordance  with clause (z) of Section
202),  does not at the time  exceed  the  greater  of ten  percent  (10%) of Net
Tangible Assets or ten percent (10%) of Capitalization.

     (c) If at any time the Company shall issue,  assume,  or guarantee any Debt
secured by any  mortgage and if Section  201(a)  requires  that the  Outstanding
Series A Senior Notes be secured equally and ratably with such Debt, the Company
will promptly execute, at its expense,  any instruments  necessary to so equally
and ratably secure the Outstanding Series A Senior Notes and deliver the same to
the Trustee along with:

     (1)  An  Officers'  Certificate  stating  that the  covenant of the Company
          contained in Section 201(a) has been complied with; and

     (2)  An Opinion of Counsel to the effect that the Company has complied with
          the covenant  contained  in Section  201(a),  and that any  instrument
          executed by the Company in the  performance of such covenant  complies
          with the requirements of such covenant.

     In the event that the Company shall hereafter secure  Outstanding  Series A
Senior  Notes  equally and ratably  with any other  obligation  or  indebtedness
(including  other  Notes)  pursuant to the  provisions  of this Section 201, the
Trustee  is  hereby   authorized   to  enter  into  an  indenture  or  agreement
supplemental  hereto and to take such action, if any, as it may, in its sole and
absolute  discretion,  deem  advisable to enable it to enforce  effectively  the
rights of the Holders of Outstanding  Series A Senior Notes so secured,  equally
and ratably with such other obligation or indebtedness.

     SECTION  202.  From and after the Release  Date and so long as any Series A
Senior  Note is  outstanding,  the  Company  will  not  enter  into any Sale and
Lease-Back  Transaction  with  respect to any  Operating  Property  and will not
permit to remain in effect any Sale and Lease-Back  Transaction  entered into on
or prior to the Release Date with respect to any  Operating  Property if, in any
case,  the  commitment  by or on behalf of the purchaser is or was obtained more
than  eighteen  (18)  months  after  the  later  of (i)  the  completion  of the
acquisition, construction, or development of such Operating Property or (ii) the
placing in operation of such Operating Property or of such Operating Property as
constructed,  developed, or substantially repaired, altered, or improved, unless
(x) the Company would be entitled  pursuant to Section 201(a) to issue,  assume,
or  guarantee  Debt  secured by a mortgage on such  Operating  Property  without
equally and ratably  securing the Series A Senior Notes or (y) the Company would
be entitled  pursuant to Section  201(b),  after giving  effect to such Sale and
Lease-Back  Transaction,  to incur $1.00 of additional Debt secured by mortgages
(other than  mortgages  permitted  by Section  201(a)) or (z) the Company  shall
apply or cause to be  applied,  in the case of a sale or transfer  for cash,  an
amount  equal to the net  proceeds  thereof  (but not in  excess of the net book
value of such  Operating  Property at the date of such sale or transfer) and, in
the case of a sale or transfer  otherwise  than for cash, an amount equal to the
fair value (as  determined by the Board of Directors) of the Operating  Property
so leased,  to the  retirement,  within one hundred  eighty (180) days after the

                                       7
<PAGE>
later to occur of the effective date of such Sale and Lease-Back  Transaction or
the Release  Date, of Notes or other Debt of the Company  ranking  senior to, or
equally  with,  the  Series A Senior  Notes;  PROVIDED,  HOWEVER,  that any such
retirement of Notes shall be in accordance  with the terms and provisions of the
Indenture  and the Notes;  PROVIDED,  FURTHER,  that the amount to be applied to
such  retirement  of Notes or other Debt shall be reduced by an amount  equal to
the sum of (a) an amount  equal to the  redemption  price with  respect to Notes
delivered  within such one hundred  eighty  (180)-day  period to the Trustee for
retirement and  cancellation and (b) the principal  amount,  plus any premium or
fee paid in connection with any redemption in accordance with the terms of other
Debt voluntarily retired by the Company within such one hundred eighty (180)-day
period, excluding in each case retirements pursuant to mandatory sinking fund or
prepayment provisions and payments at maturity.

     SECTION 203. DEFINITIONS

     For  purposes of Section  201 and  Section  202 of this Third  Supplemental
Indenture, the following terms shall have the following meanings:

     "Capitalization"  means the total of all the following  items appearing on,
or included in, the consolidated  balance sheet of the Company:  (i) liabilities
for  indebtedness  maturing  more  than  twelve  (12)  months  from  the date of
determination; and (ii) common stock, preferred stock, premium on capital stock,
capital surplus,  capital in excess of par value, and retained earnings (however
the foregoing may be  designated),  less, to the extent not otherwise  deducted,
the cost of shares of capital stock of the Company held in its treasury.

     Subject to the foregoing,  Capitalization shall be determined in accordance
with generally accepted  accounting  principles and practices  applicable to the
type of  business  in which the  Company is  engaged  and that are  approved  by
independent accountants regularly retained by the Company, and may be determined
as of a date not more than  (sixty) 60 days prior to the  happening  of an event
for which such determination is being made.

     The term "Debt" means any outstanding debt for money borrowed  evidenced by
notes, debentures, bonds, or other securities.

     The term "Net  Tangible  Assets"  means the amount shown as total assets on
the  consolidated  balance  sheet  of  the  Company,  less  the  following:  (i)
intangible assets  including,  but without  limitation,  such items as goodwill,
trademarks,  trade names, patents, and unamortized debt discount and expense and
other  regulatory  assets  carried  as an  asset on the  Company's  consolidated
balance sheet; and (ii) appropriate adjustments,  if any, on account of minority
interests.

     Net Tangible  Assets  shall be  determined  in  accordance  with  generally
accepted accounting  principles and practices applicable to the type of business
in which  the  Company  is  engaged  and that are  approved  by the  independent
accountants  regularly  retained by the Company,  and may be  determined as of a
date not more than (sixty) 60 days prior to the happening of the event for which
such determination is being made.

                                       8
<PAGE>
     The term "Operating Property" means (i) any interest in real property owned
by the Company and (ii) any asset owned by the Company  that is  depreciable  in
accordance with generally accepted accounting principles.

     The term "Sale and Lease-Back  Transaction"  means any arrangement with any
person  providing  for the  leasing  to the  Company of any  Operating  Property
(except for temporary leases for a term,  including any renewal thereof,  of not
more than forty-eight (48) months),  which Operating  Property has been or is to
be sold or transferred by the Company to such person.

     The term "Value" means, with respect to a Sale and Lease-Back  Transaction,
as of any  particular  time,  the  amount  equal to the  greater  of (1) the net
proceeds  to the  Company  from  the sale or  transfer  of the  property  leased
pursuant to such Sale and  Lease-Back  Transaction  or (2) the net book value of
such property,  as determined in accordance with generally  accepted  accounting
principles by the Company at the time of entering into such Sale and  Lease-Back
Transaction,  in either case  multiplied  by a fraction,  the numerator of which
shall be equal to the number of full years of the term of the lease that is part
of such Sale and Lease-Back  Transaction  remaining at the time of determination
and the  denominator of which shall be equal to the number of full years of such
term, without regard, in any case, to any renewal or extension options contained
in such lease.

     SECTION 204. Amendment to Section 901 of the Indenture. For purposes of the
Series A Senior  Notes,  clause (1) of Section  901 of the  Indenture,  shall be
revised by deleting  the words "For  purposes of this Article  Nine,  the phrase
`assets substantially as an entirety' shall mean 50% or more of the total assets
of the Company as shown on the  consolidated  balance sheet of the Company as of
the end of the calendar year immediately  preceding the day of the year in which
such   determination   is  made  and"   replacing  said  words  with  the  words
"Notwithstanding this Section 901."

                                  ARTICLE THREE

                          FORM OF SERIES A SENIOR NOTE

     SECTION  301. The Series A Senior Notes and the  Trustee's  certificate  of
authentication to be endorsed are to be substantially in the following forms:

Form of Face of Note.

                         ARIZONA PUBLIC SERVICE COMPANY

              5.05% Senior Notes (Maricopa 2002 Series A) Due 2029


No. 1                                                                $90,000,000


     Arizona Public Service  Company,  a corporation duly organized and existing
under the laws of Arizona (herein called the "Company",  which term includes any
successor  Person  under  the  Indenture  hereinafter  referred  to),  for value

                                       9
<PAGE>
received,  hereby  promises to pay to The Bank of New York, as Trustee under the
Maricopa  Indenture  hereinafter  referred  to, as assignee of Maricopa  County,
Arizona  Pollution  Control  Corporation  under said Maricopa  Indenture,  or it
successors in such capacity,  the principal sum of Ninety Million Dollars on May
1, 2029,  and to pay  interest  thereon  from  November 1, 2002 or from the most
recent  Interest  Payment Date with  respect to which  interest has been paid or
duly  provided  for,  semi-annually  on  May  1 and  November  1 in  each  year,
commencing  May 1,  2003,  at the rate of 5.05% per annum,  until the  principal
hereof is paid or made  available  for payment,  from the dates such amounts are
due until they are paid or made available for payment.  The interest so payable,
and punctually paid or duly provided for, on any Interest  Payment Date will, as
provided  in such  Indenture,  be paid to the Person in whose name this Note (or
one or more  Predecessor  Notes) is  registered  at the close of business on the
Regular Record Date for such interest, which shall be the April 15 or October 15
(whether  or not a  Business  Day),  as the case  may be,  next  preceding  such
Interest Payment Date.

     Notwithstanding  the above,  to the extent  required  in Section 4.2 of the
Loan Agreement  (described  below) at any time, all payments of interest on each
Interest  Payment Date and of principal on the maturity  date of this Note shall
be due and  payable  not less  than two (2)  Business  Days (as  defined  in the
Maricopa  Indenture  (described below)) prior to each such Interest Payment Date
and such maturity date.

     Rights to  payment  of this Note have been  assigned  by  Maricopa  County,
Arizona Pollution Control Corporation (the "Issuer") to The Bank of New York, as
trustee  (the  "Maricopa  Trustee")  under the  Indenture  of Trust  dated as of
November 1, 2002 (as amended and supplemented  from time to time,  herein called
the  "Maricopa  Indenture")  between the  Maricopa  Trustee  and the Issuer,  to
evidence,  secure and provide for the repayment of the loan (the "Loan") made by
the Issuer to the Company under the Loan Agreement  dated as of November 1, 2002
(the Loan Agreement"),  between the Company and the Issuer, from the proceeds of
the  issuance  by the Issuer of  $90,000,000  of the  Maricopa  County,  Arizona
Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona
Public Service Company Palo Verde Project) 2002 Series A (the "Pollution Control
Bonds")  under  the  Maricopa  Indenture,  and such  assignment  has  been  duly
registered.

     Payment of the  principal  of and interest on this Note will be paid by the
Company  to the  Maricopa  Trustee  at the  designated  office  of the  Maricopa
Trustee,  or to any  successor  trustee  under  the  Maricopa  Indenture  at its
designated  office,  in such coin or currency of the United States of America as
at the time of payment is legal tender for payment of public and private debts.

     Reference is hereby made to the further  provisions  of this Note set forth
below,  which further  provisions shall for all purposes have the same effect as
if set forth at this place.

     Unless the  certificate of  authentication  hereon has been executed by the
Trustee referred to on the reverse hereof by manual  signature,  this Note shall
not be entitled to any benefit under the Indenture or be valid or obligatory for
any purpose.

                                       10
<PAGE>
     IN WITNESS  WHEREOF,  the  Company has caused  this  instrument  to be duly
executed under its corporate seal.

                                        ARIZONA PUBLIC SERVICE COMPANY


                                        By______________________________________

Attest:

______________________________________

Form of Reverse of Note.

     This Note is one of a duly  authorized  issue of  securities of the Company
(herein called the "Notes"), issued and to be issued in one or more series under
an Indenture,  dated as of November 15, 1996, as supplemented and amended by the
First  Supplemental  Indenture  thereto  dated as of  November  15, 1996 and the
Second  Supplemental  Indenture  thereto  dated  as of  April  1,  1997  (herein
collectively  called the  "Indenture"),  between the Company and The Bank of New
York, as Trustee (herein called the "Trustee", which term includes any successor
trustee under the Indenture),  and reference is hereby made to the Indenture for
a  statement  of the  respective  rights,  limitations  of  rights,  duties  and
immunities  thereunder of the Company,  the Trustee and the Holders of the Notes
and of the terms  upon  which the Notes are,  and are to be,  authenticated  and
delivered. This Note is one of the series designated on the face hereof, limited
in aggregate principal amount to $90,000,000.

     Prior to the  Release  Date (as  hereinafter  defined),  this  Note will be
secured by First Mortgage Bonds, Senior Note Series C (the "Senior Note Series C
Bonds")  delivered  by the Company to the Trustee for the benefit of the Holders
of the series of Notes of which this Note is a part,  issued  under the Mortgage
and Deed of Trust, dated as of July 1, 1946, from the Company to The Bank of New
York, as successor trustee (the "Mortgage Trustee"), as supplemented and amended
(the  "First  Mortgage").  Reference  is  made  to  the  First  Mortgage  for  a
description  of property  mortgaged  and  pledged,  the nature and extent of the
security,  the rights of the holders of the first mortgage bonds under the First
Mortgage  and of the  Mortgage  Trustee  in  respect  thereof,  the  duties  and
immunities of the Mortgage  Trustee and the terms and conditions  upon which the
Senior  Note  Series C Bonds  are  secured  and the  circumstances  under  which
additional first mortgage bonds may be issued.

     FROM AND AFTER SUCH TIME AS ALL FIRST  MORTGAGE  BONDS  (OTHER  THAN SENIOR
NOTE FIRST MORTGAGE  BONDS,  AS SUCH TERM IS DEFINED IN THE INDENTURE) HAVE BEEN
RETIRED  THROUGH  PAYMENT,  REDEMPTION  OR  OTHERWISE  AT,  BEFORE  OR AFTER THE

                                       11
<PAGE>
MATURITY  THEREOF (THE "RELEASE  DATE"),  THE SENIOR NOTE FIRST  MORTGAGE  BONDS
SHALL CEASE TO SECURE THE NOTES IN ANY MANNER.

     This Note is nonnegotiable and nontransferable except as required to effect
assignment  to the  Maricopa  Trustee  under the Maricopa  Indenture  and to any
successor trustee thereunder.  Upon the appointment of a successor trustee under
the Maricopa  Indenture,  the Trustee shall  authenticate  and the Company shall
issue in the name of said successor  trustee a new fully registered Note of this
series  in the  amount  of  the  unpaid  principal  amount  of  this  Note  then
outstanding,  and this Note  shall be  surrendered  to,  and  canceled  by,  the
Trustee.

     The Company  shall have no  obligation to make payments with respect to the
principal and/or interest on the Notes of this series unless and until, and only
to the extent that,  payments shall be due and payable pursuant to the Pollution
Control Bonds. Any provision hereof to the contrary notwithstanding, the Company
shall receive a credit against its obligation to make any payment of interest on
the Notes of this Series in an amount equal to the amount,  if any,  held by the
Maricopa  Trustee  under the Maricopa  Indenture on deposit in the Bond Fund (as
defined in the  Maricopa  Indenture)  and  available  to make the  corresponding
payment on the Pollution Control Bonds. In addition, the Company shall receive a
credit  against its  obligation to make any payment of principal of the Notes of
this Series,  whether at maturity,  upon  redemption or otherwise,  in an amount
equal to the amount,  if any,  held by the Maricopa  Trustee  under the Maricopa
Indenture on deposit in said Bond Fund and  available to make the  corresponding
payment on the Pollution Control Bonds.

     In the manner and with the effect  provided in Article 12 of the Indenture,
the Notes of this series will be subject to  redemption  prior to  maturity,  as
follows:

     (a) The Notes of this Series are subject to redemption prior to maturity in
whole  or in  part,  by lot,  at any  time at a  redemption  price  equal to the
principal  amount  of the  Notes of this  Series  to be  redeemed  plus  accrued
interest to the  redemption  date in the event of the exercise by the Company of
its rights to prepay the Loan in full or in part in accordance  with Section 7.2
of the Loan Agreement upon the occurrence of any of certain extraordinary events
specified in Section 4.01(a)(1) of the Maricopa Indenture.

     (b) The Notes of this series are subject to redemption prior to maturity in
whole or in part, by lot, on any date on or after November 1, 2012, in the event
of the  exercise  by the  Company of its rights to prepay the Loan in full or in
part in accordance with Section 7.2 of the Loan Agreement and Section 4.01(a)(2)
of the Maricopa  Indenture at 100% of the principal  amount of the Notes of this
series to be  redeemed,  together  with  accrued  interest to the date fixed for
redemption

     (c) The Notes of this  series  shall  also be  redeemable,  in whole at any
time,  prior to maturity by the  application  of cash  delivered to or deposited
with the  Trustee in the event of the  exercise  by the Company of its rights to
prepay the Loan in full in accordance with Section 7.2 of the Loan Agreement and
Section  4.01(a)(3)  of the Maricopa  Indenture,  pursuant to the  provisions of
Section 87 of the First  Mortgage (but only if and to the extent such Section is
properly applicable to bona fide transactions),  at 100% the principal amount of
the Notes of this series to be redeemed  together  with accrued  interest to the
date fixed for redemption.

                                       12
<PAGE>
     (d) The Notes of this series are subject to mandatory  redemption  prior to
maturity in whole or in part, by lot, at a redemption price equal to 100% of the
principal  amount  of the  Notes of this  series  to be  redeemed  plus  accrued
interest to the  redemption  date upon the  mandatory  prepayment of the Loan in
full or in part in accordance  with Section 7.3 of the Loan  Agreement  upon the
occurrence of any of certain  extraordinary  events specified in Section 4.01(b)
of the Maricopa Indenture.

     Any notice  given  under the  provisions  of Section  4.03 of the  Maricopa
Indenture  with respect to redemption of all or a part of the Pollution  Control
Bonds or Section 7.5 of the Loan Agreement with respect to the prepayment of all
or a part of the Loan will also constitute  sufficient  notice of the redemption
of the principal amount of the Notes of this series  corresponding to the amount
of the Pollution Control Bonds to be redeemed.

     In the event of  redemption  of this Note in part only, a new Note or Notes
of this  series  and of like tenor for the  unredeemed  portion  hereof  will be
issued in the name of the Holder hereof upon the cancellation hereof.

     All payments by the Company on the Notes of this series shall be made at or
prior to the opening of business on the due date thereof.  If the  corresponding
date  for  making  any  payment  provided  in the  Maricopa  Indenture  is to be
determined in accordance with the provisions of Section 11.11 thereof,  the "due
date" hereunder will be determined in the same manner.

     The Notes of this series will not be subject to any sinking fund.

     If an Event of Default with respect to Notes of this series shall occur and
be continuing, the principal of the Notes of this series may be declared due and
payable in the manner and with the effect provided in the Indenture.

     If an Event of Default with respect to Notes of this series shall occur and
be continuing, the principal of the Notes may be declared due and payable in the
manner and with the effect provided in the Indenture and, upon such declaration,
the  Trustee can demand the  acceleration  of the  payment of  principal  of the
Senior Note Series C Bonds as provided in the Indenture.

     The Indenture  permits,  with certain  exceptions as therein provided,  the
amendment  thereof and the  modification  of the rights and  obligations  of the
Company and the rights of the Holders of the Notes of each series to be affected
under the  Indenture at any time by the Company and the Trustee with the consent
of the  Holders  of a  majority  in  principal  amount  of the Notes at the time
Outstanding  of  each  series  to  be  affected.  The  Indenture  also  contains
provisions  permitting the Holders of specified  percentages in principal amount
of the Notes of each series at the time Outstanding, on behalf of the Holders of
all Notes of such  series,  to waive  compliance  by the  Company  with  certain
provisions of the  Indenture  and certain past defaults  under the Indenture and
their consequences.  Any such consent or waiver by the Holder of this Note shall
be conclusive  and binding upon such Holder and upon all future  Holders of this
Note and of any Note  issued  upon the  registration  of  transfer  hereof or in
exchange therefor or in lieu hereof,  whether or not notation of such consent or
waiver is made upon this Note.

                                       13
<PAGE>
     As provided in and subject to the provisions of the  Indenture,  the Holder
of this Note shall not have the right to institute any  proceeding  with respect
to the  Indenture  or for the  appointment  of a receiver  or trustee or for any
other  remedy  thereunder,  unless such Holder shall have  previously  given the
Trustee  written  notice of a  continuing  Event of Default  with respect to the
Notes of this series,  the Holders of not less than 25% in  principal  amount of
the Notes of this series at the time Outstanding shall have made written request
to the Trustee to institute  proceedings  in respect of such Event of Default as
Trustee and offered the Trustee reasonable indemnity,  and the Trustee shall not
have  received  from the Holders of a majority in  principal  amount of Notes of
this series at the time Outstanding a direction  inconsistent with such request,
and shall  have  failed to  institute  any such  proceeding,  for 60 days  after
receipt of such notice, request and offer of indemnity.  The foregoing shall not
apply to any suit  instituted by the Holder of this Note for the  enforcement of
any payment of principal  hereof or interest  hereon on or after the  respective
due dates expressed herein.

     No reference  herein to the  Indenture  and no provision of this Note or of
the  Indenture  shall alter or impair the  obligation  of the Company,  which is
absolute and unconditional, to pay the principal of and interest on this Note at
the times, place and rate, and in the coin or currency, herein prescribed.

     All terms used in this Note which are defined in the  Indenture  shall have
the meanings assigned to them in the Indenture.

Form of Trustee's Certificate of Authentication.

                          CERTIFICATE OF AUTHENTICATION

     This is one of the Notes of the series  designated  therein  referred to in
the within-mentioned Indenture.

     Dated:
                                                           THE BANK OF NEW YORK,
                                                                      AS TRUSTEE


                                                By______________________________
                                                            AUTHORIZED SIGNATORY

                                  ARTICLE FOUR

                     ORIGINAL ISSUE OF SERIES A SENIOR NOTES

     SECTION 401.  Series A Senior Notes in the  aggregate  principal  amount of
$90,000,000,  may, upon execution of this Third Supplemental  Indenture, or from
time to time thereafter, be executed by the Company and delivered to the Trustee
for  authentication,  and the Trustee shall thereupon  authenticate  and deliver
said Notes to or upon the written order of the Company,  signed by its Chairman,
its  President,  or  any  Vice  President  and  its  Treasurer  or an  Assistant
Treasurer, without any further action by the Company.

                                       14
<PAGE>
                                  ARTICLE FIVE

                           PAYING AGENT AND REGISTRAR

     SECTION  501.  The  Bank of New  York  will be the  Paying  Agent  and Note
Registrar for the Series A Senior Notes.

                                   ARTICLE SIX

                                SUNDRY PROVISIONS

     SECTION  601.  Except  as  otherwise   expressly  provided  in  this  Third
Supplemental  Indenture  or in the form of  Series A Senior  Notes or  otherwise
clearly  required by the context hereof or thereof,  all terms used herein or in
said form of Series A Senior Notes that are defined in the Indenture  shall have
the several meanings respectively assigned to them thereby.

     SECTION 602. The  Indenture,  as  supplemented  by this Third  Supplemental
Indenture,   is  in  all  respects  ratified  and  confirmed,   and  this  Third
Supplemental  Indenture  shall be deemed part of the Indenture in the manner and
to the extent herein and therein provided.

     SECTION  603.  The  Trustee  hereby  accepts  the trusts  herein  declared,
provided, created,  supplemented, or amended and agrees to perform the same upon
the terms and conditions herein and in the Indenture, as heretofore supplemented
and amended, set forth and upon the following terms and conditions:

     The Trustee shall not be  responsible  in any manner  whatsoever  for or in
respect of the validity or sufficiency of this Third  Supplemental  Indenture or
for or in respect of the recitals  contained  herein,  all of which recitals are
made by the  Company  solely.  In  general,  each and every  term and  condition
contained in Article Seven of the Indenture shall apply to and form part of this
Third Supplemental  Indenture with the same force and effect as if the same were
herein set forth in full with such omissions,  variations,  and  insertions,  if
any, as may be  appropriate  to make the same conform to the  provisions of this
Third Supplemental Indenture.

     This  instrument  may be  executed in any number of  counterparts,  each of
which so executed shall be deemed to be an original,  but all such  counterparts
shall together constitute but one and the same instrument.

                                       15
<PAGE>
     IN WITNESS WHEREOF,  the parties hereto have caused this Third Supplemental
Indenture  to be duly  executed,  and  their  respective  corporate  seals to be
hereunto affixed and attested, all as of the day and year first above written.


                                        ARIZONA PUBLIC SERVICE COMPANY


                                        By: Barbara M. Gomez
                                            ------------------------------------
                                            Barbara M. Gomez
                                            Treasurer

Attest:


Betsy A. Pregulman
-------------------------------------
Betsy A. Pregulman
Associate Secretary

                                        THE BANK OF NEW YORK, as Trustee


                                        By: Debra A. Schwalb
                                            ------------------------------------
                                            Vice President

Attest:

Thomas J. Provenzano
-------------------------------------
Vice President

                                       16
<PAGE>
STATE OF ARIZONA         )
                         ) ss:
COUNTY OF MARICOPA       )

     On the 1st day of November, 2002, before me personally came Barbara M.
Gomez, to me known, who, being by me duly sworn, did depose and say that she is
the Treasurer of Arizona Public Service Company, one of the corporations
described in and which executed the foregoing instrument; that she knows the
seal of said corporation; that the seal affixed to said instrument is such
corporate seal; that it was so affixed by authority of the Board of Directors of
said corporation; and that she signed her name thereto by like authority.


                                            Debra L. Blondin
                                            ------------------------------------
                                                       NOTARY PUBLIC

My Commission Expires:

June 7, 2004
----------------------

                                       17
<PAGE>
STATE OF NEW JERSEY      )
                         ) ss:
COUNTY OF PASSAIC        )

     On the 1st day of November, 2002, before me personally came Debra A.
Schwalb, to me known, who, being by me duly sworn, did depose and say that she
is the Vice President of The Bank of New York, one of the corporations described
in and which executed the foregoing instrument; that she knows the seal of said
corporation; that the seal affixed to said instrument is such corporate seal;
that it was so affixed by authority of the Board of Directors of said
corporation; and that she signed her name thereto by like authority.


                                            Ronald M. Mania
                                            ------------------------------------
                                                       NOTARY PUBLIC

My Commission Expires:

10-4-06
----------------------

                                       18

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.3
<SEQUENCE>5
<FILENAME>ex10-3.txt
<DESCRIPTION>3RD AMEND. TO INVESTMENT CO. DEFERRED COMP PLAN
<TEXT>
                                                                    Exhibit 10.3

                               THIRD AMENDMENT TO
                      THE PINNACLE WEST CAPITAL CORPORATION
                         ARIZONA PUBLIC SERVICE COMPANY
                           SUNCOR DEVELOPMENT COMPANY
                        AND EL DORADO INVESTMENT COMPANY
                           DEFERRED COMPENSATION PLAN

     Effective January 1, 1992, Pinnacle West Capital Corporation (the
"Company"), Arizona Public Service Company, SunCor Development Company and El
Dorado Investment Company adopted the Pinnacle West Capital Corporation, Arizona
Public Service Company, SunCor Development Company and El Dorado Investment
Company Deferred Compensation Plan (the "Plan"). The Plan was thereafter amended
several times and was amended and restated in its entirety on December 1, 1995,
and thereafter amended September 15, 1999 and December 1, 1999.

     By this instrument, and pursuant to the authority granted in the Section
11.2 of the Plan, the Company intends to amend the Plan to increase the
threshold for automatic cashout of the Account balance of a terminated or
retired Participant under certain circumstances, and to provide for the
crediting of interest for a full month if a Participant works past the 15th of
such month.

     1.   This Amendment shall amend only those Sections set forth herein and
those Sections not amended hereby shall remain in full force and effect.

     2.   The third sentence of Section 3.5 is revised to read as follows:

          In the event of Retirement, Disability, death or a Termination of
          Employment prior to the end of a Plan Year, the basis for that year's
          interest crediting will be a fraction of the full year's interest
          based on the Account Balance as of the end of the immediately
          preceding Plan Year, together with the amount actually deferred for
          the Plan Year as of the date of the Participant's Retirement,
          Disability, death of Termination of Employment and based further on
          the number of full months that the Participant was employed with or
          served as a Director of the Employer during the Plan Year prior to the
          occurrence of such event, and for this purpose, a Participant shall be
          deemed to be so employed or to have so served for a full month if he
          or she was employed with or served as a Director of the Employer past
          the 15th day of such month.

     3.   Section 5.4 is revised to read as follows:

          5.4  AUTOMATIC DISTRIBUTION OF RETIREMENT BENEFITS.
<PAGE>
               Notwithstanding any provision of this Article 5 to the contrary,
               if the Account Balance of a Retired Participant does not exceed
               Twenty Thousand Dollars ($20,000), the Participant's Retirement
               Benefit shall be distributed in a lump sum within sixty (60) days
               following his Retirement.

     4.   Section 7.2(c) is revised to read as follows:

          (c)  AUTOMATIC DISTRIBUTION OF TERMINATION BENEFITS.

          Notwithstanding any provision of this Section 7.2 to the contrary, if,
          upon a Participant's Termination of Employment, his Account Balance,
          as determined pursuant to Section 7.1, does not exceed Twenty Thousand
          Dollars ($20,000), the Participant's Termination Benefit shall be
          distributed in a lump sum within sixty (60) days following his
          Termination of Employment.

     5.   This Amendment shall be effective as of January 1, 2002.

     IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by
its duly authorized officer this 22nd day of October, 2002.


                                        PINNACLE WEST CAPITAL CORPORATION


                                        By Armando Flores
                                           -------------------------------------

                                           Its Executive Vice President,
                                               Corporate Business Services
                                               ---------------------------------

                                        2

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12.1
<SEQUENCE>6
<FILENAME>ex12-1.txt
<DESCRIPTION>RATIO OF EARNINGS TO FIXED CHARGES
<TEXT>
                                                                    Exhibit 12.1


                        PINNACLE WEST CAPITAL CORPORATION
                    COMPUTATION OF EARNINGS TO FIXED CHARGES
                             (THOUSANDS OF DOLLARS)

<TABLE>
<CAPTION>
                                           Three
                                           Month
                                           Ended
                                          March 31,            Twelve Months Ended December 31,
                                          --------  ----------------------------------------------------
                                            2003       2002       2001       2000       1999       1998
                                          --------   --------   --------   --------   --------   --------
<S>                                       <C>        <C>        <C>        <C>        <C>        <C>
Earnings:
  Income from Continuing
    Operations ........................   $ 20,153   $206,198   $327,367   $302,332   $269,772   $242,892
  Income Taxes ........................     12,754    132,228    213,535    194,200    141,592    138,589
  Fixed Charges .......................     55,788    219,651    211,958    202,804    194,070    201,184
                                          --------   --------   --------   --------   --------   --------
    Total .............................     88,695    558,077    752,860    699,336    605,434    582,665
                                          ========   ========   ========   ========   ========   ========
Fixed Charges:
  Interest Expense ....................     47,851    187,512    175,822    166,447    157,142    163,975
  Estimated Interest Portion of
    Annual Rents ......................      7,937     32,139     36,136     36,357     36,928     37,209
                                          --------   --------   --------   --------   --------   --------
    Total Fixed Charges ...............     55,788    219,651    211,958    202,804    194,070    201,184
                                          ========   ========   ========   ========   ========   ========
Ratio of Earnings to Fixed Charges
  (rounded down) ......................       1.58       2.54       3.55       3.44       3.11       2.89
                                          ========   ========   ========   ========   ========   ========
</TABLE>

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99.1
<SEQUENCE>7
<FILENAME>ex99-1.txt
<DESCRIPTION>WILLIAM J. POST SECTION 906 CERTIFICATION
<TEXT>
                                                                    Exhibit 99.1

 FORM OF CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
                                (WILLIAM J. POST)

     I, William J. Post, the Chairman of the Board and Chief Executive Officer
of Pinnacle West Capital Corporation ("Pinnacle West"), certify, to the best of
my knowledge, that: (a) the attached Quarterly Report on Form 10-Q of Pinnacle
West for the fiscal quarter ended March 31, 2003 (the "March 2003 Form 10-Q")
fully complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act of 1934 and (b) the information contained in the March 2003 Form
10-Q Report fairly presents, in all material respects, the financial condition
and results of operations of Pinnacle West.


                                        William J. Post
                                        ----------------------------------------
                                        William J. Post
                                        Chairman of the Board and
                                        Chief Executive Officer

                                        Date: May 14, 2003

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99.2
<SEQUENCE>8
<FILENAME>ex99-2.txt
<DESCRIPTION>DONALD E. BRANDT SECTION 906 CERTIFICATION
<TEXT>
                                                                    Exhibit 99.2

 FORM OF CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
                               (DONALD E. BRANDT)

     I, Donald E. Brandt, Senior Vice President and Chief Financial Officer, of
Pinnacle West Capital Corporation ("Pinnacle West"), certify, to the best of my
knowledge, that: (a) the attached Quarterly Report on Form 10-Q of Pinnacle West
for the quarter ended March 31, 2003 (the "March 2003 Form 10-Q") fully complies
with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act
of 1934 and (b) the information contained in the March 2003 Form 10-Q Report
fairly presents, in all material respects, the financial condition and results
of operations of Pinnacle West.


                                        Donald E. Brandt
                                        ----------------------------------------
                                        Donald E. Brandt
                                        Senior Vice President and
                                        Chief Financial Officer

                                        Date: May 14, 2003

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99.3
<SEQUENCE>9
<FILENAME>ex99-3.txt
<DESCRIPTION>ACC DECISION NO. 65796 DTD 4/4/03
<TEXT>
                                                                    Exhibit 99.3

                    BEFORE THE ARIZONA CORPORATION COMMISSION

COMMISSIONERS

MARC SPITZER, Chairman
JIM IRVIN
WILLIAM A. MUNDELL
JEFF HATCH-MILLER
MIKE GLEASON

IN THE MATTER OF THE APPLICATION OF         DOCKET NO. E-01345A-02-0707
ARIZONA PUBLIC SERVICE COMPANY FOR AN
ORDER OR ORDERS AUTHORIZING IT TO
ISSUE, INCUR, OR ASSUME EVIDENCES OF
LONG-TERM INDEBTEDNESS; TO ACQUIRE A           DECISION NO. 65796
FINANCIAL INTEREST OR INTERESTS IN AN
AFFILIATE OR AFFILIATES; TO LEND MONEY
TO AN AFFILIATE OR AFFILIATES; AND TO
GUARANTEE THE OBLIGATIONS OF AN
AFFILIATE OR AFFILIATES.                       OPINION AND ORDER

DATES OF HEARINGS:            September   24,  2002   (procedural   conference);
                              October 4, 2002 (procedural  conference);  January
                              3, 2003  (prehearing);  January  8, 9, 10, 13, and
                              14, 2003
PLACE OF HEARINGS:            Phoenix, Arizona
ADMINISTRATIVE LAW JUDGE:     Lyn Farmer
IN ATTENDANCE:                William  A.   Mundell,   Chairman   Marc  Spitzer,
                              Commissioner Jeff Hatch-Miller,  Commissioner Mike
                              Gleason, Commissioner

APPEARANCES:                  Mr.  Michael  R.  Engleman  and Mr.  Frederick  D.
                              Ochsenhirt,  DICKSTEIN, SHAPIRO, MORIN & OSHINSKY,
                              L.L.P, on behalf of Panda Gila River, LP;

                              Mr. Scott S. Wakefield,  Chief Counsel,  on behalf
                              of the Residential Utility Consumer Office;

                              Mr.  Thomas  L.  Mumaw  and Ms.  Karilee  Ramaley,
                              PINNACLE WEST CAPITAL CORPORATION; and Mr. Jeffrey
                              B. Guldner,  SNELL & WILMER,  P.L.C., on behalf of
                              Arizona Public Service Company;

                              Mr.  James  McGuire,   ROSHKA,  HEYMAN  &  DeWULF,
                              P.L.C.,   on  behalf  of  Tucson   Electric  Power
                              Company;

                              Mr., Lawrence V. Robertson,  Sr., MUNGER CHADWICK,
                              P.L.C.;  and  Mr.  Theodore  E.  Roberts,   SEMPRA
                              ENERGY,  on behalf of Sempra Energy  Resources and
                              Southwestern Power Group, II;

                                        1                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

                              Mr. William P. Sullivan,  MARTINEZ & CURTIS, P.C.,
                              on behalf of Reliant Energy Resources;

                              Mr.  Walter W. Meek,  President,  on behalf of the
                              Arizona Utility Investors Association;

                              Mr. C. Webb Crockett,  FENNEMORE  CRAIG,  P.C., on
                              behalf of the  Arizonans  for Electric  Choice and
                              Competition;

                              Mr. Jay I. Moyes,  MOYES STOREY,  on behalf of PPL
                              Southwest    Generating    Holdings,    LLC;   PPL
                              EnergyPlus, LLC; and PPL Sundance Energy, LLC; and

                              Mr. Christopher C. Kempley, Chief Counsel, and Ms.
                              Janet F. Wagner,  Staff Attorney,  Legal Division,
                              on behalf of the Utilities Division of the Arizona
                              Corporation Commission.

BY THE COMMISSION:

     On September 16, 2002,  Arizona Public Service Company ("APS" or "Company")
filed with Corporation Commission ("Commission") the above-captioned application
for financing approval ("Application").

     On September 20, 2002, Panda Gila River, L.P.  ("Panda") filed a Motion for
Leave to Intervene.  On September 23, 2002,  the  Residential  Utility  Consumer
Office ("RUCO") filed an Application to Intervene.

     By Procedural Order issued September 23, 2002, a Procedural  Conference was
held on September  24,  2002,  to discuss the  procedures  for  processing  this
application.  By Procedural Order issued September 25, 2002, a second Procedural
Conference was scheduled. -

     On October 4, 2002, the second Procedural  Conference was held as scheduled
and established  procedural dates for the preparation and conduct of this matter
and to consider  the Motions to  Intervene  by Panda;  Reliant  Resources,  Inc.
("Reliant");   the  Harquahala  Generating  Company,  LLC  ("Harquahala");   PPL
Southwest  Generation  Holdings,  LLC;  PPL Energy  Plus,  LLC; and PPL Sundance
Energy,  LLC  (collectively  "PPL  entities");  the  Arizona  Utility  Investors
Association,  Inc.  ("AUIA");  Southwestern  Power Group II, LLC and Bowie Power
Station (collectively "SWPG/Bowie"); Sempra Energy Resources ("Sempra"); Arizona
Competitive Power Alliance ("ACPA"); and Tucson Electric Power Company ("TEP").

                                       2                      DECISION NO. 65796
<PAGE>
                                                    DOCKET NO. E-01 345A-02-0707

     At the Procedural  Conference,  oral arguments were heard on the motions to
intervene and the parties discussed their proposed  procedural schedule for this
matter.  The motions to intervene were granted,  and it was noted that the scope
of the hearing would not be broadened by their participation.

     By Procedural Order issued October 9, 2002, the hearing was set to commence
on January 8, 2003. On October 10, 2002, APS filed an Emergency Motion to Modify
the October 9, 2002 Procedural  Order, and on October 15, 2002, the Commission's
Utilities Division Staff ("Staff'), RUCO, and Panda responded to APS' Motion.

     On October 16, 2002, APS filed a Motion for Protective Order ("Motion"). On
October 21, 2002, Staff filed its Response;  on October 23, 2002, RUCO filed its
Response;  on October 23,  2002,  APS filed its Reply;  and on October 29, 2002,
Panda filed a Response to Staff's  Response.  On November 25, 2002, APS withdrew
its Motion without prejudice. Intervention was granted to Arizonans for Electric
Choice and Competition ("AECC") on November 18, 2002.

     Notice of the hearing was  published  in the ARIZONA  REPUBLIC,  THE BISBEE
DAILY REVIEW, THE CASA GRANDE DISPATCH,  THE ARIZONA DAILY SUN (FLAGSTAFF),  THE
PRESCOTT COURIER, AND THE YUMA DAILY SUN.

     The hearing  commenced as scheduled  in January 8, 2003 and  witnesses  for
APS, AUIA, Panda,  RUCO, and Staff testified and presented  evidence during five
days of hearing.  Initial  posthearing briefs were filed on January 27, 2003 and
reply briefs were filed on February 6, 2003.

                                   BACKGROUND

     On May  20,  1994,  the  Commission  opened  Docket  No.  U-0000-94-165  to
investigate the  introduction of retail  electric  competition.  On December 26,
1996, the Commission issued Decision No. 59943, which adopted A.A.C.  R14-2-1601
through  1616,  the Retail  Electric  Competition  Rules.  Hearings were held on
generic  stranded  cost issues,  and on June 28,  1998,  the  Commission  issued
Decision No. 60977 on Stranded Costs. On August 10, 1998, in Decision No. 61071,
the Commission  adopted amended rules on an emergency basis, and on December 11,
1998, adopted the emergency rules on a permanent basis in Decision No. 61272. On
January 11, 1999, the  Commission  issued  Decision No. 61311,  which stayed the
Retail Electric Competition Rules and related decisions,  including Decision No.
60977.

                                       3                      DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

     On April 27, 1999, the Commission issued Decision No. 61677,  which amended
Decision No. 60977, the Commission's prior Stranded Cost decision.  Decision No.
61677 ordered the Hearing  Division to issue a Procedural Order to set dates for
consideration of stranded costs and unbundled tariffs for each Affected Utility.
The revised Retail Electric Competition Rules were published on May 14, 1999 and
public comment  sessions were held. On May 18, 1999, APS filed for approval of a
Settlement Agreement, a hearing was held, and the Commission issued Decision No.
61973  (October 6, 1999),  approving the Settlement  Agreement with changes.  On
September 29, 1999, the Commission issued Decision No. 61969, which approved the
revised Retail Electric  Competition Rules ("Electric  Competition  Rules").  In
Decision  No.  62924  (October  10,  2000)  the  Commission  adopted  clarifying
revisions to the Electric Competition Rules.

     The Settlement Agreement provided and Decision No. 61973 granted a two-year
extension of time,  until December 31, 2002, for APS to separate  assets (A.A.C.
1615(A)(1)) and also granted a "similar two-year  extension" for compliance with
A.A.C. R14-2-1606(B)(2). APS planned to divest its competitive generation assets
to a yet-to-be  formed  generation  affiliate.  The Addendum to APS'  Settlement
Agreement  also provided that:  "[a]fter the  extensions  granted in Section 4.1
have expired, APS shall procure generation for Standard Offer customers from the
competitive  market  as  provided  for in the  Electric  Competition  Rules.  An
affiliated   generation   company  formed  pursuant  to  this  Section  4.1  may
competitively  bid for  APS'  Standard  Offer  load,  but  enjoys  no  automatic
privilege  outside of the market  bid on account of its  affiliation  with APS."
(4.1(3))

     On October 18, 2001, APS filed a Variance/Purchased Power Agreement ("PPA")
application.  The application stated that "adherence to the competitive  bidding
requirements  of the  Electric  Competition  Rules will not produce the intended
result of reliable  electric  service for Standard Offer customers at reasonable
rates,"  requested that the Commission grant a partial variance to R14-2-1606(B)
that would  otherwise  obligate  APS to acquire all of its  customers'  Standard
Offer generation requirements from the competitive market, and sought Commission
approval of a long term purchase power agreement with its parent,  Pinnacle West
Capital Corporation ("PWCC").

----------
(1)  A.A.C.  R14-2-1615(A)  provides:  "All  competitive  generation  assets and
     competitive  services shall be separated from an Affected  Utility prior to
     January 1, 2001. Such separation  shall either be to an unaffiliated  party
     or to a separate corporate affiliate or affiliates.  If an Affected Utility
     chooses  to  transfer  its  competitive  generation  assets or  competitive
     services to a competitive  electric affiliate,  such transfer shall be at a
     value  determined  by the  Commission  to be fair and  reasonable."  ("Rule
     1615(A)")
(2)  A.A.C.  R14-2-1606(B) provides:  "After January 1, 2001, power purchased by
     an investor owned Utility  Distribution  Company for Standard Offer Service
     shall be acquired from the competitive market through prudent, arm's length
     transactions,  and with at least 50% through a  competitive  bid  process."
     ("Rule 1606(B)")

                                       4                      DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

     By  Procedural  Order  issued  on May 2,  2002,  a generic  proceeding  was
established  that set up Track A to resolve  issues  relating  to market  power,
divestiture,  codes of conduct/affiliate transactions and jurisdictional issues.
It also established Track B to address competitive procurement. On September 10,
2002, the  Commission  issued  Decision No. 65154 in the Track A proceeding.  On
September 16, 2002, APS filed this  application.  On November 8, 2002, APS filed
an "Emergency Application" requesting a partial waiver of A.A.C. R14-2-804(B)(1)
and (2) to  allow  APS to make  short-term  advances  to PWCC in the  form of an
inter-affiliate  line  of  credit,  or  alternatively,  in  the  form  of an APS
guarantee of PWCC's  short-term  debt. In Decision No. 65434 (December 3, 2002),
the  Commission  granted the request with  conditions.  On March 14,  2003,  the
Commission issued its Decision No. 65743 in Track B.

                                   DISCUSSION

     APS' parent,  PWCC, has incurred  approximately $1 billion in debt in order
to finance the  construction  of  generating  units(3)  at Pinnacle  West Energy
Corporation  ("PWEC"),  its merchant subsidiary.  PWCC used debt with short-term
maturities(4) because it planned for PWEC to refinance the debt at an investment
grade once the APS  rate-based  generation  assets were  transferred to PWEC. In
Decision No. 65154  (September 10, 2002),  the Commission  ordered APS to cancel
any plans to divest  interests in any  generating  assets.(5)  On September  16,
2002,  APS filed this  financing  application.  APS, on behalf of its parent and
affiliate,  claims that without the APS generation assets, PWEC does not have an
investment  grade credit rating and therefore cannot finance the PWEC generation
assets.  Further, APS claims on behalf of its parent and affiliate,  that due to
market  conditions,  PWEC cannot obtain  project  financing.  PWCC's bridge debt
begins coming due in August 2003.

     In its application APS asks that the Commission:

     *    Authorize the Company to assume, issue, or incur up to $500,000,000 in
          aggregate principal amount of Recapitalization Debt;
     *    Authorize  the  Company to  determine  the terms  associated  with the
          Recapitalization   Debt,   including   whether   any  portion  of  the
          Recapitalization Debt will be secured by

----------
(3)  West Phoenix  combined  cycle  generating  units 4 & 5, Saguaro  combustion
     turbine Unit No. 3 and Redhawk Units I & 2.
(4)  This has been referred to as PWCC's "bridge debt".
(5)  The  Decision  also  provided  that if "APS  wishes to pursue  the issue of
     acquiring  PWEC's   generation   assets,  it  shall  file  the  appropriate
     application(s) by September 15, 2002."

                                       5                      DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

          all or a portion of the Company's assets;
     *    Authorize the Company to provide the APS Guarantees in accordance with
          the Application;
     *    Authorize the Company to determine the terms  associated  with the APS
          Guarantees,  including  whether any portion of the APS Guarantees will
          be secured by all or a portion of the Company's assets;
     *    Provide that the Recapitalization Debt and the APS Guarantees will not
          be classified or counted as Continuing Debt;
     *    Find that the issuance and  incurrence of  Recapitalization  Debt, and
          the  issuance  of the  APS  Guarantees  are  reasonable  necessary  or
          appropriate  for the purposes set forth in this  Application  and that
          such purposes are within those permitted by A.R.S.  Section 40-301, ET
          SEQ.;
     *    Permit such purposes to the extent they may be  reasonably  chargeable
          to  operative  expenses  or to income and allow the payment of related
          expenses as contemplated herein;
     *    Authorize APS to obtain a financial  interest in PWEC or Pinnacle West
          in  the  form  of  an  inter-affiliate  loan,  APS  Guarantees,  or  a
          combination of the two up to a maximum  aggregate  principal amount of
          $500,000,000;
     *    Authorize  APS to  make  such  expenditures,  sign  and  deliver  such
          documents,  and negotiate such terms and conditions with  underwriters
          or  selling  agents,  purchasers  and/or  lenders,  including  but not
          limited  to  those   pertaining  to  terms,   rates,   and  collateral
          requirements (if any), all as described  herein,  as may be reasonably
          necessary to economically  effectuate the other authorizations granted
          herein; and
     *    Grant the Company such additional  relief as is appropriate  under the
          circumstances.

     The Company is  requesting  approval  of either an  inter-company  loan,  a
guarantee, or a combination of both. The proceeds of the long-term debt incurred
by APS would then be loaned to either  PWEC or PWCC.  The funds would be used to
pay off an  equivalent  amount  of PWCC  debt  previously  incurred  to  finance
construction of the PWEC assets.

     Jack Davis,  APS President and CEO, and PWCC President,  testified that the
following were benefits from granting the  application:  avoiding a downgrade of
APS debt ratings;  avoiding corresponding  increases in the APS cost of capital;
strengthening  wholesale  competition by maintaining PWEC as a viable competitor
in the upcoming Track B  solicitation;  preserving the  Commission's  ability to
consider  rate base  treatment  of the PWEC assets in the  2003-2004  rate case;
strengthening   investor  and  rating  agency   confidence  in  the  Commission;
continuing a responsive and responsible regulatory  environment;  preserving the
current Track B solicitation process; and resulting in settlement of most of the
issues in the Track A legal appeals. (APS-8 at 4-5) Further, in its Initial

                                       6                      DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

Post-Hearing  Brief, APS identified what it believes are additional  benefits to
it and its customers  from approval of the  application,  including net interest
income  of  between  7.5 to 13.2  million  dollars  per  year,  and  with  Staff
conditions,  there may be  greater  regulatory  insulation  for APS  within  the
holding company structure.

     APS witness,  Arthur Tildesley,  Managing  Director,  Salomon Smith Barney,
Inc.,  testified that under current market  conditions,  PWEC would be unable to
raise significant debt financing on a standalone or non-recourse basis. "Without
the transfer of the APS generation  assets or the  establishment of some form of
power purchase  agreement  ("PPA"),  the business  profile and credit quality of
PWEC would be viewed as very weak." Mr.  Tildesley  testified that "APS business
fundamentals  and credit  statistics  are  strong,  and we believe  that APS has
significant capacity to provide an intercompany loan or guarantee to PWEC in the
amount of $500 million without  impairing  fundamental  utility credit quality."
Mr. Tildesley did not attempt to evaluate PWEC's ability to actually service the
loan, and in fact,  for purposes of determining  the impact of a loan on APS, he
assumed no repayment capacity at PWEC. (APS-3 pp 4 & 5)

AUIA

     The AUIA  urged  the  Commission  to grant APS the  authority  it seeks and
believes that this action would be in the public  interest in  safeguarding  the
financial  integrity of APS and its parent.  AUIA  believes  that if APS' credit
cannot be used, "it is not inconceivable  that a bankruptcy and/or a forced sale
of some or all of the PWEC assets could occur.  Of course,  any sale in the near
future would be into a market that is already glutted with the bad  construction
decisions of merchant  generators."  (AUIA-1 at 5). AUIA  believes  that such an
impact on APS would not be positive as it is "increasingly difficult to insulate
an affiliate  from the fortunes of its holding  company and vice versa and it is
unrealistic  to expect  that APS would be immune  from a  financial  meltdown at
Pinnacle West." (Id.)

STAFF

     Staff believes that APS could face a downgrade if PWCC is downgraded,  that
such a downgrade of APS could  interfere  with APS' ability to provide  electric
service  to the  public if it  resulted  in  increases  in the cost of  capital,
potential lack of access to the capital markets, potential

                                       7                      DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

increases in  collateral  requirements,  and an  inability  to do business  with
vendors.  Staff believes that APS' requested  financing will be compatible  with
the public  interest if, by  preventing a downgrade in APS' credit  ratings,  it
prevents a substantial  disintegration  in APS' ability to provide service.  For
those reasons,  Staff  recommended  that the Commission  authorize APS to borrow
$500 million in order to loan the proceeds to PWEC.

     Although Staff concludes that APS' proposed financing will likely serve the
public  interest,  Staff believes that the  transaction  poses some risks to the
Company and to its  ratepayers,  including the fact that issuing debt to loan to
PWEC will diminish  APS' ability to obtain its own required debt capital  needed
in the coming years, and that the proposed financing runs counter to the goal of
insulating APS from its affiliates' unregulated activities.  Staff believes that
these  considerations  do not  outweigh  the need to prevent a downgrade to APS'
credit  rating,  but require  conditions  to approval  of the  financing.  Staff
Conditions for approval include:

     1.   APS should be authorized  to issue and sell no more than  $500,000,000
          of debt in addition to its current authorizations;
     2.   The debt to be lent to PWEC  should  be no more than  $500,000,000  of
          secured  callable notes from PWEC.  The security  interest shall be on
          the same terms as the  security  interest  APS already has pursuant to
          the $125,000,000 loan authorization from Decision No. 65434;
     3.   The PWEC  secured  note  coupon  shall be 264 basis  points  above the
          coupon on APS debt issued and sold on equivalent  terms (including but
          not limited to maturity and security);
     4.   The  difference  in interest  income and  interest  expense  should be
          capitalized  as a  deferred  credit  and used to  offset  rates in the
          future. The deferred credit balance shall bear an interest rate of six
          percent;
     5.   The PWEC debt maturity shall not exceed four years,  unless  otherwise
          ordered by the Commission;
     6.   Any  demonstrable  increase in APS' cost of capital as a result of the
          transaction,  such as from a decline in bond rating, will be extracted
          from future rate cases; and
     7.   APS shall maintain a minimum common equity of 40 percent and shall not
          be allowed to pay  dividends if such  payment  would reduce its common
          equity  ratio below this  threshold,  unless  otherwise  waived by the
          Commission.  The Commission will process the waiver within sixty days,
          and for this  sixty-day,  period this  condition  shall be  suspended.
          However,  this condition  shall not be  permanently  waived without an
          order of the  Commission.  During  the  hearing,  Staff  proposed  two
          clarifications  to Condition 7: that the  condition  should  remain in
          effect  indefinitely  and that APS should file the  capital  structure
          calculation  with the  Commission  within one week of filing a 10-Q or
          10-K.

                                       8                      DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

     Staff's  conditions 2 and 6 are designed to protect APS and its  ratepayers
from any harm that may result from this transaction. Condition 2 is necessary to
ensure that APS'  interests  are  protected if there were a default on the loan.
Condition  6 puts the  Company and its  affiliates  on notice that any  negative
credit  effects to APS will not be borne by its  ratepayers.  Conditions 3 and 4
are designed to ensure that APS and its ratepayers are appropriately compensated
for the risk associated with the transaction. Conditions 5 and 7 are intended to
provide appropriate regulatory insulation between APS and its affiliates.

     Staff believes that ordinarily,  it would probably recommend denial of such
a financing.  However,  Staff believes that the  circumstances  surrounding this
application are "far from ordinary".  "The financial markets are  deteriorating,
the energy sector is in disarray,  electric utilities in neighboring states have
suffered  financial  difficulties,  and the wholesale market for electricity has
been volatile. Against this backdrop, the Commission's policy should be aimed at
ensuring  that  Arizona  will  continue  to  have  financially   sound  electric
utilities.  Because of the potential  risk of a downgrade to APS' credit rating,
the Commission should approve APS'  application;  because of the potential risks
inherent in this transaction,  the Commission should condition its approval upon
Staff's seven conditions." (Staff Initial Br. At 6).

     Staff  asserts  that the  Commission  should not base its  approval of this
application  upon APS'  allegations  that the  Commission is at fault for PWCC's
predicament. Staff states that throughout its presentation of its case, "APS has
implied that the Commission is responsible for PWCC's dilemma, claiming that the
Commission 'largely created' this problem 'in the first instance.' (Ex. APS-1 at
24). Over and over again, APS insinuates that the Commission's  Track A order is
largely to blame, (APS' Br. At 5, 7), and that the Commission is now responsible
for repairing that order's 'loose ends.' (Tr. at 586).  Finally,  APS has stated
that  incurring the bridge debt was  'consistent  with  Commission  guidance and
directives,'  (APS' Br. At 8), as if the Commission were the entity that decided
to build the PWEC assets and to finance them through short term bridge debt. The
Commission  should not conclude that it is responsible for PWCC's problems,  and
it certainly should not base its approval of this application upon such claims."
(Staff Reply Br. at 5).

     Staff  cites  the  existing  turmoil  in  the  financial  markets  and  the
volatility that has existed in the

                                       9                      DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

wholesale electric market.  Staff's witness testified that if the Commission had
not stopped  divestiture,  given the current market  situation,  PWEC could have
been facing an even worse  problem  than trying to finance  now.  Staff  further
noted  that the "PWCC  enterprise  chose to build the  assets at PWEC,  chose to
finance them at the holding company level, and chose the maturities of the debt.
None of these  decisions  were made or  sanctioned by the  Commission.  APS will
argue that its code of conduct prevented it from building the PWEC assets at APS
(Tr. at 520);  nonetheless,  an  examination  of that  document does not clearly
support that conclusion." (Staff Reply Brief at 5-6)

RUCO

     RUCO recommends  granting the financing  application and also proposes that
APS be required to file an  application  with the  Commission  within 45 days to
transfer the PWEC generation assets to APS.

     RUCO believes  that because APS will use borrowed  funds to protect its own
credit rating, the financing is within the proper performance of its duties as a
public service corporation.  Based upon Moody's December 30, 2002 Opinion Update
on APS and Standard and Poor's  statement  that "[e]ven on a stand-alone  basis,
APS' financial  health  remains  solidly within the 'BBB' category even with the
addition of $500 million in debt" (Ex S-4),  RUCO  believes  that the  financing
will not impair APS' ability to perform its public service obligations.

     RUCO believes that with  conditions,  the financing is compatible  with the
public  interest.  According  to RUCO,  it will allow  PWEC/APS to maintain  the
generation assets to the benefit of APS customers.  RUCO notes that generally, a
utility  issuing debt to finance  assets owned by an affiliate is not compatible
with sound financial  practices,  however,  RUCO believes that it and Staff have
proposed  conditions  that  would  make  the  financing  consistent  with  sound
financial practices. RUCO recognizes that "[t]ransferring the PWEC assets to APS
and  including  some or all in rate  base  could  signal  the  death  knell  for
wholesale competition",  however, RUCO argues that "it is in the public interest
for the  Commission  to take action to protect  the  public,  even if that means
returning to an integrated electric utility model at this time." (RUCO Reply Br.
at 3) RUCO  concludes  that  granting the APS  application  is "merely a stopgap
measure to prevent PWCC from defaulting on its short-term  debt  obligations and
going into bankruptcy" and that a "cohesive comprehensive plan to rebuild the

                                       10                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

regulatory  paradigm is necessary to return the electric  industry in Arizona to
functional viability." (RUCO Br. At 7)

PANDA

     Panda recommends that the Commission deny the financing application, but if
it does approve some form of credit support to an affiliate, that the Commission
require  that it be in the form of a  guarantee  of  affiliate  debt,  but not a
direct inter-company loan. Panda disagrees with APS' assertions that PWCC cannot
refinance  the debt  itself;  that  PWCC  will be  downgraded  if the  financing
application is denied; that APS will be downgraded if the financing  application
is denied; and that if the financing is approved,  APS will not be harmed,  even
with the Staff conditions.

     According  to Panda,  APS  asserted  two  primary  reasons  for  Commission
approval of the financing.  First, APS argues that the Commission's  decision in
the Track A harmed it and its  parent  and  affiliate,  and that the  Commission
should  approve  the  financing  as a remedy.  Second,  APS argues  that PWEC is
fundamentally different from other merchant generators and therefore, Commission
should protect it.

     Susan Abbott, a former Moody's analyst with twenty years experience  rating
utility companies, including APS, testified on behalf of Panda.

     Panda  argues that there is no evidence in the record that PWCC will suffer
a downgrade if APS does not  refinance  the bridge debt.  In its Initial  Brief,
Panda states "APS  introduced NO written  evidence that PWCC would be downgraded
if it refinanced or  renegotiated  the bridge debt at the holding company level,
nor any evidence that such a refinancing or renegotiation is impossible. Rather,
Ms. Gomez relied on undocumented and unsubstantiated conversations she allegedly
had with lenders and rating agency personnel during the course of which, or even
after  which,  she failed to take a SINGLE  note.  Tr. at 114,  lines 3-6 ... In
short,  Ms. Gomez could produce no evidence to back up her  assertion  that PWCC
would be  downgraded  if it  refinanced  the bridge debt at the holding  company
level." (emphasis  original) (Panda Initial Br. p. 11) Panda's witness testified
that were she analyzing PWCC, she would not recommend a rating downgrade if PWCC
refinanced  the debt,  because PWCC's credit metrics would remain within the BBB
range.  Ms. Abbott  further noted that APS testified  that PWCC could raise $300
million over the next year for its Nevada generation

                                       11                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

(Silverhawk).

     Panda also  argues  that there is no  evidence  in the record that APS will
suffer a downgrade  if PWCC is  downgraded.  Panda's  witness  testified  that a
downgrade  of a  holding  company  can  result  in a  downgrade  of the  utility
subsidiary  when the  parent's  debt load is so high as to  require  substantial
dividends from the utility  company in order for the parent to service the debt,
but  here,  the  debt  load  of the  parent  would  not  change,  since  it is a
refinancing.  Panda argues that any evidence  that APS will not be downgraded if
it assumes an  additional  $500  million in debt is "either  not  credible or is
entirely  self-serving."  (Initial Br. at 14) Panda's witness testified that the
analysis of the rating agencies  depends on what information was provided by the
utility,  and Panda  argues  that since APS sent its  testimony  (which says APS
intends to seek rate base treatment of the PWEC generation assets) to the rating
agencies but APS' witness  cannot  remember  what she told the rating  agencies,
there is no way to know whether the analyses  presume rate base treatment of the
PWEC  assets,  and  therefore  would  decline if the assets did not become  rate
based.  Panda also argues that the relevance of prior rating  agency  statements
are questionable "given that APS appears to have provided inaccurate information
to the rating agencies and analysts in the past as well.  Shortly after the 1999
Settlement and after PWEC proposed constructing  generation assets, APS and PWEC
told the rating  agencies  that PWEC and APS either had, or would,  enter into a
four-year  Power  Purchase  Agreement  ("PPA")  for the  supply  of  APS'  power
requirements, even though the final two years of the PPA would be AFTER the date
when APS was required to procure 100% of its Standard Offer Service requirements
from the competitive market rather than from its unregulated merchant affiliate.
Exhs.  P-23,  24 and 25. On  cross-examination,  Ms. Gomez  admitted  that there
really was no such PPA,  and that APS merely  told the rating  agencies  that it
'expected'  to sell  power  under  just such a  contract.  Tr. at  145-146.  The
documents offer no such qualification, and it is reasonable to infer, therefore,
that had the agencies been provided more accurate information, they likely would
not have opined as they did." (Panda Initial Br. at 14-15)

     Ms. Abbott testified that if additional  leverage were to be placed on APS,
it is difficult to believe that would not be reflected in a ratings downgrade by
Moody's and Fitch,  and by S&P at the first mortgage bond level.  She found that
APS' financial parameters would decline significantly, and

                                       12                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

although  they  are not the  only  concern  for the  rating  agencies,  they are
important  guideposts that have a heavy influence on ratings.  Panda argued that
even if APS is not downgraded as result of making a loan to its  affiliate,  its
credit quality will suffer.  Ms. Abbott testified that approval of the financing
application  would  diminish  APS'  credit  quality  and that she would have not
recommended  keeping the rating the same based on her  analysis  and  conclusion
that the resulting  financial metrics were more commensurate with those of other
vertically  integrated  fully regulated  utilities in the "B 11" range.  (Tr. at
752) She  expressed  some  surprise  at Moody's  December  30,  2002  statement,
indicating that although ratings are not the sole product of financial  metrics,
it is not known what  information  APS provided to Moody's.  APS Treasurer,  Ms.
Gomez testified that she did not keep records of her conversations.(6)

     Another concern expressed by Ms. Abbott is that a loan or guarantee between
APS and PWCC would make that relationship closer, and APS will be less protected
from  negative  circumstances  affecting  PWCC.  She  concludes  that  there are
negative  consequences  to APS  ratepayers  in the long  run,  including  higher
interest cost should APS be downgraded,  and a less robust competitive market in
Arizona  leading  to higher  purchased  power  costs.  Panda  believes  that the
appropriate place to refinance the PWEC assets is at PWCC.

     Panda cites the rulemaking docket and order that adopted the Public Utility
Holding  Companies  and  Affiliated  Interests  Rules  A.A.C.  R14-2-401 ET SEQ.
("Affiliated  Interest  Rules") to support  its  position  that the  application
should not be granted. Panda quotes the Commission's

Concise Explanatory Statement:

     The Rules were first  promulgated  in 1985 in response to the formation [of
     PWCC by APS] and to its acquisition  one year later of MeraBank,  a federal
     savings and loan institution. The Commission at the time expressed concerns
     that the  transactions  would  prevent  proper  regulation  and  effect the
     establishment  of rates for APS. In  response,  APS and its parent  offered
     assurances to the Commission

----------
(6)  Q.   I think you responded in response to data requests  that, in fact, you
          have no written statements from any of the financing agencies; is that
          correct? As far as your discussions with them?
     A.   That's right.  We don't keep  documentation  of the  discussions  with
          them.
     Q.   Why is that?
     A.   It's our practice to not keep documentation.
     Q.   Okay. So you keep no  documentation  of any of your  discussions  with
          Moody's, Fitch, Standard & Poor's?
     A.   No, I  don't.  The  discussions  happen  frequently  and I do not keep
          records of that. Gomez Tr. pp. 113-114. See also TR. At 117 & 298.

                                       13                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

     that the concerns  were  unfounded  ... The huge capital  losses which have
     recently been  experienced by MeraBank and have forced Pinnacle West to the
     brink of financial  collapse  served as the catalyst for the  Commission to
     again engage in rulemaking  for the  regulation of public  utility  holding
     company formation and affiliated  transactions ... Article 8 is designed to
     ensure that utility  ratepayers are insulated from the dangers proven to be
     inherent in holding  company  structure and  diversification.  Its singular
     purpose is to ensure that  ratepayers do not pay rates for utility  service
     that include costs associated with holding company  structure,  financially
     beleaguered  affiliates,  or sweetheart  deals with affiliates  intended to
     extract capital from the utility to subsidize non-utility operations.(7)

     The Concise Explanatory  Statement also stated that the Rules were intended
to implement these principles: "First, utility funds must not be commingled with
non-utility  funds.  Second,  crosssubsidization  of  non-utility  activities by
utility  ratepayers  must be  prohibited.  Third,  the  financial  credit of the
utility must not be affected by non-utility activities.  Fourth, the utility and
its affiliate  must provide the  Commission  with the  information  necessary to
carry out regulatory responsibilities." (Id.)

     Panda concludes that "APS's (sic) assertion that APS' credit rating will be
adversely  affected if it is not permitted to loan half a billion dollars to its
non-regulated  affiliate is clearly an action that the Affiliated Interest Rules
were intended to prohibit." (Panda Initial Br. at 5-6)

     Panda  argues  that  APS  failed  to prove  the  elements  required  by the
statutory and regulatory standards,  but instead posed the "eight 'benefits"' it
believes the financing provides.

     Panda argues that the evidence  demonstrates that PWEC assets were built to
serve the wholesale market, not APS customers. (Panda Initial Brief pp 15-19)

     Panda  believes  that if the  Commission  decides  that it is in the public
interest for APS to provide some credit support for its affiliate,  it should be
in the form of a guarantee, and not a loan.

     Panda  recommends  that the  Commission  restrict  any  financing to an APS
guarantee of PWEC's debt because it would:  maintain the separation of regulated
and  unregulated  assets;  preserve to the greatest  extent possible the goal of
wholesale  competition;  not  prejudge or call into  question  the issue of rate
basing PWEC assets;  allow PWEC to make an entry into the financial  markets(8);
and

----------
(7)  In the Matter of the Notice of Proposed Adoption of Rules for Regulation of
     Public Utility Companies with Unregulated  Affiliates,  Decision No. 56844,
     Attachment B at 2 (1990).
(8)  APS' witness, Arthur Tildesley of Salomon Smith Barney testified that while
     the  guarantee  structure  "may be perceived by investors as somewhat  more
     complex and may be marginally more expensive than an intercompany  loan, it
     has the benefit of the notes being issued directly by PWEC." (APS-3 at 9)

                                       14                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

APS  credit  quality  would not  suffer as much,  because  there is no  interest
obligation on a guarantee.(9)

     Panda believes that the Commission's  goal should be to establish PWEC as a
standalone entity as soon as possible,  and a direct loan from APS to PWEC would
perpetuate the relationship between regulated and unregulated entities,  whereas
a corporate guarantee would provide more of a degree of separation.

     Panda  argues  that  APS' new  reason to  prefer a loan to a  guarantee  is
because the  guarantee  would be more  difficult  to undo if the PWEC assets are
rate based.  Panda states that the "Commission is faced with the choice of using
a guarantee, which APS witnesses have testified advances the future potential of
PWEC standing on its own two feet, or allowing an  inter-company  loan, the only
benefit  of which is that it makes  APS'  desire  to rate  base the PWEC  assets
easier.  With these facts and the  Commission's  objective  to preserve a viable
competitive  wholesale market, it should be an easy choice for the Commission to
select the corporate guarantee over the interaffiliate loan." (Panda Initial Br.
at 27) "Putting the PWEC assets in APS' rate base is the antithesis of promoting
wholesale competition. As Jack Davis made clear, if the PWEC assets go into rate
base they will all but eliminate  APS' capacity and energy needs going  forward.
Tr. at 655 ... Based on Mr.  Davis'  testimony,  there is little  question  that
rate-basing  the PWEC assets would  decimate  wholesale  competition in Arizona.
Hence,  if  approval  of the loan option  would make this  rate-basing  any more
likely, it should be rejected in favor of the guarantee  option." (Panda Initial
Br. at pp 28-29).

     Panda  argues  that the  potential  harm to  wholesale  competition  can be
created by the loan itself and by a default  under the loan.  APS has  indicated
its intent to transfer the PWEC assets to APS and seek rate base treatment,  and
defaulting  on the loan could  accomplish  that goal.  According to Panda,  APS'
assertions  that the potential for  cross-defaults  would prevent a PWEC default
would not  suffice,  because  the PWCC debt that  contains  cross-defaults  will
expire,  leaving only a $25 million callable Prudential loan at the end of 2004.
Further, even if new debt contains the cross-default provisions,  Panda believes
that since the cross-default  language is discretionary  (the lender MAY declare
the debt

----------
(9)  APS  testified  that it  proposed  the  guarantee  option  "because  of its
     potentially  reduced  impact on APS and because it might  provide PWEC some
     'credit  exposure'  in the market that would be  valuable  in the  future."
     (APS-2 at 7).

                                       15                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

to become  immediately  due and payable) and that such  provisions are routinely
waived by lenders,  a waiver would be expected in an inter-company  transaction.
Panda also believes that APS'  assertion  that Deeds of Trust would also prevent
automatic  transfer to APS upon PWEC default is without  merit,  as the Deeds of
Trust allow APS to 'enter upon and take possession of the trust estate.' Deed of
Trust at 9,  paragraph  1.10."  (Panda  Initial Br. at 31).  Panda argues that a
direct  inter-company  loan has the  potential  to  adversely  affect  wholesale
competition because APS would have a strong incentive to prefer its affiliate in
the Track B competitive solicitation, both to support payment of its loan and to
establish a case for rate base treatment of the PWEC assets.

     Panda  also  points  out that  the  cost of a  guarantee  would  have  been
evaluated when APS first proposed that alternative, and states that any costs of
pursuing a guarantee  would be borne by PWEC and would be of no  consequence  to
APS or its customers.

     Panda  proposes what it believes are three critical terms to any guarantee:
the PWEC  assets  must be pledged as  collateral  for the loan;  the lender must
execute on the assets  prior to seeking  payment from APS; and APS should not be
permitted  to bid on the assets in the event PWEC were to default  and a sale of
assets be held.

     In response to APS'  argument that under a guarantee,  ratepayers  will not
have the benefit of the conditions  Staff proposes,  Panda argues that these are
not "benefits"  but ways to mitigate harm from the financing.  Panda also argues
that  Staff's  conditions  only  address the rate impacts of an increase in APS'
cost of capital,  and do not address  other ways approval of a loan may harm APS
ratepayers. Panda believes that loan approval will directly harm the competitive
market by making it much more likely APS will  ultimately be able to include the
PWEC assets in APS rate base.  Staff did not analyze the effect of loan approval
on wholesale  power  rates,  and Panda  argues that  therefore,  Staff cannot be
certain that approval of the application will not harm APS customers.

     In response to Staffs  assertion that a guarantee is  inappropriate,  Panda
argues  that if Staff  still  believes  that a risk  premium is  appropriate  to
reflect the risk that APS would be called  upon to pay the amount of  difference
between  the  underlying;  PWEC  debt  and the  value of the  PWEC  assets,  the
transaction  could be structured to collect such a risk premium from PWEC. Panda
states that Staffs concern about APS not having a primary  security  interest is
misplaced unless the point of the security

                                       16                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

interest is that APS  ultimately  owns the PWEC assets or if Staff believes that
the PWEC  assets  are not  worth at least  $500  million.  This is  because  the
security  interest  requirement is to make sure that ratepayers are protected by
allowing an opportunity to exercise on the collateral to recover the loan. Under
the  guarantee,  APS would bear no risk of making any  payment  unless and until
PWEC  defaults,  and only  then if the PWEC  assets  are sold for less  than the
deficiency  amount. As far as Staff's assertion that a guarantee is impractical,
Panda notes that it was APS that  proposed the  guarantee  and has  consistently
agreed  to  use  the  guarantee  if  the  Commission   determined  that  it  was
appropriate;  that APS has had time to any prepare  and  address any  additional
complexities;  and that APS' own lender witness testified that his firm would be
interested in placing the guarantee and underlying PWEC debt.

SEMPRA/SWPG/BOWIE

     Sempra/SWPG/Bowie  believes that the  Commission  should deny the financing
for both policy and failure of proof reasons.

     Sempra/SWPG/Bowie  believes that serious  questions exist as to whether APS
has  satisfactorily  discharged its probative burden under A.R.S. ss. 40-301(C).
Sempra/SWPG/Bowie  argues that the analysis should look at "whether the proposed
borrowing and loaning by APS is for a 'lawful purpose'  directly related to each
of the five (5) decision making  standards set forth in A.R.S.  ss.  40-301(C)."
(emphasis original)(Reply Br. at 9)

     Specifically,  Sempra/SWPG/Bowie  concluded that APS had not met its burden
of showing that its proposed financial assistance to its affiliate is within its
corporate powers and intended corporate purpose.

     Sempra/SWPG/Bowie argues that the record contains no credible evidence that
APS'  creditworthiness or financial integrity would be impaired if the financing
were denied.  Sempra/SWPG/Bowie  state that "[o]n the face of it, the use of its
creditworthiness  and  financial  resources  by APS to  prop  up an  unregulated
generation  affiliate,  and to financially  back-stop its unregulated  corporate
parent,  would appear to have nothing to do with the proper  performance  of its
role and obligations as a public service corporation" (Sempra/SWPG/Bowie Initial
Br. at 11), a finding  required under A.R.S.  ss.  40-301(C).  Sempra/SWPG/Bowie
further stated that APS

                                       17                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

acknowledges  that it may be required to secure a loan with mortgage lien on APS
assets and argues that "[t]he very  existence of such a mortgage lien would,  by
its very nature,  restrict  APS' ability to use its assets to borrow or bond for
its  own  needs  from  what  would   otherwise   be  the  case."   (Br.  at  12)
Sempra/SWPG/Bowie  believes that given this  uncertainty,  APS is unable to show
that its ability to properly perform its public service obligations might not be
impaired at some future date.

     Sempra/SWPG/Bowie suggests that when looking at whether the financing is in
the public interest, the Commission may consider whether the purposes underlying
APS' proposed  borrowing  and lending,  or guarantee,  are  consistent  with its
purpose and  responsibilities  as a public service corporation and whether there
is a risk that the results would be  inconsistent  with other "public  interest"
determinations  previously made by the Commission.  (Sempra/SWPG/Bowie Reply Br.
at 11)

     Sempra/SWPG/Bowie  argued  that it is  imperative  that this  Decision  not
undercut or dilute the  Commission's  efforts to facilitate the development of a
viable  competitive  wholesale electric market through the Track B proceeding or
preposition  the  Commission  as to how it may resolve any future APS request to
acquire or rate base PWEC's generation assets.

     In  its  Reply  Brief,  Sempra/SWPG/Bowie  argues  that  APS  continues  to
attribute a potential  "liquidity  crisis" that threatens its parent's financial
integrity  to  Decision  No.  65154.  Sempra/SWPG/Bowie  notes  that the Track A
proceeding was instituted in part in response to APS' Variance/PPA  application;
that it was APS' parent,  PWCC,  that decided how to finance the PWEC assets and
chose the maturity  dates for such  financing;  and that there is no  suggestion
that APS had any role in that  decision or that the  Commission  was  consulted.
"Rather,  it appears PWCC made the decision for its own financial gain, and with
a view towards avoiding 'more expensive and restrictive  financing' [APS Initial
Brief, page 6, lines 4-7 However, now that PWCC and PWEC apprehend difficulty in
arranging for permanent  financing of these generation assets,  they look to APS
and its  creditworthiness  to 'bail' them out,  although there is no evidence in
the record that PWCC ever intended to share the benefits of its reduced  interim
financing  costs with APS or its  ratepayers."  (Sempra/SWPG/Bowie  Reply Br. at
3-4)

     Sempra/SWPG/Bowie  also  notes  the  "failure  of APS (and its  unregulated
parent and

                                       18                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

generation affiliate) to avail itself of the Commission's invitation in Decision
No. 65154 to file an application  seeking approval to acquire PWEC's  generation
assets.  Such an application was to be filed on or before September 15, 2002, if
APS  decided  to pursue  that  course of action.  Had it elected to do so,  that
matter  might have been  resolved by now;  and,  perhaps an  entirely  different
scenario might have unfolded  without a purported  'liquidity  crisis'...  It is
very  clear  from the  record  in this  proceeding  that  APS has the  financial
capacity to issue  additional  bonds and thus raise funds by which it could have
acquired PWEC's generation assets, without the necessity of an accompanying rate
increase." (Reply Br. at 4-5)

     Sempra/SWPG/Bowie   is  also   concerned  by  APS'   acceptance  of  Staffs
recommended condition that the term of the loan not exceed four years, because a
four-year  loan  will not  solve  PWCC's  purported  need to  arrange  permanent
financing for PWEC's generation  assets,  and APS' and PWCC's plan have no "exit
strategy" if the Commission  grants the financing but denies an APS  application
to rate base the generation assets.  Sempra/SWPGBowie believes that APS and PWCC
are  actually  seeking  to  put  the  Commission  in a  position  of  having  no
alternative  but to  approve  an APS  request  for rate base  treatment  of PWEC
assets.

AECC

     AECC takes no position on approval of the financing application,  but it is
concerned  about the effect  approval  will have,  VIS A VIS a December 13, 2002
Memorandum  from the Director of the  Utilities  Division to the  Commissioners,
with an attached  document  titled  "Track 'A'  Appeals  Issues  Principles  For
Resolution." ("Principles of Resolution") AECC argues that a Commission decision
granting the financing without specifically  rejecting certain provisions of the
Principles of Resolution  "will have the effect of: 1) breaking the Commission's
reassurance in Decision No. 65154 not to undermine the benefits that the parties
have bargained for under the APS Settlement Agreement;  2) amending Decision No.
61973 without  complying  with the provisions of A.R.S.  ss. 40-252;  and 3) may
constitute  "legal action" by settling  litigation  currently  before the courts
without  proper notice under  Arizona's  open meeting law." (AECC Opening Br. at
2-3)

RELIANT

     In its Opening  Post-Hearing  Brief,  Reliant  states that it intervened in
this financing docket to

                                       19                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

"guard against the possibility that the financing  application might subvert the
efforts  of the  Commission  and  numerous  parties  to  develop a fair and open
competitive  wholesale  generation  market." (Reliant Br. at 3) Reliant requests
that this Decision expressly find that neither the implementation of the Track B
competitive  solicitation process nor the Commission's  consideration of whether
to authorize APS to acquire PWEC generation  assets or their rate base treatment
will be prejudiced or adversely affected by this Decision,.

     APS  indicates  that  granting  this  application  will not  give  PWEC any
advantage  in meeting the credit  requirements  in the Track B process,  because
PWEC will remain without an investment grade rating.

                                    ANALYSIS

     The Company is  requesting  approval  of either an  inter-company  loan,  a
guarantee, or a combination of both. The proceeds of the long-term debt incurred
by APS would then be loaned to either  PWEC or PWCC.  The funds would be used to
pay off an  equivalent  amount  of PWCC  debt  previously  incurred  to  finance
construction  of West Phoenix  combined  cycle  generating  units 4 & 5, Saguaro
combustion  turbine  Unit No. 3 and Redhawk  Units 1 & 2. As a  supplement  to a
loan, or as an alternative, APS seeks authority to guarantee debt issued by PWEC
or PWCC.

APPLICABLE STATUTES/REGULATIONS

     Pursuant to Arizona  Revised  Statutes  ss.40-285(A),  "[a] public  service
corporation shall not sell, lease, assign,  mortgage, or otherwise dispose of or
encumber the whole or any part of its railroad, line, plant, or system necessary
or useful in the  performance  of its duties to the  public ... . without  first
having secured from the commission an order authorizing it to do so."

     A.R.S.  ss.  40-301(C)  sets  forth  the  minimum   requirements  that  the
Commission must find to authorize APS' issuance of additional debt.

     A.R.S. ss. 40-301

     A.   The power of public  service  corporations  to issue  stocks and stock
          certificates, bonds, notes and other evidences of indebtedness, and to
          create liens on their property  located within this state is a special
          privilege, the right of supervision,  restriction and control of which
          is vested in the state,  and such power shall be exercised as provided
          by law and under rules, regulations and orders of the commission.

                                       20                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

     B.   A public service  corporation may issue stocks and stock certificates,
          bonds, notes and other evidences of indebtedness payable at periods of
          more than twelve months after the date thereof,  only when  authorized
          by an order of the commission.

     C.   The commission shall not make any order or supplemental order granting
          any  application as provided by this article unless it finds that such
          issue is for lawful purposes which are within the corporate  powers of
          the applicant,  are compatible  with the public  interest,  with sound
          financial practices,  and with the proper performance by the applicant
          of service  as a public  service  corporation  and will not impair its
          ability to perform that service.

     Pursuant to A.R.S. ss. 40-302,  the Commission may grant or refuse to grant
permission  and  may  attach  whatever   conditions  it  deems   reasonable  and
appropriate.

     A.R.S. ss. 40-302

     A.   Before  a  public   service   corporation   issues  stocks  and  stock
          certificates,  bonds,  notes and other evidences of  indebtedness,  it
          shall first secure from the commission an order authorizing such issue
          and stating  the amount  thereof,  the  purposes to which the issue or
          proceeds  thereof are to be applied,  and that,  in the opinion of the
          commission,  the issue is reasonably  necessary or appropriate for the
          purposes  specified in the order,  pursuant to ss.  40-301,  and that,
          except as  otherwise  permitted  in the order,  such  purposes are not
          wholly or in part,  reasonably  chargeable to operative expenses or to
          income ....

     B.   The  commission  may  grant  or  refuse  permission  for the  issue of
          evidences of  indebtedness  or grant the permission to issue them in a
          lesser amount,  and may attach to its  permission  conditions it deems
          reasonable  and  necessary.  The  commission  may authorize less than,
          equivalent to or greater than the  authorized  or  subscribed  capital
          stock of the  corporation,  and the  provisions of the general laws of
          the  state  with  reference  thereto  have no  applications  to public
          service corporations.

     Pursuant  to A.A.C.  R14-2-804(B),  APS cannot  lend to any  affiliate  not
regulated by the Commission or obtain a financial  interest in any affiliate not
regulated by the  Commission,  or guarantee,  or assume the  liabilities  of the
affiliate, without approval of the Commission.  Pursuant to A.A.C. R14-2-804(B),
the Commission will review the  transactions  "to determine if the  transactions
would impair the financial  status of the public utility,  otherwise  prevent it
from attracting  capital at fair and reasonable  terms, or impair the ability of
the public utility to provide safe, reasonable and adequate service."

OBLIGATIONS OF CERTIFICATED PUBLIC SERVICE CORPORATIONS

     As a certificated public service corporation in Arizona,  APS has a duty to
provide  reliable  electric  service to its  customers at reasonable  rates.  In
furtherance  of that duty,  APS should  manage its  business and  operations  to
insure that it is financially capable of providing such service. It is in

                                       21                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

the public  interest that APS maintain  healthy  credit  ratings so that APS has
access to the capital markets at reasonable  terms and rates, as those costs are
reflected in rates paid by APS customers. Further, APS has a duty to comply with
applicable statutes, regulations, and Commission decisions.

NEED FOR APS CREDIT SUPPORT

     Much of the  testimony  focused upon who may be downgraded if the financing
application  is approved or denied.  APS argued that  neither  PWCC nor PWEC can
refinance the existing PWCC debt at reasonable  terms without  support from APS.
APS further argues that PWCC will be downgraded if the application is denied and
APS will be downgraded if PWCC is downgraded.  APS argues that a downgrade would
impair  its  ability to obtain  credit to support  its  utility  operations  and
possibly interfere with its ability to provide electric service.  Staff and RUCO
agreed with APS'  conclusions.  Panda argued that PWCC could  refinance the debt
and that if APS issues debt to loan to PWEC, it is likely to be downgraded,  and
at the very least, its credit quality will suffer.

     Staff  believes that a rating  downgrade at APS could  interfere  with APS'
ability to provide electric service to the public - it could result in increases
in cost of capital,  potential lack of access to the capital markets,  potential
increases in  collateral  requirements,  and an  inability  to do business  with
vendors.  Staff concluded that "there is some risk of ratings downgrade to PWCC,
and as a  consequence,  to APS."  (Staff  Initial  Br.  at 3-4)  Although  Staff
believes  that  "the  evidence  on this  issue  is  clothed  in  conjecture  and
speculation,  significant evidence nonetheless supports the conclusion that PWCC
is at risk for credit downgrades.  As a consequence,  APS faces a similar risk."
(Ibid at 4).

     Rating agency reports indicating a potential for a PWCC downgrade include a
December 2002 Fitch report stating  "[f]ailure to obtain the inter-company  loan
or access  alternate  sources of funding  would  result in a  downgrade  of PNW"
(APS-2, Ex. BMG-2R);  Standard and Poor's November 4, 2002 report stating "[t]he
stable outlook reflects the assumption that the ACC will approve the application
by PWCC to  issue  up to $500  million  at APS to  repay a  portion  of the $750
million bridge  financing at PWCC" (Staff Ex.4); and a December 30, 2002 Moody's
report stating "PWCC's rating outlook is stable and  incorporates  the view that
the ACC  will  adopt  the  staff  recommendation  concerning  the APS  financing
application, which should allow for a successful

                                       22                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

refinancing of PWCC debt." (APS Ex. 5).

     The likelihood of an APS downgrade in the event of a PWCC downgrade is more
speculative.  Staff's witness  testified that he could not state for a fact that
APS would be downgraded,  but cited the December 30, 2002 Moody's Opinion update
(APS Exh. 5) which states:  "APS' rating outlook is stable and  incorporates the
view  that  the ACC will  adopt  the  staff  recommendation  concerning  the APS
financing  application  and other Track A issues.  Moody's notes that while APS'
coverages may decline if the financing  application is approved,.  the resulting
credit metrics should remain  consistent with the current  rating,  particularly
when one considers the benefits to bondholders  of having APS remain  vertically
integrated."  Staff  acknowledges that the report is subject to  interpretation,
but believes that it implies that APS' ratings  outlook is stable as long as the
financing application is approved.

     Panda's  witness  testified that APS acquiring  additional  debt to loan to
PWEC should result in a downgrade of APS, whereas, PWCC refinancing its existing
bridge  debt should not result in a downgrade  of PWCC or APS.  Logically,  this
analysis makes sense.  However, we do not know what APS told the rating agencies
- since Ms. Gomez sent them her testimony  that indicates that APS seeks to rate
base these assets,  we do not know whether or how this  information was factored
into the agency opinions.  Therefore,  it is possible that APS may be downgraded
if APS led the rating  agencies to believe  that the assets are going to be rate
based, and that the assets had an assured cash flow.

     This testimony and evidence on the need for APS credit support  consists of
speculation  on actions that third parties may take as a result of our decision.
Our foremost  concern and guiding  principle is what is in the best  interest of
the  ratepayers  of APS.  Although  it is not  clear  to us that  APS  would  be
downgraded if this financing  application is denied,  we are not willing to risk
that since we believe  that with  appropriate  conditions,  we can  minimize the
effects  of  the  financing  on  the  ratepayers.  Accordingly,  APS  should  be
authorized to provide credit support.

FORM OF APS CREDIT SUPPORT - LOAN AND/OR GUARANTEE

     APS seeks either a loan and/or a guarantee. Staff supports only a loan, and
Panda supports only a guarantee.

                                       23                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

LOAN

     Panda and  other  intervenors  urge the  Commission  not to  approve a loan
because it does not maintain separation between APS and its affiliate;  it would
undermine  wholesale  competition;  and because  APS' credit  quality  would not
suffer as much as with a guarantee.

     We stated in Decision No. 65434  (December 3, 2002),  that we would examine
ways to improve the regulatory insulation between APS and its affiliates in this
docket. We are also concerned about regulatory insulation, but find that Panda's
concerns  about a loan can be addressed in the  conditions we place upon a loan,
by monitoring subsequent events including the Track B solicitation,  and through
our  Affiliated   Interest  Rules.(10)  Further,  we  are  not  adopting  RUCO's
recommended requirement that APS file an application to acquire or rate base the
PWEC  assets,  and none of the  proceeds  will be used for or to support  PWEC's
non-Arizona generation assets.

     Although APS' witness Tildesley  testified that for purposes of determining
the impact on APS, he assumed no repayment  capacity at PWEC,  we are  approving
this financing based upon the testimony of President and Chief Executive Officer
for APS and the President of PWCC, Jack Davis, that if PWEC did not win any bids
in the Track B competitive procurement,  that PWEC would sell its power out into
the wholesale market,  and that that would generate  sufficient funds to pay the
loan to APS.  (Davis Tr. p. 641).  Additionally,  APS will soon be filing a rate
case and we can take  further  action to protect  ratepayers  at that  time,  if
necessary.  Therefore,  if there are any negative  effects of the  financing (in
addition to Staff's identified capital cost concerns),  we will insure that APS'
ratepayers  are held  harmless.  Further,  we will  require  that APS notify the
Commission  in the event of a default on the loan,  so that the  Commission  can
take  appropriate  action.  Staffs Condition 2 requires APS to obtain a security
interest in the PWEC assets and only APS has such a lien,  so APS would have the
first priority in the event of a default. (Tr. 269-272)

     APS  generally  agreed with Staff's  conditions  for a loan  approval,  but
requested  modification  of  Condition 3 to reduce the point  spread from 264 to
150.  APS  believes  that  Staff's  premium  is  excessive  and   "substantially
overstates the risk undertaken by APS". APS' point spread corresponds

----------
(10) See discussion and conditions  hereinafter in the Affiliated Interest Rules
     section.

                                       24                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

to the  difference  between APS' credit  rating and the rating APS believes PWEC
would have  obtained  absent  Decision No. 65154.  Staff  believes that the loan
should be priced at an appropriate  market rate - PWEC's current status reflects
a BB minus  rating  which is not  investment  grade.  Staff's  basis  point risk
premium is designed to insure that APS will be  compensated  for the actual risk
associated  with lending  money to PWEC.  We agree with Staff that APS should be
compensated for the actual risk and given PWEC's  acknowledgement  that it could
not obtain project financing even prior to Decision No. 65154,(11)  believe that
Staffs premium is appropriate.

     APS proposes that the Commission adopt its clarification to Condition 7, by
defining the  calculation of the amount of common equity to mean calculated on a
quarterly  basis,  using  APS'  10-Q or 10-K  filings  with the  Securities  and
Exchange Commission.  Using the reported APS balance sheet accounts, APS' common
equity would be divided by the sum of such common equity and APS long-term  debt
(including  current  maturities of such debt).  Staff did not disagree with this
method.  However, it is not clear from APS' clarification if this new debt is to
be included in the  calculation,(12)  so we will approve APS' clarification with
the condition  that the debt financing  approved  herein will be included in the
calculation.

     Accordingly, we will adopt Staffs recommended conditions to APS' financing,
with the clarifications above.

GUARANTEE

     In its Initial Brief,  APS indicates  that although it initially  requested
either a loan or a  guarantee,  if forced to choose  between the two, it prefers
the loan option,  primarily  because of timing - it believes  that the financial
markets  are more  familiar  with APS debt so an APS loan  would be  easier  and
quicker than if potential  lenders must do "market  discovery" on PWEC.  This is
especially so if "it is determined  that PWEC should  register its debt with the
SEC as an initial public  offering  rather than place debt  privately." APS also
believes  that  Staff's  conditions  would  be  difficult  to  implement  with a
guarantee.  Further,  APS believes that an APS loan would "reduce  future issues
involved  in the  determination  by the  Commission  of  the  ultimate  retaking
treatment" of the PWEC

----------
(11) Tr. At 211
(12) Staff  recommends a maximum  term of four years,  which would likely not be
     included in long-term debt.

                                       25                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

assets because "it minimizes any  subsequent  costs of assuming or refunding the
PWEC debt being guaranteed by APS." (APS Initial Br. at 25) Further, a guarantee
would be more costly to PWEC.

     APS believes that Panda's three critical  conditions on a guarantee  should
be rejected as  impractical,  unnecessary,  and contrary to APS' customers' best
interests. APS criticizes Panda's requirement that PWEC assets should be pledged
to a third-party  lender as directly  conflicting with Staff's  Condition No. 2;
that a  requirement  that a  third-party  lender  execute on PWEC assets  before
seeking  payment  from APS  would  make  the  financing  unmarketable;  and that
precluding  APS from  bidding  on PWEC  assets  in an  auction  would  violate a
fundamental  principle in commercial  secured  transactions  that "a creditor is
entitled  to  protect  its own equity in an  investment  by bidding at least its
secured  amount into any auction" (APS Closing Br. at 15); and would prevent the
Commission from ever considering the used and usefulness of the plants.

     Staff  opposed APS'  request to  guarantee  the debt issued by PWCC or PWEC
because Staff  believes that it is  "undefined,  impractical,  ill suited by the
circumstances of the case, and unsupported by the record." (Staff Initial Br. at
6) Even if a  guarantee  were well  defined,  Staff  believes  that a loan would
better protect  ratepayers  because an explicit loan with a stated interest rate
would set forth the APS risk  exposure.  Further,  Staff is  concerned  with the
timing and  complexity  of a  guarantee  and  believes  that a  guarantee  would
interfere with Staff's  condition that APS hold a security  interest in the PWEC
assets.  In  response  to  Panda's  argument  that a  guarantee  would  maintain
separation between APS and its affiliates, Staff states that although regulatory
insulation is important,  it would be unreasonable to structure this transaction
around that single goal.

     We believe that APS should have the flexibility to use the guarantee option
if it would be in the best interests of ratepayers. Although none of the parties
are as  familiar  with such a  guarantee,  we  believe  that it is  possible  to
structure  such a  guarantee  to  address  the  concerns  raised by Staff in its
proposed  conditions to the loan approval.  Not all of the debt to be refinanced
is due this summer,  and it may be possible to use a combination of debt now and
guarantee  later. If APS chooses to use the guarantee  option,  it shall consult
with Staff to make sure that the transaction's structure meets Staff's concerns.
We find that  Panda's  proposed  restriction  limiting  APS'  ability  to bid at
auction to preserve its equity is not in the public interest.

                                       26                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

COMPLIANCE WITH A.R.S. ss. 40-301

     In response to Sempra/SWPG/Bowie  argument that the financing is not within
its corporate powers, APS argues that its current Articles of Incorporation were
adopted in 1988 under  Title 10 of the  Arizona  Revised  Statutes.  A.R.S.  ss.
10-054(A)(4)   required  all  corporations  to  include  in  their  articles  of
incorporation a brief statement of character of business the corporation intends
to actually  conduct,  but the statement did not limit the character of business
that the corporation ultimately conducted.  Further,  pursuant to A.R.S. ss. ss.
10-301 & 302,  corporations  have the power to pledge property,  borrow and lend
monies,  and  engage in any  lawful  activity."  APS  argues  that the  language
included in its  Articles of  Incorporation  to comply with the  then-applicable
1976 Arizona  Business  Corporation Act did not act as an implied  limitation to
the  broad  "purposes"  paragraph  of the  Articles:  We agree and find that the
financing is for lawful purposes within APS' corporate powers.

     Generally,  a  public  service  corporation  borrowing  funds to lend to an
affiliate  to  refinance  assets  would not be  considered  to be in the  public
interest, to be consistent with sound financial practices,  nor to be within the
proper  performance of its duties as a public service  corporation.  In fact, we
adopted Affiliated Interest Rules in order to ensure that utility ratepayers are
insulated  from  the  dangers   inherent  in  holding  company   structures  and
diversification.  Their purpose is to make sure that ratepayers do not pay rates
for utility  service  that include  costs  associated  with the holding  company
structure,  including financially  beleaguered  affiliates and "sweetheart deals
with  affiliates  intended  to extract  capital  from the  utility to  subsidize
non-utility operations." However, we believe that with the conditions imposed in
this decision,  those goals can be met. Taking into account the events that have
happened in the move to deregulate the electric industry, on both a national and
local basis,  including the current state of the financial  markets,  the public
interest may require  approval of some unusual  requests that  seemingly are not
related to a  utility's  proper  performance  of its duties as a public  service
corporation.  It is under this unique  backdrop that we must analyze  whether we
can make the findings required by statute to approve this financing.

     Approval  of the  financing  will  allow APS to use the  borrowed  funds to
protect its own credit rating, and in that context,  the financing is within the
proper performance of its duties as a public service  corporation.  According to
the rating agencies, APS' health will remain stable, even with the

                                       27                     DECISION NO. 65796
<PAGE>
                                                    DOCKET NO. E-01 345A-02-0707

additional debt. Although Staff found that APS has significant needs for capital
for the regulated  utility  operations over the coming years and issuing debt to
loan to PWEC would  diminish  APS' ability to obtain its own debt  capital,  the
condition  that the loan not exceed four years and APS'  ability to fund capital
expenditures  from  internally-generated  funds together with the restriction on
payment of dividends,  will prevent the financing from impairing APS' ability to
perform  its  service  as a public  service  corporation.  Generally,  a utility
issuing debt to finance  assets owned by an  affiliate  is not  consistent  with
sound financial practices,  but with conditions of Staff, including the security
interest in the PWEC assets and the interest premium paid by PWEC, there will be
no "sweetheart deal" extracting capital from APS. Staff's witness testified that
the financing is not obviously  compatible  with the public  interest,  but with
conditions,  it will protect  APS' credit  rating which will insure that APS can
continue to provide  electric  service to its customers at a reasonable cost. We
conclude  that  APS'  financing  with the  conditions  adopted  herein,  will be
compatible with the public interest if, by preventing a downgrade in APS' credit
rating,  it prevents a  substantial  disintegration  in APS'  ability to provide
service.

     In December 2002,  PWCC raised  approximately  $200 million in net proceeds
from the sale of common stock and the proceeds  were used for debt  reduction at
PWCC.  We  believe  that it is  appropriate  for  PWCC to  improve  its  overall
financial  health,  but  not at the  expense  of  APS  ratepayers.  Accordingly,
consistent  with  APS'  argument  that a  downgrade  to PWCC  would  result in a
downgrade of APS, and in recognition of our approval of the financing, we expect
that PWCC not take any actions  (including  issuing  debt or equity)  that would
result in a downgrade to itself or to APS.

     Through  this  financing  application,  PWCC is  attempting  to  share  the
financial  risks  associated with the PWEC assets with APS. There is no evidence
that APS analyzed the  developing  wholesale  market and requested PWCC to build
such  assets(13),  and in fact,  APS was  obligated  to  purchase  its power for
Standard Offer customers from the competitive market, not through a PPA with its
affiliate.  PWCC's  supposed  claim  "damages as a result of Decision No. 65154"
rings hollow when

----------
(13) Tr. p 281

                                       28                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

one looks at the  circumstances  under which PWEC obtained its investment  grade
credit,  especially  against the  background  of our  admonitions  contained  in
Decision No.  61973,(14) and given APS' witness'  testimony that by the time she
started  talking to bankers  about  refinancing  options in the  fall/winter  of
2001(15),  the options were basically the same as today.  Nevertheless,  we find
ourselves  in the  situation  where it appears that some action must be taken to
prevent APS ratepayers from potential harm resulting from APS' parent's decision
to build  generation  and to finance  that  generation  with "bridge  debt",  in
combination  with  the  circumstances  that  currently  exist  in the  financial
markets. We believe that with the conditions  contained herein,  approval of the
application is in the public interest.

CONTINUING LONG-TERM INDEBTEDNESS

     As of June 30, 2002, APS had total outstanding long-term indebtedness in an
aggregate principal amount of approximately  $2,206,780,000.  Decision No. 55017
(May 6, 1987)(16)  allows APS to have  outstanding up to an aggregate  principal
amount  of  long-term  indebtedness  of  $2,698,917,000.  Accordingly,  APS  has
approximately   $492,137,000   in  additional   long-term   debt   authorization
outstanding. APS views having such a debt margin as a "critical component of the
financing  flexibility  afforded  by the 1986  Order."  (Application  p. 10) APS
requests that the  Commission  maintain the current  margin under the Continuing
Debt limit by not  treating the new debt as  Continuing  Debt under the 1986 and
1984  Orders.  Staff  did not  object  to such  treatment.  Although  we are not
counting the new debt as continuing  debt, we are including the  $500,000,000 in
APS' capital structure for purposes of calculating the minimum 40 percent common
equity ratio requirement for APS to issue, dividends.  Staff testified that "APS
has  significant  needs for capital for regulated  utility  operations  over the
coming  years"  (Exhibit  S-1,  Thornton  p. 1).  APS' needs for capital for its
regulated  public  utility  service  take  precedence  over  PWCC's  desire  for
dividends from APS.  Accordingly,  in the proper  performance of its duties as a
public service corporation,  APS' financial decisions shall be governed by those
duties, and not by the needs of its parent or affiliates.

----------
(14) See Tr. p 275; pp 649-50
(15) Well before Decision No. 65154, issued in September 2002.
(16) The 1986 Order superseded the long-term indebtedness limitation granted APS
     in Decision No. 54230 (November 8, 1984) (1984 Order).

                                       29                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

APS shall not forgo  funding for needed  utility  operations  so that it can pay
dividends to its parent.

ASP DEBT - SECURED OR UNSECURED

     On February 20, 2003, the Federal  Energy  Regulatory  Commission  ("FERC")
issued  a  news  release  "Commission  Sets  New  Conditions  For  Utility  Debt
Acquisition" and on February 21, 2003, issued its "Order Conditionally  Granting
Authorization  to Issue  Long-Term  Unsecured  Debt and Announcing New Policy on
Conditioning  Securities  Authorizations" in Docket No. ES02-52-000,  concerning
Westar Energy, Inc.

     Section 204 of the Federal  Power Act ("FPA")  provides  that  requests for
authority to issue  securities  or assume  liabilities  shall be granted if FERC
finds that the issuance:

     (a)  is for some  lawful  object,  within  the  corporate  purposes  of the
          applicant, and compatible with the public interest, which is necessary
          or appropriate  for or consistent  with the proper  performance by the
          applicant of service as a public utility and which will not impair its
          ability to perform that service,  and (b) is  reasonably  necessary or
          appropriate for such purposes.

     Section  204 of the FPA does not apply to a public  utility  organized  and
operating in a state where its  securities  issuances  are  regulated by a state
commission.  Accordingly,  jurisdiction over APS' financing  application is with
this Commission.  We note the similarities of Arizona's  financing statutes with
Section 204 of the FPA and therefore,  in addition to our consideration of state
law,  will  consider  and  evaluate  APS'  application  in light of FERC's newly
announced conditions. Those conditions are:

     *    public  utilities  seeking  authorization  to issue  debt  backed by a
          utility  asset must use the proceeds of the debt for utility  purposes
          only;

     *    if any utility  assets that secure debt  issuances are 'spun off,' the
          debt must follow the asset and also be 'spun off'

     *    if any of the proceeds from  unsecured  debt are used for  non-utility
          purposes,  the  debt  must  follow  the  non-utility  assets.  If  the
          non-utility  assets are 'spun  off,' then  proportionate  share of the
          debt must follow the 'spun off' non-utility asset; and

     *    if utility assets financed by unsecured debt are 'spun off' to another
          entity,  then a  proportionate  share of the debt  must  also be 'spun
          off'. The  stated  purpose of the  conditions  is "to  prevent  public
          utilities  from borrowing  substantial  amounts of money and diverting
          the proceeds to finance non-utility businesses.

                                       30                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

     Under these FERC conditions, APS could not issue debt secured by its assets
because the proceeds of the debt are not being used for a utility  purpose,  but
are being  used to lend  funds to an  affiliate  to  refinance  affiliate  debt.
Further,  if the funded  non-utility  assets are 'spun off',  then the debt must
follow the  assets.  Under this  analysis,  the  non-utility  assets are already
divested or 'spun off' since they are owned by PWEC,  and APS would  essentially
be acting as a secured  lender.  We believe that our condition to require APS to
obtain a security  interest in the PWEC assets assures that the debt follows the
assets,  and the interest premium paid by PWEC will compensate APS for its risk.
We agree  that it is not in the  public  interest  for APS to use its  assets to
secure its debt and will limit the debt APS issues to  unsecured  debt only.  As
indicated  hereinafter,  we  will  further  condition  approval  on APS  and its
affiliate's  agreement  to be  bound  by  all  the  Affiliated  Interest  Rules,
including  those that APS obtained a waiver from in Decision No.  61973,  during
the terms of the loan and/or guarantee.

PRINCIPLES OF RESOLUTION

     AECC believes that the Commission  should reject certain  provisions of the
Principles of Resolution.  Notwithstanding  Staff and APS' agreement,  any party
may object to the inclusion of those issues in the rate case,  and the presiding
officer can determine the appropriate scope of the  proceeding.(17)  However, as
we said in Decision No.  65154,  "[a]ccordingly,  we will direct Staff to open a
rulemaking  docket to address any required  changes to rules, and will keep this
docket open for parties to file  comments upon what other  decisions/issues  may
need to be revisited." (p. 27) APS' ability to raise these issues may be limited
by the Settlement Agreement, but until such time as that issue is before us, APS
should comply with the terms of the  Settlement  Agreement if it seeks to modify
issues resolved  therein.  Our approval of this financing  application  with the
knowledge that Staff has filed its  Principles of Resolution  does not mean that
we consider the  Commission a party to the 1999  Settlement  Agreement  and have
agreed to reopen the 1999 Settlement  Agreement,  nor is it intended to indicate
our agreement that the issues set forth in the Principles of Resolution  will be
decided  by us in the  rate  case.  The  Staff's  Principles  of  Resolution  is
essentially  an  agreement  by Staff not to object  to APS'  inclusion  of these
issues in the rate case, and does not eliminate APS'

----------
(17) It is possible that other parties may propose to address  additional issues
     as well, such as APS' recovery of stranded costs from its ratepayers.

                                       31                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

obligations  to parties  under the  Settlement  Agreement,  or under A.R.S.  ss.
40-252.  As is clear in our  discussion  herein,  our  decision  to approve  the
financing  application  with the conditions  contained  herein is not based upon
APS'  assertion  that  Decision  No.  65154  "caused  damages to APS" and is not
related to settling the appeal filed by APS.

     APS notes that it can  withdraw  portions of its Track A appeal on its own,
with or without Commission action.

TRACK B - COMPETITIVE PROCUREMENT

     As stated in the Company's  application,  "APS also wishes to make it clear
that  this  Application  does  not  affect  nor is it  intended  to  affect  the
Commission's  consideration of, or the Company's  position on, any of the 'Track
B' issues identified in Commission Docket No.  E-00000A02-0051.  This too was an
express part of the  Commission's  order in Decision No. 65154 (ID. at pp.33-34,
Tenth Ordering Paragraph.)"  (Application p. 4) APS indicates that granting this
application will not give PWEC any advantage in meeting the credit  requirements
in the Track B process,  because PWEC will remain  without an  investment  grade
rating.

     Accordingly,  the public  interest  requires that any improvement in PWEC's
credit worthiness as a result of approval of this financing not be considered or
used  in  the  evaluation  of  bids/offers   during  APS'  Track  B  competitive
procurement.  This will help  neutralize  possible  "preference to an affiliate"
incentives  that may be created  by  approval  of this  financing.  Further,  we
believe that we have structured the Track B proceeding to prevent favoritism.

     Reliant  requests  that  this  Decision  expressly  find that  neither  the
implementation of Track B competitive  solicitation process nor the Commission's
consideration  of whether to authorize APS to acquire PWEC generation  assets or
the rate  base  treatment  will be  prejudiced  or  adversely  affected  by this
Decision.

AFFILIATED INTERESTS RULES

     Pursuant to Decision No. 61973 (October 6, 1999),  APS was granted  various
waivers of the  Commission's  Public  Utility  Holding  Companies and Affiliated
Interests rules. Specifically, APS was granted waivers of:

     *    "R14-2-801(5) and R14-2-803,  such that the term 'reorganization' does
          not include,

                                       32                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

          and no Commission  approval is required for,  corporate  restructuring
          that  does not  directly  involve  the  utility  distribution  company
          ('UCD') in the holding company.  For example,  the holding company may
          reorganize,  form, buy or sell non-UDC  affiliates,  acquire or divest
          interests in non-UDC affiliates,  etc., without Commission  approval";
          R14-2-805(A) "shall apply only to the UDC."
     *    R14-2-805(A)(2)
          R14-2-805(A)(6)
     *    R14-2-805(A)(9), (10),and (11).

R14-2-805(A) provides:

     On or before April 15th of each calendar year, all public utilities meeting
     the  requirements  of R14-2-802 and public utility  holding  companies will
     provide the Commission with a description of diversification  plans for the
     current  calendar  year that have been approved by the Boards of Directors.
     As part of these filings,  each public utility meeting the  requirements of
     R14-2-802 will provide the Commission the following information:

     1.   The name, home office location and description of the public utility's
          affiliates with whom transactions  occur,  their  relationship to each
          other  and  the  public  utility,  and the  general  nature  of  their
          business;

     2    A  BRIEF  DESCRIPTION  OF THE  BUSINESS  ACTIVITIES  CONDUCTED  BY THE
          UTILITY'S AFFILIATES WITH WHOM TRANSACTIONS  OCCURRED DURING THE PRIOR
          YEAR, INCLUDING ANY NEW ACTIVITIES NOT PREVIOUSLY REPORTED;

     3.   A  description  of plans for the utility's  subsidiaries  to modify or
          change  business  activities,  enter into new business  ventures or to
          acquire, merge or otherwise establish a new business entity;

     4.   Copies  of the  most  recent  financial  statements  for  each  of the
          utility's subsidiaries;

     5.   An  assessment  of  the  effect  of  current  and  planned  affiliated
          activities on the public  utility's  capital  structure and the public
          utility's ability to attract capital at fair and reasonable rates;

     6.   THE BASES UPON  WHICH THE PUBLIC  UTILITY  HOLDING  COMPANY  ALLOCATES
          PLANT, REVENUE AND EXPENSES TO AFFILIATES AND THE AMOUNTS INVOLVED; AN
          EXPLANATION OF THE DERIVATION OF THE FACTORS;  THE REASONS  SUPPORTING
          THAT METHODOLOGY AND THE REASONS SUPPORTING THE ALLOCATION;

     7.   An explanation of the manner in which the utility's capital structure,
          cost of capital and ability to raise capital at reasonable  rates have
          been  affected by the  organization  or  reorganization  of the public
          utility holding company;

     8.   The dollar amount  transferred  between the utility and each affiliate
          during the annual period, and the purpose of each transfer;

     9.   CONTRACTS   OR   AGREEMENTS   TO  RECEIVE,   OR  PROVIDE   MANAGEMENT,
          ENGINEERING,  ACCOUNTING,  LEGAL,  FINANCIAL OR OTHER SIMILAR SERVICES
          BETWEEN A PUBLIC UTILITY AND AN AFFILIATE;

     10.  CONTRACTS  OR  AGREEMENTS  TO PURCHASE OR SELL GOODS OR REAL  PROPERTY
          BETWEEN A PUBLIC UTILITY AND AN AFFILIATE; AND

     11.  CONTRACTS  OR  AGREEMENT  TO LEASE  GOODS OR REAL  PROPERTY  BETWEEN A
          PUBLIC UTILITY AND AN AFFILIATE.

     We believe that as a condition to our approval of the financing herein, and
in order to protect APS' security  interests in PWEC's  generation assets and to
promote the public interest, neither

                                       33                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

PWCC nor PWEC shall  reorganize or  restructure,  acquire or divest  assets,  or
form,  buy or  sell  affiliates,  or  pledge  or  otherwise  encumber  the  PWEC
generation  assets  during the  duration  of the  loan/guarantee  without  prior
Commission  approval.   This  requirement  will  apply  to  reorganizations  and
restructurings,  including  the  formation,  buying or  selling  of  affiliates,
acquisitions or divestitures of assets in the amount of $100 million or greater,
measured on a cumulative  basis over the calendar year in which the transactions
will be made. Further, those transactions  identified in the Company's "recovery
plan",  including the  accelerated  sale of SunCor assets in the amount of $80 -
100  million  per year for 3 years;  the sale of 25  percent  of the  Silverhawk
generation  project to the Southern Nevada Water  Authority;  and the payment of
ongoing  construction  costs  for the  West  Phoenix  CC #5 and  the  Silverhawk
generation plant in Nevada would not need prior Commission approval. Further, we
believe that the public  interest  requires  that during the term of the loan or
guarantee,  APS and its affiliates must comply with all the Affiliated  Interest
Rules.  Compliance  with the Rules is, subject to the provisions and limitations
described in this paragraph,  on a going forward basis, and the approval granted
in Decision No.  65434  allowing  APS' $125  million  credit line to PWCC is not
affected.  Accordingly,  we will make this a condition  to our  approval of this
financing application.

     Further,  we believe that a preliminary  inquiry into APS, PWCC, and PWEC's
actions  related  to  the  transition  to  electric  competition,   particularly
compliance with our electric  competition  rules and with Decision No. 61973 and
APS' activities with its affiliates should be undertaken by Staff. Of concern to
us  is  testimony  and  evidence  elicited  during  this  hearing  of  the  PWCC
enterprise's  possible  use of APS  (both  its  generation  assets  and  captive
ratepayers)  to gain advantage in the developing  competitive  environment.  One
example is how APS' Treasurer  described the way that PWEC was able to obtain an
investment grade rating(18); another is APS' application for an air quality

----------
(18) Information provided to the rating agencies by PWCC et al. By the Spring of
     2001,  PWEC  obtained a  contingent  investment  grade  rating.(See  Tr. At
     281-282)  Testimony and evidence  indicate that PWEC made  presentations to
     rating agencies  indicating that PWEC was under contract to sell its output
     to APS under a four year purchase  power  agreement.  (See Panda Exh. 4, 5,
     Gomez Tr. At 150,  276) In  September,  2002,  APS asked the credit  rating
     agencies to withdraw PWEC's credit rating.  APS would have been required to
     begin  purchasing  100% of its  standard  offer power from the  competitive
     market by January 1, 2001,  if it had not  obtained a 2 year  waiver in its
     Settlement  Agreement.  During  that  2 year  period,  APS'  parent  formed
     competitive   affiliates,   including  PWEC,  and  PWCC/PWEC  built  4  new
     generating  units and  obtained a  contingent  investment  grade rating for
     PWEC.  If the  Commission  had not stayed  divestiture  of its  assets,  on
     January 1, 2003,  APS would have been  acquiring 100% of its standard offer
     power  from the  competitive  market,  with no  ability to change its rates
     until at least July,  2004.  APS' position in this  application  that these
     assets were "dedicated.:

                                       34                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707


permit on behalf of PWEC.  Although some may argue that our granting approval of
the financing request is another example,  we have carefully tried to neutralize
any  competitive  advantage that may accrue to PWEC as a result of our approval.
Nothing in this Decision  condones  actions  taken by APS,  PWEC, or PWCC, it is
merely an attempt to prevent harm to APS  ratepayers.  Additionally,  we are not
intending our approval to constitute  state action for the purposes of antitrust
laws.

     When  asked  whether  Decision  No.  61973  was  presented  as  part of the
presentation to the rating agencies,  APS' Treasurer responded that: "[w]ell, we
would have modeled what the Order  required in our  presentation,  yes." (Gomez,
Tr. p. 275) When asked whether she was familiar  with the  following  quote from
Decision No.  61973 at p. 10 which  states:  "[w]e share the  concerns  that the
noncompetitive  portion of APS not  subsidize  the spun-off  competitive  assets
through an unfair  financial  arrangement",  APS Treasurer Gomez stated that she
was not familiar with that sentence.  (Gomez,  Tr. p. 275). Ms. Gomez  testifies
that there was no contract, but was a modeling assumption. She further testified
that the  investment  grade  rating was not based upon just the  unification  of
assets,  but it is also based upon the cash flow from those assets.  (Gomez, Tr.
pp. 277-278; 281-282) During cross-examination of Jack Davis, he testified about
documents  prepared  by  PWEC  for a  Rating  Agency  Presentation  in  February
2001.(19)  Mr.  Davis  testified  that the  document  discussed  a "PPA  between
Pinnacle  West Power  Marketing & Trading,  and Pinnacle West Energy" and also a
PPA between  APS and it "goes on to  represent  how  Pinnacle  West  Marketing &
Trading  will make  those  deliveries  to Arizona  Public  Service."  Mr.  Davis
testified  that a page  entitled  "PWEC Credit  Strengths  shows the first arrow
indicates  "Four year fixed price  contract"  and "The majority of generation is
dedicated to APS load through 2004". (Tr. pp. 729-730)

     The date of 2004 is significant,  because the APS rates set in Decision No.
61973  were to remain in effect  until at least  June 30,  2004.  However,  from
January 1, 2003 until June 30,  2004,  APS was to be  purchasing  power from the
competitive market (without an adjustor in place) and would have been exposed to
the price difference between the "market price" and the APS Standard

----------
     to APS customers raises the issue of possible intended  noncompliance  with
     the    Commission's    electric    competition    rules   and/or   possible
     anti-competitive activity.
(19) Panda Exhibit 22 was admitted under seal, but the cross  examination of Mr.
     Davis  was  not  confidential.  This  discussion  will  refer  only  to the
     non-confidential testimony on that document.

                                       35                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

Offer rates.

     Decision No. 61973 provided that: "Such Code of Conduct should also include
provisions  to govern the supply of  generation  during the  two-year  period of
delay for the transfer of  generation  assets so that APS doesn't give itself an
undue advantage over the ESPs". (p. 12)

     "Some  parties were  concerned  that Sections 4.1 and 4.2 provide in effect
that the  Commission  will have  approved  in  advance  any  proposed  financing
arrangements  associated with future transfers of `competitive  services' assets
to an affiliate.  As a result,  there was a  recommendation  that the Commission
retain  the  right to  review  and  approve  or reject  any  proposed  financing
arrangements.  In  addition,  some  parties  expressed  concern that APS has not
definitively  described  the assets it will retain and which it will transfer to
an affiliate.  We share the concerns that the non-competitive portion of APS not
subsidize  the  spun-off   competitive   assets  through  an  unfair   financial
arrangement.  We  want to  make  it  clear  that  the  Commission  will  closely
scrutinize  the  capital  structure  of APS at its 2004  rate  case and make any
necessary adjustments." (Decision No. 61973 at p. 10)

     Although  APS  asserts  that  under  its  Code  of  Conduct,  the  Electric
Competition  Rules,  and Decision No. 61973, it could not construct  generation,
Staff,  in its  Responsive  Brief,  states that "APS will argue that its code of
conduct prevented it from building the assets at APS, (Tr. at 520); nonetheless,
an  examination  of that  document  does not clearly  support that  conclusion."
(Staff Responsive Br. at 5).

MISCELLANEOUS

     The  issue  transferring  PWEC  assets  to  APS is not  before  us in  this
application.  RUCO  recommended  that we approve this financing and order APS to
file an  application  to transfer  the  assets.  APS  indicated  it would not be
appropriate for the Commission to require a proceeding  seeking  transfer of the
PWEC assets to APS at this time,  and  believes  that  Staff's  Condition  No. 2
provides   essentially   the  same   protection.   We  will  not  adopt   RUCO's
recommendation.

                              * * * * * * * * * *

     Having  considered  the entire record herein and being fully advised in the
premises, the Commission finds, concludes, and orders that:

                                       36                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

                                FINDINGS OF FACT

     l. APS is a public service  corporation  principally  engaged in furnishing
electricity  in the State of Arizona.  APS provides  either  retail or wholesale
electric service to substantially  all of Arizona,  with the major exceptions of
the Tucson  metropolitan  area and about  one-half of the  Phoenix  metropolitan
area. APS also generates,  sells and delivers electricity to wholesale customers
in the western United States.

     2. On September 16, 2002, APS filed an application  requesting  approval of
financing in the form of either an inter-company loan and/or a guarantee of debt
to  allow  PWCC  or  PWEC  to  refinance  bridge  debt  incurred  by PWCC in the
construction of certain PWEC generation assets.

     3. Notice of the application was provided in accordance with the law.

     4. Intervention was granted to RUCO, Panda,  Reliant,  Harquahala,  the PPL
entities, AUIA, SWPG/Bowie, Sempra, AECC, ACPA and TEP.

     5. The hearing  commenced on January 8, 2003 and testimony and evidence was
taken over five days of hearing.  Initial Briefs were filed on January 27, 2003,
and Reply Briefs were filed on February 6, 2003.

     6. APS'  parent,  PWCC,  has  incurred  approximately  $1  billion  in debt
financing the construction of generating units at PWEC, its merchant subsidiary.

     7. PWCC used debt with short-term maturities because it planned for PWEC to
refinance the debt at an  investment  grade once the APS  rate-based  generation
assets were transferred to PWEC.

     8. In the spring of 2001,  PWCC made  presentations  to rating  agencies on
behalf of PWEC and obtained a contingent investment grade rating for PWEC.

     9. By the fall of 2001,  project  financing for the PWEC generation  assets
was no longer available.

     10. On  October  18,  2001,  APS filed an  application  for  approval  of a
Variance/Purchased  Power Agreement.  The application  stated that "adherence to
the competitive bidding  requirements of the Electric Competition Rules will not
produce the intended  result of reliable  electric  service for  Standard  Offer
customers at reasonable  rates,"  requested that the Commission  grant a partial
variance to  R14-2-1606(B)  that would otherwise  obligate APS to acquire all of
its customers' Standard Offer

                                       37                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

generation  requirements  from the  competitive  market,  and sought  Commission
approval of a long term purchase power agreement with its parent, PWCC.

     11. By  Procedural  Order  issued May 2,  2002,  a generic  proceeding  was
established  that set up Track A to resolve  issues  relating  to market  power,
divestiture,  codes of conduct/affiliate transactions and jurisdictional issues,
and Track B to address competitive procurement.

     12. On September 10, 2002, the Commission  issued Decision No. 65154 in the
Track A  proceeding  wherein the  Commission  ordered APS to cancel any plans to
divest interests in any generating assets:

     13. On March 14,  2003,  the  Commission  issued  Decision No.  65743,  the
Decision in the Track B proceeding.

     14. Currently,  there is turmoil in the financial markets and the wholesale
electric market is volatile.

     15. APS seeks  authorization  to issue up to $500 million of debt,  and APS
would loan the proceeds of that debt to PWCC or PWEC to be used to retire PWCC's
existing debt.

     16. In addition,  or in the  alternative,  APS seeks  approval to guarantee
debt that may be issued by PWCC or PWEC to retire PWCC's existing debt.

     17. The total amount of financing  authority requested does not exceed $500
million.

     18. RUCO recommended  approval of the loan with conditions,  including that
the Commission require APS to file an application to transfer the PWEC assets to
APS.

     19. Panda and various intervenors recommended that the Commission not grant
the requested financing,  but if some financing is approved, it should be in the
form of a guarantee with certain conditions.

     20. Staff  recommended  that the  Commission  authorize  APS to borrow $500
million in order to loan the proceeds to PWEC, with seven conditions.

     21. As a certificated public service corporation, APS has a duty to provide
reliable electric service to its customers at reasonable rates.

     22. It is in the public  interest that APS maintain  healthy credit ratings
so that it has access to the capital markets at reasonable terms and rates.

                                       38                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

     23. APS could face a downgrade if PWCC is downgraded,  and such a downgrade
of APS could  interfere  with APS'  ability to provide  electric  service to the
public at  reasonable  rates if it resulted in increases in the cost of capital,
potential  lack  of  access  to the  capital  markets,  potential  increases  in
collateral requirements, and an inability to do business with vendors.

     24. APS' requested  financing will be compatible  with the public  interest
if, by preventing a downgrade in APS' credit ratings,  it prevents a substantial
disintegration in APS' ability to provide reliable service at reasonable rates.

     25.  Because  the  transaction  poses some risks to the  Company and to its
ratepayers,  we will require conditions to approval of the financing,  including
Staff's seven conditions and conditions that the debt authorized  herein will be
included in the capital structure calculation to determine whether APS can issue
dividends; that any guarantee shall meet the same concerns identified in Staff's
seven conditions; APS shall inform the Commission in the event of a loan default
so that the Commission can take appropriate  action;  APS', debt issuance be for
unsecured debt only; that neither PWCC nor PWEC shall reorganize or restructure,
acquire  or  divest  assets,  or form,  buy or sell  affiliates,  or  pledge  or
otherwise  encumber  the PWEC  generation  assets  during  the  duration  of the
loan/guarantee without prior Commission approval and this requirement will apply
to  reorganizations  and  restructurings,  including  the  formation,  buying or
selling of affiliates,  acquisitions  or divestitures of assets in the amount of
$100 million or greater,  measured on a cumulative  basis over the calendar year
in which the transactions will be made. Further,  those transactions  identified
in the  Company's  "recovery  plan",  including the  accelerated  sale of SunCor
assets in the amount of $80 - 100 million  per year for 3 years,  the sale of 25
percent of the  Silverhawk  generation  project  to the  Southern  Nevada  Water
Authority, and the payment of ongoing construction costs for the West Phoenix CC
#5 and the Silverhawk generation plant in Nevada would not need prior Commission
approval;  and  that  during  the  term of the  loan or  guarantee,  APS and its
affiliates must comply with all the Affiliated  Interest Rules.  Compliance with
the Rules is,  subject  to the  provisions  and  limitations  described  in this
paragraph,  on a going forward basis,  and the approval  granted in Decision No.
65434 allowing APS' $125 million credit line to PWCC is not affected.

     26.  Staffs  Condition 2 requires APS to obtain a security  interest in the
PWEC assets and

                                       39                     DECISION NO. 65796
<PAGE>
                                                    DOCKET NO. E-01 345A-02-0707

only APS has such a lien, so APS would have the first priority in the event of a
default.

     27. APS shall  immediately  notify the Commission within five business days
in the  event  of a  default  on the  loan,  so that  the  Commission  can  take
appropriate action.

     28.  The  public   interest   requires  that  any   improvement  in  PWEC's
creditworthiness  as a result of approval of this financing not be considered or
used  in  the  evaluation  of  bids/offers   during  APS'  Track  B  competitive
procurement.

     29. It is in the public  interest to grant  authority for both a loan and a
guarantee with the conditions  attached  hereto,  so that Arizona Public Service
can structure the  transaction in a manner that will provide the most protection
for its ratepayers.

     30. The issue of the  purpose  for which the PWEC  assets were built is not
before us in this  proceeding,  and we are making no determination as to whether
or not those assets should be part of APS' rate base.

     31. Testimony and evidence presented during the hearing merit a preliminary
inquiry by Staff into APS'  compliance  with  Decision No.  61973,  the Electric
Competition Rules, its Code of Conduct, and applicable law.

                               CONCLUSIONS OF LAW

     1. Arizona Public Service  Company is a public service  corporation  within
the meaning of Article XV of the Arizona  Constitution and A.R.S. ss.ss. 40-285,
-301, and 40-302 and A.A.C. R-14-2804.

     2. The Commission has jurisdiction  over Arizona Public Service Company and
the subject matter of the application.

     3. Notice of the application was provided in accordance with the law.

     4. APS'  application  should be approved  consistent  with the  Discussion,
Analysis, and Findings of Fact herein.

     5. The financing with the conditions approved herein is for lawful purposes
within Arizona Public Service Company's corporate powers, is compatible with the
public interest, with sound financial practices, and with the proper performance
by Arizona Public Service Company of

                                       40                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

service  as a public  service  corporation,  and with  the  conditions  approved
herein, will not impair Arizona Public Service Company's ability to perform that
service.

     6. The financing  with the conditions  approved  herein is for the purposes
stated in the  application and is reasonably  necessary for those purposes,  and
such  purposes may,  wholly or in part,  be  reasonably  chargeable to operating
expenses or to income.

     7. The financing  with the conditions  approved  herein will not impair the
financial  status of the public  utility,  otherwise  prevent it from attracting
capital  at fair and  reasonable  terms,  or impair  the  ability  of the public
utility to provide safe, reasonable and adequate service.

                                      ORDER

     IT IS  THEREFORE  ORDERED  that the  application  for  financing,  with the
conditions  contained  herein,  is hereby  approved and Arizona  Public  Service
Company is hereby  authorized to either issue  non-secured debt in an amount not
greater  than  $500,000,000  and loan  the  proceeds  to  Pinnacle  West  Energy
Corporation and/or guarantee the debt of Pinnacle West Energy Corporation in the
amount of  $500,000,000,  for the purposes set forth in the  application  and as
modified  herein,  and  in  compliance  with  the  conditions  and  restrictions
contained in the discussion and findings herein.

     IT IS FURTHER  ORDERED that such debt will not be  classified or treated as
continuing  debt in the context of the debt limits  established by Decision Nos.
55017 and 54230.

     IT IS  FURTHER  ORDERED  that  Arizona  Public  Service  Company  is hereby
authorized  to obtain a financial  interest  and/or a guarantee in its affiliate
Pinnacle West Energy  Corporation  consistent  with the terms,  conditions,  and
restrictions of this Decision.

     IT IS  FURTHER  ORDERED  that  Arizona  Public  Service  Company  is hereby
authorized to engage in any transactions  and to execute any document  necessary
to effectuate the authorization granted herein.

     IT IS FURTHER  ORDERED that such  authority is expressly  conditioned  upon
Arizona Public Service Company's  compliance with the conditions set forth below
in this ordering paragraph and upon the use of the proceeds for the purposes set
forth in the application as modified herein. The conditions are:

                                       41                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

     1)   APS should be authorized  to issue and sell no more than  $500,000,000
          of debt in addition to its current authorizations;

     2)   The debt to be lent to PWEC  should  be no more than  $500,000,000  of
          secured  callable notes from PWEC.  The security  interest shall be on
          the same terms as the  security  interest  APS already has pursuant to
          the $125,000,000 loan authorization from Decision No. 65434;

     3)   The PWEC  secured  note  coupon  shall be 264 basis  points  above the
          coupon on APS debt issued and sold on equivalent  terms (including but
          not limited to maturity and security);

     4)   The  difference  in interest  income and  interest  expense  should be
          capitalized  as a  deferred  credit  and used to  offset  rates in the
          future. The deferred credit balance shall bear an interest rate of six
          percent;

     5)   The PWEC debt maturity shall not exceed four years,  unless  otherwise
          ordered by the Commission;

     6)   Any  demonstrable  increase in APS' cost of capital as a result of the
          transaction,  such as from a decline in bond rating, will be extracted
          from future rate cases;

     7)   APS shall maintain a minimum common equity of 40 percent and shall not
          be allowed to pay  dividends if such  payment  would reduce its common
          equity  ratio below this  threshold,  unless  otherwise  waived by the
          Commission.  This condition shall remain in effect  indefinitely,  and
          APS shall file with the Commission a calculation of capital  structure
          within one week of filing a 10-Q or 10-K;

     8)   The debt authorized  herein will be included in the capital  structure
          calculation to determine whether APS can issue dividends;

     9)   Any guarantee shall meet the same concerns identified in Staff's seven
          conditions;

     10)  APS' debt issuance be for unsecured debt only;

     11)  Neither  PWEC or PWCC  shall  reorganize  or  restructure,  acquire or
          divest assets, or form buy or sell affiliates,  or pledge or otherwise
          encumber  the  PWEC  generation  assets  during  the  duration  of the
          loan/guarantee  without prior Commission approval and this requirement
          will  apply  to  reorganizations  and  restructurings,  including  the
          formation,   buying  or  selling  of   affiliates,   acquisitions   or
          divestitures  of assets  in the  amount of $100  million  or  greater,
          measured on a  cumulative  basis over the  calendar  year in which the
          transactions will be made. Further,  those transactions  identified in
          the  Company's  "recovery  plan",  including the  accelerated  sale of
          SunCor assets in the amount of $80 - 100 million per year for 3 years;
          the sale of 25 percent  of the  Silverhawk  generation  project to the
          Southern   Nevada  Water   Authority;   and  the  payment  of  ongoing
          construction  costs  for the  West  Phoenix  CC #5 and the  Silverhawk
          generation plant in Nevada would not need prior  Commission  approval;
          and

                                       42                     DECISION NO. 65796
<PAGE>
                                                    DOCKET NO. E-01 345A-02-0707

     12)  During the term of the loan or guarantee,  APS and its affiliates must
          comply with all the Affiliated  Interest  Rules.  Compliance  with the
          Rules is, subject to the provisions and limitations  described in this
          paragraph,  on a going  forward  basis,  and the  approval  granted in
          Decision No. 65434  allowing APS' $125 million  credit line to PWCC is
          not affected.

     IT IS FURTHER  ORDERED  that with  respect to any waiver  sought by Arizona
Public Service Company under Condition No. 7, the Commission  shall process such
waiver request within 60 days and, for this 60-day period,  the condition  shall
be suspended.  However,  Condition No. 7 shall not be permanently waived without
an order of the Commission.

     IT IS FURTHER  ORDERED that approval of the financing set forth herein does
not  constitute  or imply  approval  or  disapproval  by the  Commission  of any
particular  expenditure of the proceeds  derived thereby or any particular prior
expenditure being refinanced for the purpose of establishing just and reasonable
rates.

     IT IS FURTHER  ORDERED that Arizona Public Service  Company shall file with
the  Commission  copies of all executed  financing  documents  setting forth the
terms of the financing, within 30 days of obtaining such financing.

     IT IS FURTHER ORDERED that Arizona Public Service Company shall not use any
authority  granted  in this  Decision  to  prejudice  or  adversely  affect  the
implementation of the Track B competitive solicitation process.

     IT IS FURTHER  ORDERED that the issue of Arizona Public  Service  Company's
acquisition of Pinnacle West Energy Corporation  generation assets and rate base
treatment  is not  presently  before us, and we make no  determination  on those
issues in this Decision.

     IT IS  FURTHER  ORDERED  that  any  improvement  in  Pinnacle  West  Energy
Corporation's  creditworthiness  as a result of approval of this financing shall
not be considered or used in the evaluation of bids/offers during Arizona Public
Service Company's Track B competitive procurement.

     IT IS FURTHER ORDERED that Arizona Public Service Company shall immediately
notify the Commission within five business days in the event of a default on the
loan, so that the Commission can take appropriate action.

                                       43                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

     IT IS FURTHER ORDERED that Staff shall commence a preliminary  inquiry into
Arizona Public Service Company and its affiliate's  compliance with the Electric
Competition Rules, Decision No. 61973, its Code of Conduct, and applicable law.

     IT  IS  FURTHER   ORDERED  that  this  Decision  shall  be  come  effective
immediately. BY ORDER OF THE ARIZONA CORPORATION COMMISSION.


MARC SPITZER                      JIM IRVIN                   WILLIAM A. MUNDELL
--------------------------------------------------------------------------------
CHAIRMAN                          COMMISSIONER                      COMMISSIONER


JEFF HATCH-MILLER
--------------------------------------------------------------------------------
COMMISSIONER                      COMMISSIONER


                                   IN  WITNESS  WHEREOF,  I,  BRIAN  C.  McNEIL,
                                   Executive    Secretary    of   the    Arizona
                                   Corporation Commission,  have hereunto set my
                                   hand  and  caused  the  official  seal of the
                                   Commission  to be - fixed at the Capitol,  in
                                   the City of  Phoenix,  this 4th day of April,
                                   2003.


                                   BRIAN C. McNEIL
                                   ---------------------------------------------


DISSENT Mike Gleason
        ------------------------------------
LAF:dap

                                       44                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

SERVICE LIST FOR:                                 ARIZONA PUBLIC SERVICE COMPANY
DOCKET NOS.:                                      E-01345A-02-0707


Jeffrey B. Guldner
SNELL & WILMER
One Arizona Center
400 E. Van Buren
Phoenix, Arizona 85004

Thomas L. Mumaw
Karilee Ramaley
PINNACLE WEST CAPITAL CORP
LAW DEPARTMENT
P.O. Box 53999, MS 8695
Phoenix, Arizona 85004-3999

C. Webb Crockett
Jay L. Shapiro
FENNEMORE CRAIG
3003 N. Central Avenue, Suite 2600
Phoenix, Arizona 85012
Attorney for Panda Gila River, L.P.

Larry F. Eisenstat
Michael R. Engleman
Frederick D. Ochsenhirt
DICKSTEIN SHAPIRO MORIN & OSHINSKY LLP
2101 L Street, NW
Washington, DC 20037
Attorneys for Panda Gila River, L.P.

Scott Wakefield
RUCO
1110 W. Washington, Suite 200
Phoenix, Arizona 85007

William P. Sullivan
Michael A. Curtis
2712 N. 7th Street
Phoenix, Arizona 85006-1090
Attorneys for Reliant Resources, Inc.

                                       45                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

Roger K. Ferland
QUARLES & BRADY STRETCH LANG, LLP
Renaissance One
Two North Central Avenue
Phoenix, Arizona 85004-2391
Attorneys for Harquahala Generating Company, LLC

Jay I. Moyes
MOYES STOREY
3003 N. Central Ave., Suite 1250
Phoenix, Arizona 85012
Attorneys for PPL Southwest Generation Holdings, LLC:
PPL Energy Plus, LLC; and PPL Sundance Energy, LLC

Jesse A. Dillon
PPL
2 North Ninth Street
Allentown, Pennsylvania 18101

Walter W. Meek AUIA
2100 N. Central Ave., Suite 210
Phoenix, Arizona 85004

Lawrence V. Robertson, Jr.
MUNGER CHADWICK
National Bank Plaza
333 N. Wilmot, Suite 300
Tucson, Arizona 85711
Attorneys for Southwestern Power Group II, LLC; Bowie Power Station; and
Sempra Energy Resources

Greg Patterson
ACPA
5432 E. Avalon
Phoenix, Arizona 85018

Raymond S. Heyman
Michael W. Pattern
ROSHKA, HEYMAN & DeWULF
One Arizona Center
400 E. Van Buren, Suite 800
Phoenix, Arizona 85004
Attorneys for Tucson Electric Power Co.

                                       46                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

Christopher Kempley, Chief Counsel
ARIZONA CORPORATION COMMISSION
Legal Division
1200 West Washington
Phoenix, AZ 85007

Ernest Johnson, Director
Utilities Division
ARIZONA CORPORATION COMMISSION
1200 West Washington Street
Phoenix, Arizona 85007

                                       47                     DECISION NO. 65796
<PAGE>
                                                     DOCKET NO. E-01345A-02-0707

                         DISSENT OF COMMISSIONER GLEASON

I respectfully dissent from my fellow  Commissioners  regarding the Commission's
approval of APS's request to loan PWEC up to $500  million.  While I believe the
record  supports  APS's claim that PWEC needs APS's credit  support to refinance
its debt,  a  guarantee  is the only type of  refinancing  that is in the public
interest.

By this  order,  the  Commission  approved a  speculative  loan from a regulated
utility to an unregulated company with less than investment credit rating, which
will put the utility over its mandated debt ceiling.

The following support this statement:

     1.   There is no list of collateral for this loan.

     2.   There is no  appraisal  of  assets to be used as  collateral  for this
          loan.

     3.   The  banks  will not  make  the  loan;  thus it must be  considered  a
          speculative loan.

     4.   The  exclusion  of this loan from APS's  continuing  credit  will,  by
          testimony,  put APS's debt over the  mandated  ceiling.  This  tacitly
          increases the debt limit when utilities are under pressure to conserve
          their financial debts.

Thus, the Commission  authorized a speculative use of a regulated utilities fund
which could put the ratepayers at risk of higher rates.

Furthermore,  the fundamental principles of the Commission's Affiliated Interest
Rules prohibit  exactly this type of situation.  To preserve  competition and to
maintain the integrity of our Affiliated  Interest Rules, a lending  institution
needs to stand in between PWEC assets and APS.

The Order  requires APS to  refinance  PWEC debt in a manner that is in the best
interest of the  ratepayers.  To that end,  it is my belief APS should  choose a
guarantee. Since the Order allows APS to select a loan, I must dissent.

                                       48                     DECISION NO. 65796

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99.5
<SEQUENCE>10
<FILENAME>ex99-4.txt
<DESCRIPTION>PINNACLE WEST RISK FACTORS
<TEXT>
                                                                    Exhibit 99.4

                                  RISK FACTORS

Set forth below and in other documents we file with the Securities and Exchange
Commission ("SEC") are risks and uncertainties that could affect our financial
results.

WE ARE SUBJECT TO COMPLEX GOVERNMENT REGULATION WHICH MAY HAVE A NEGATIVE IMPACT
ON OUR BUSINESS AND OUR RESULTS OF OPERATIONS.

We are, directly and through our subsidiaries, subject to governmental
regulation which may have a negative impact on our business and results of
operations. We are a "holding company" within the meaning of the Public Utility
Holding Company Act ("PUHCA"); however, we are exempt from the provisions of
PUHCA by virtue of our filing of an annual exemption statement with the SEC.

Arizona Public Service Company ("APS") is subject to comprehensive regulation by
several federal, state and local regulatory agencies, which significantly
influence its operating environment and may affect its ability to recover costs
from utility customers. APS is required to have numerous permits, approvals and
certificates from the agencies that regulate APS' business. The Federal Energy
Regulatory Commission ("FERC"), the Nuclear Regulatory Commission ("NRC"), the
Environmental Protection Agency ("EPA"), and the Arizona Corporation Commission
("ACC") regulate many aspects of our utility operations, including siting and
construction of facilities, customer service and the rates that APS can charge
customers. We believe the necessary permits, approvals and certificates have
been obtained for APS' existing operations. However, we are unable to predict
the impact on our business and operating results from the future regulatory
activities of any of these agencies. Changes in regulations or the imposition of
additional regulations could have an adverse impact on our results of
operations.

WE CANNOT PREDICT THE OUTCOME OF THE GENERAL RATE CASE THAT APS WILL FILE WITH
THE ACC ON OR BEFORE JUNE 30, 2003.

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

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

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

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

The general rate case will also address the implementation of rate adjustment
mechanisms that were the subject of ACC hearings in April 2003. The rate
adjustment mechanisms, which were authorized as a result of the 1999 Settlement
Agreement, would allow APS to recover several types of costs, the most
significant of which are power supply costs (fuel and purchased power costs) and
costs associated with complying with the ACC retail electric competition rules
described below. We assume that the ACC will make a decision in this general
rate case by the end of 2004. We cannot predict the outcome of the rate case and
the resulting levels of regulated revenues.
<PAGE>
IF WE ARE NOT ABLE TO ACCESS CAPITAL AT COMPETITIVE RATES, OUR ABILITY TO
IMPLEMENT OUR FINANCIAL STRATEGY WILL BE ADVERSELY AFFECTED.

We rely on access to both short-term money markets and longer-term capital
markets as a significant source of liquidity and for capital requirements not
satisfied by the cash flow from our operations. We believe that we will maintain
sufficient access to these financial markets based upon current credit ratings.
However, certain market disruptions or a downgrade of our credit rating may
increase our cost of borrowing or adversely affect our ability to access one or
more financial markets. Such disruptions could include:

     *    an economic downturn;

     *    capital market conditions generally;

     *    the bankruptcy of an unrelated energy company;

     *    market prices for electricity and gas;

     *    terrorist attacks or threatened attacks on our facilities or those of
          unrelated energy companies; or

     *    the overall health of the utility industry.

Changes in economic conditions could result in higher interest rates, which
would increase our interest expense on our debt and reduce funds available to us
for our current plans. Additionally, an increase in our leverage could adversely
affect us by:

     *    increasing the cost of future debt financing;

     *    increasing our vulnerability to adverse economic and industry
          conditions;

     *    requiring us to dedicate a substantial portion of our cash flow from
          operations to payments on our debt, which would reduce funds available
          to us for operations, future business opportunities or other purposes;
          and

     *    placing us at a competitive disadvantage compared to our competitors
          that have less debt.

See the following Risk Factor for more information relating to this discussion.

A SIGNIFICANT REDUCTION IN OUR CREDIT RATINGS COULD MATERIALLY AND ADVERSELY
AFFECT OUR BUSINESS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

We cannot be sure that any of our current ratings will remain in effect for any
given period of time or that a rating will not be lowered or withdrawn entirely
by a rating agency if, in its judgment, circumstances in the future so warrant.
Any downgrade could increase our borrowing costs which would diminish our
financial results. We would likely be required to pay a higher interest rate in
future financings, and our potential pool of investors and funding sources could
decrease. A downgrade could require additional support in the form of letters of
credit or cash or other collateral and otherwise have a material adverse effect
on our business, financial condition and results of operations. If our
short-term ratings were to be lowered, it could limit our access to the
commercial paper market. We note that the ratings from credit agencies are not
recommendations to buy, sell or hold our securities and that each rating should
be evaluated independently of any other rating.

DEREGULATION OR RESTRUCTURING OF THE ELECTRIC INDUSTRY MAY RESULT IN INCREASED
COMPETITION, WHICH COULD HAVE A SIGNIFICANT ADVERSE IMPACT ON OUR BUSINESS AND
OUR FINANCIAL RESULTS.

Retail competition could have a significant adverse financial impact on us due
to an impairment of assets, a loss of retail customers, lower profit margins or
increased costs of capital. In 1999, the ACC approved rules that provide a

                                       2
<PAGE>
framework for the introduction of retail electric competition in Arizona. Under
the rules, as modified by the 1999 Settlement Agreement, APS was required to
transfer all of its competitive electric assets and services to an unaffiliated
party or parties or to a separate corporate affiliate or affiliates no later
than December 31, 2002. Pursuant to an ACC order dated September 10, 2002, the
ACC unilaterally modified the 1999 Settlement Agreement and directed APS to
cancel any plans to divest interests in any of its generating assets. The ACC
has further established a requirement that APS solicit bids for certain
estimated capacity and energy requirements for periods beginning July 1, 2003.
These regulatory developments and legal challenges to the rules have raised
considerable uncertainty about the status and pace of retail electric
competition in Arizona. Although some very limited retail competition existed in
APS' service area in 1999 and 2000, there are currently no active retail
competitors offering unbundled energy or other utility services to APS'
customers. As a result, we cannot predict when, and the extent to which,
additional competitors will re-enter APS' service territory.

As a result of changes in federal law and regulatory policy, competition in the
wholesale electricity market has greatly increased due to a greater
participation by traditional electricity suppliers, non-utility generators,
independent power producers, and wholesale power marketers and brokers. This
increased competition could affect our load forecasts, plans for power supply
and wholesale energy sales and related revenues. As a result of the changing
regulatory environment and the relatively low barriers to entry, we expect
wholesale competition to increase. As competition continues to increase, our
financial position and results of operations could be adversely affected.

THE PROCUREMENT OF WHOLESALE POWER BY APS WITHOUT THE ABILITY TO ADJUST RETAIL
RATES COULD HAVE AN ADVERSE IMPACT ON OUR BUSINESS AND FINANCIAL RESULTS.

The 1999 Settlement Agreement limits APS' ability to change retail rates until
at least July 1, 2004, which could have a significant adverse financial impact
on us if wholesale power prices significantly exceed the amount included for
generation costs in APS' current bundled retail rates. Under the ACC's rules,
APS is the "provider of last resort" for standard-offer, full-service customers
under rates that have been approved by the ACC. These rates are established
until at least July 1, 2004. The 1999 Settlement Agreement allows APS to seek
adjustment of these rates in the event of emergency conditions or circumstances,
such as the inability to secure financing on reasonable terms; material changes
in APS' cost of service for ACC-regulated services resulting from federal,
tribal, state or local laws; regulatory requirements; or judicial decisions,
actions or orders. Energy prices in the western wholesale market vary and,
during the course of the last two years, have been volatile. At various times,
prices in the spot wholesale market have significantly exceeded the amount of
generation costs per kilowatt hour included in APS' current retail rates. In the
event of shortfalls due to unforeseen increases in load demand or generation or
transmission outages, APS may need to purchase additional supplemental power in
the wholesale spot market. The ACC has further established a requirement that
APS solicit bids for certain estimated capacity and energy requirements for
periods beginning July 1, 2003. This competitive procurement process may
adversely affect the cost of APS' procurement of wholesale power. In sum, there
can be no assurance that APS would be able to fully recover the costs of
wholesale power under its present rate structure. Although APS could seek to
adjust its rates under the emergency provisions of the settlement agreement
discussed above, ACC approval of such an adjustment also cannot be assured.

RECENT EVENTS IN THE ENERGY MARKETS THAT ARE BEYOND OUR CONTROL MAY HAVE
NEGATIVE IMPACTS ON OUR BUSINESS.

As a result of the energy crisis in California during the summer of 2001, the
recent volatility of natural gas prices in North America, the filing of
bankruptcy by the Enron Corporation, and investigations by governmental
authorities into energy trading activities, companies generally in the regulated
and unregulated utility businesses have been under an increased amount of public
and regulatory scrutiny. The capital markets and ratings agencies also have
increased their level of scrutiny. We believe that we are complying with all
applicable laws, but it is difficult or impossible to predict or control what
effect these or related issues may have on our business or our access to the
capital markets.

                                       3
<PAGE>
OUR RESULTS OF OPERATIONS CAN BE ADVERSELY AFFECTED BY MILDER WEATHER.

Weather conditions directly influence the demand for electricity and affect the
price of energy commodities. Electric power demand is generally a seasonal
business. In Arizona, demand for power peaks during the hot summer months, with
market prices also peaking at that time. As a result, our overall operating
results fluctuate substantially on a seasonal basis. In addition, we have
historically sold less power, and consequently earned less income, when weather
conditions are milder. As a result, unusually mild weather could diminish our
results of operations and harm our financial condition.

THERE ARE INHERENT RISKS IN THE OPERATION OF NUCLEAR FACILITIES, SUCH AS
ENVIRONMENTAL, HEALTH AND FINANCIAL RISKS AND THE RISK OF TERRORIST ATTACK.

Through APS, we have an ownership interest in and operate the Palo Verde Nuclear
Generating Station ("Palo Verde"). Palo Verde is subject to environmental,
health and financial risks such as the ability to dispose of spent nuclear fuel,
the ability to maintain adequate reserves for decommissioning, potential
liabilities arising out of the operation of these facilities, and the costs of
securing the facilities against possible terrorist attacks. We maintain nuclear
decommissioning trust funds and external insurance coverage to minimize our
financial exposure to these risks; however, it is possible that damages could
exceed the amount of insurance coverage.

The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of noncompliance, the NRC has the authority to impose fines or shut
down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. In addition, although we have no reason
to anticipate a serious nuclear incident at Palo Verde, if an incident did
occur, it could materially and adversely affect our results of operations or
financial condition. A major incident at a nuclear facility anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of any
domestic nuclear unit.

The operation of Palo Verde requires licenses that need to be periodically
renewed and/or extended. We do not anticipate any problems renewing these
licenses. However, as a result of potential terrorist threats and increased
public scrutiny of utilities, the licensing process could result in increased
licensing or compliance costs that are difficult or impossible to predict.

THE USE OF DERIVATIVE CONTRACTS IN THE NORMAL COURSE OF OUR BUSINESS COULD
RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT OUR RESULTS OF OPERATIONS.

Our operations include managing market risks related to commodity prices,
changes in interest rates, and investments held by our pension plan and nuclear
decommissioning trust funds. We are exposed to the impact of market fluctuations
in the price and transportation costs of electricity, natural gas, coal, and
emissions allowances and credits. We have established procedures to manage risks
associated with these market fluctuations by utilizing various commodity
derivatives, including exchange-traded futures and options and over-the-counter
forwards, options, and swaps. As part of our overall risk management program, we
enter into derivative transactions to hedge purchases and sales of electricity,
fuels, and emissions allowances and credits. The changes in market value of such
contracts have a high correlation to price changes in the hedged commodity.

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

Changing interest rates will affect interest paid on variable-rate debt and
interest earned by our pension plan and nuclear decommissioning trust funds. Our
policy is to manage interest rates through the use of a combination of
fixed-rate and floating-rate debt. The pension plan and nuclear decommissioning
trust funds also have risks associated with changing market values of equity
investments. Most of the pension costs and all of the nuclear decommissioning
costs are recovered in regulated electricity prices.

                                       4
<PAGE>
THE UNCERTAIN OUTCOME REGARDING THE CREATION OF REGIONAL TRANSMISSION
ORGANIZATIONS, OR RTOS, MAY MATERIALLY IMPACT OUR OPERATIONS, CASH FLOWS OR
FINANCIAL POSITION.

In a December 1999 order, the FERC set minimum characteristics and functions
that must be met by utilities that participate in regional transmission
organizations. The characteristics for an acceptable RTO include independence
from market participants, operational control over a region large enough to
support efficient and nondiscriminatory markets, and exclusive authority to
maintain short-term reliability. On October 16, 2001, APS and other owners of
electric transmission lines in the Southwest filed with the FERC a request for a
declaratory order confirming that their proposal to form WestConnect RTO, LLC
would satisfy the FERC's requirements for the formation of an RTO. On October
10, 2002, the FERC issued an order finding that the WestConnect proposal, if
modified to address specified issues, could meet the FERC's RTO requirements and
provide the basic framework for a standard market design for the Southwest. As
of March 28, 2003, the FERC was considering various aspects of its order as a
result of requests for clarification filed by the WestConnect applicants.

WE ARE SUBJECT TO NUMEROUS ENVIRONMENTAL LAWS AND REGULATIONS WHICH MAY INCREASE
OUR COST OF OPERATIONS, IMPACT OUR BUSINESS PLANS, OR EXPOSE US TO ENVIRONMENTAL
LIABILITIES.

We are subject to numerous environmental regulations affecting many aspects of
our present and future operations, including air emissions, water quality,
wastewater discharges, solid waste, and hazardous waste. These laws and
regulations can result in increased capital, operating, and other costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require us to obtain and
comply with a wide variety of environmental licenses, permits, inspections and
other approvals. Both public officials and private individuals may seek to
enforce applicable environmental laws and regulations. We cannot predict the
outcome (financial or operational) of any related litigation that may arise.

In addition, we may be a responsible party for environmental clean up at sites
identified by a regulatory body. We cannot predict with certainty the amount and
timing of all future expenditures related to environmental matters because of
the difficulty of estimating clean-up costs. There is also uncertainty in
quantifying liabilities under environmental laws that impose joint and several
liability on all potentially responsible parties.

We cannot be sure that existing environmental regulations will not be revised or
that new regulations seeking to protect the environment will not be adopted or
become applicable to us. Revised or additional regulations that result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from APS' customers, could have a material
adverse effect on our results of operations.

THE MARKET PRICE OF OUR COMMON STOCK MAY BE VOLATILE.

The market price of our common stock could be subject to significant
fluctuations in response to factors such as the following, some of which are
beyond our control:

     *    variations in our quarterly operating results;

     *    operating results that vary from the expectations of management,
          securities analysts and investors;

     *    changes in expectations as to our future financial performance,
          including financial estimates by securities analysts and investors;

     *    developments generally affecting industries in which we operate,
          particularly the energy distribution and energy generation industries;

     *    announcements by us or our competitors of significant contracts,
          acquisitions, joint marketing relationships, joint ventures or capital
          commitments;

     *    announcements by third parties of significant claims or proceedings
          against us;

                                       5
<PAGE>
     *    favorable or adverse regulatory developments;

     *    our dividend policy;

     *    future sales of our equity or equity-linked securities; and

     *    general domestic and international economic conditions.

In addition, the stock market in general has experienced extreme volatility that
has often been unrelated to the operating performance of a particular company.
These broad market fluctuations may adversely affect the market price of our
common stock.

OUR STOCK PRICE COULD BE AFFECTED BECAUSE A SUBSTANTIAL NUMBER OF SHARES OF OUR
COMMON STOCK COULD BE AVAILABLE FOR SALE IN THE FUTURE.

Sales in the public market of a substantial number of shares of common stock
could depress the market price of the common stock and could impair our ability
to raise capital through the sale of additional equity securities. Because of
the number of shares of our common stock that we are authorized to issue under
our articles of incorporation, a substantial number of shares of our common
stock could be available for future sale.

OUR CASH FLOW AND ABILITY TO PAY DIVIDENDS LARGELY DEPENDS ON THE PERFORMANCE OF
OUR SUBSIDIARIES.

We conduct our operations primarily through subsidiaries. Substantially all of
our consolidated assets are held by such subsidiaries. Accordingly, our cash
flow and our ability to pay dividends on our capital stock are largely dependent
upon the earnings of these subsidiaries and the distribution or other payment of
such earnings to us in the form of dividends, loans or advances or repayment of
loans and advances from us. The subsidiaries are separate and distinct legal
entities and have no obligation to pay dividends or to make any funds available
for such payment.

The debt agreements of some of our subsidiaries may restrict their ability to
pay dividends, make distributions or otherwise transfer funds to us. Section
39(III) of APS' mortgage requires APS to meet a financial covenant before paying
common stock dividends. Under this covenant, APS may pay dividends on its common
stock if there is a sufficient amount "available" from retained earnings and the
excess of cumulative book depreciation (since the mortgage's inception) over
mortgage depreciation, which is the cumulative amount of additional property
pledged each year to address collateral depreciation. As of December 31, 2002,
the amount "available" under the mortgage would have allowed APS to pay
approximately $3 billion of dividends compared to APS' current annual common
stock dividends of $170 million. As part of the ACC's approval of a $500 million
financing arrangement between APS and Pinnacle West Energy, the ACC required APS
to maintain a common equity ratio of at least forty percent and prohibited APS
from paying common stock dividends if such payment would reduce its common
equity below that threshold.

WE HAVE AND MAY ENTER INTO CREDIT AND OTHER AGREEMENTS FROM TIME TO TIME THAT
RESTRICT OUR ABILITY TO PAY DIVIDENDS.

Payment of dividends on the common stock may be restricted by loan agreements,
indentures and other transactions entered into by us from time to time.

                                       6


</TEXT>
</DOCUMENT>
</SUBMISSION>
