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<TYPE>10-Q
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<CONFORMED-NAME>PINNACLE WEST CAPITAL CORP
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<STREET1>400 E VAN BUREN ST PO BOX 52132
<STREET2>P O BOX 52132
<CITY>PHOENIX
<STATE>AZ
<ZIP>85072-2132
<PHONE>6022501000
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<STATE>AZ
<ZIP>85072-2132
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<TYPE>10-Q
<SEQUENCE>1
<FILENAME>e-8506.txt
<DESCRIPTION>QUARTERLY REPORT FOR THE QTR ENDED 03/31/2002
<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, 2002

                                       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 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 10, 2002: 84,806,733
<PAGE>
                                    GLOSSARY

ACC - Arizona Corporation Commission

ACC Staff - Staff of the Arizona Corporation Commission

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

APSES - 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

EITF - 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

Four Corners - Four Corners Power Plant

GAAP - Generally accepted accounting principles in the United States

GCVTC - Grand Canyon Visibility Transport Commission

ISO - California Independent System Operator

MW - megawatt, one million watts

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

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

Palo Verde - Palo Verde Nuclear Generating Station

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

PX - California Power Exchange

Rules - ACC retail electric competition rules

SFAS - Statement of Financial Accounting Standards

SNWA - Southern Nevada Water Authority

SPE - special purpose entity

SunCor - SunCor Development Company, a subsidiary of the Company

T&D - transmission and distribution

2001 10-K - Pinnacle West Capital Corporation Annual Report on Form 10-K for the
fiscal year ended December 31, 2001
<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,
                                                              ----------------------------
                                                                  2002           2001
                                                                ---------      ---------
<S>                                                             <C>            <C>
Operating Revenues
   Electric                                                     $ 579,772      $ 906,494
   Real estate                                                     41,185         32,335
                                                                ---------      ---------
     Total                                                        620,957        938,829
                                                                ---------      ---------

Operating Expenses
   Purchased power and fuel                                       221,036        516,424
   Operations and maintenance                                     117,430        125,250
   Real estate operations                                          37,358         31,008
   Depreciation and amortization                                   99,913        104,781
   Taxes other than income taxes                                   26,758         25,303
                                                                ---------      ---------
     Total                                                        502,495        802,766
                                                                ---------      ---------
Operating Income                                                  118,462        136,063
                                                                ---------      ---------
Other Income (Expense)                                              1,088           (738)
                                                                ---------      ---------

Interest Expense
   Interest charges                                                44,688         42,749
   Capitalized interest                                           (14,123)       (10,427)
                                                                ---------      ---------
     Total                                                         30,565         32,322
                                                                ---------      ---------
Income Before Income Taxes                                         88,985        103,003
Income Taxes                                                       35,228         40,798
                                                                ---------      ---------
Income Before Accounting Change                                    53,757         62,205
Cumulative Effect of a Change in Accounting for Derivatives
 - Net of Income Tax Benefit of $1,793                                 --         (2,755)
                                                                ---------      ---------
Net Income                                                      $  53,757      $  59,450
                                                                =========      =========

Weighted-Average Common Shares Outstanding - Basic                 84,735         84,727

Weighted-Average Common Shares Outstanding  - Diluted              84,884         84,966

Earnings Per Weighted-Average Common Share Outstanding
    Income Before Accounting Change - Basic                     $    0.63      $    0.73
    Net Income - Basic                                               0.63           0.70
    Income Before Accounting Change - Diluted                        0.63           0.73
    Net Income - Diluted                                             0.63           0.70

Dividends Declared Per Share                                    $    0.40      $   0.375
</TABLE>

See Notes to Condensed Consolidated Financial Statements.

                                       -2-
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                   CONDENSED CONSOLIDATED STATEMENTS OF INCOME
                                   (unaudited)
                    (in thousands, except per share amounts)

<TABLE>
<CAPTION>
                                                             Twelve Months Ended March 31,
                                                             -----------------------------
                                                                 2002             2001
                                                              -----------      -----------
<S>                                                           <C>              <C>
Operating Revenues
   Electric                                                   $ 4,055,743      $ 3,992,076
   Real estate                                                    177,758          148,811
                                                              -----------      -----------
     Total                                                      4,233,501        4,140,887
                                                              -----------      -----------

Operating Expenses
   Purchased power and fuel                                     2,368,830        2,323,784
   Operations and maintenance                                     522,275          465,006
   Real estate operations                                         159,812          132,610
   Depreciation and amortization                                  423,035          433,553
   Taxes other than income taxes                                  102,523           99,691
                                                              -----------      -----------
     Total                                                      3,576,475        3,454,644
                                                              -----------      -----------
Operating Income                                                  657,026          686,243
                                                              -----------      -----------
Other Income (Expense)                                             (3,939)         (36,635)
                                                              -----------      -----------

Interest Expense
   Interest charges                                               177,761          169,697
   Capitalized interest                                           (51,558)         (28,216)
                                                              -----------      -----------
     Total                                                        126,203          141,481
                                                              -----------      -----------
Income Before Income Taxes                                        526,884          508,127
Income Taxes                                                      207,965          197,660
                                                              -----------      -----------
Income Before Accounting Change                                   318,919          310,467
Cumulative Effect of Change in Accounting for Derivatives
 - Net of Income Tax Benefits of $8,099 and $1,793                (12,446)          (2,755)
                                                              -----------      -----------
Net Income                                                    $   306,473      $   307,712
                                                              ===========      ===========

Weighted-Average Common Shares Outstanding - Basic                 84,719           84,732

Weighted-Average Common Shares Outstanding  - Diluted              84,910           84,974

Earnings Per Weighted-Average Common Share Outstanding
    Income Before Accounting Change - Basic                   $      3.76      $      3.66
    Net Income - Basic                                               3.62             3.63
    Income Before Accounting Change - Diluted                        3.76             3.65
    Net Income - Diluted                                             3.61             3.62

Dividends Declared Per Share                                  $      1.55      $      1.45
</TABLE>

See Notes to Condensed Consolidated Financial Statements.

                                       -3-
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                      CONDENSED CONSOLIDATED BALANCE SHEETS
                             (dollars in thousands)

                                     ASSETS

<TABLE>
<CAPTION>
                                                             March 31,    December 31,
                                                               2002           2001
                                                            ----------     ----------
                                                            (unaudited)
<S>                                                         <C>            <C>
Current Assets
   Cash and cash equivalents                                $   20,443     $   28,619
   Trust fund for bond redemption                              121,668             --
   Customer and other receivables--net                         313,426        367,241
   Accrued utility revenues                                     63,708         76,131
   Materials and supplies (at average cost)                     79,428         81,215
   Fossil fuel (at average cost)                                28,334         27,023
   Assets from risk management and trading activities           58,520         66,973
   Other current assets                                         83,140         80,203
                                                            ----------     ----------
      Total current assets                                     768,667        727,405
                                                            ----------     ----------

Investments and Other Assets
   Real estate investments--net                                427,465        418,673
   Assets from risk management and trading activities -
     long-term                                                 226,482        200,351
   Other assets                                                302,946        320,004
                                                            ----------     ----------
      Total investments and other assets                       956,893        939,028
                                                            ----------     ----------

Property, Plant and Equipment
   Plant in service and held for future use                  8,101,610      8,030,134
   Less accumulated depreciation and amortization            3,340,326      3,290,097
                                                            ----------     ----------
      Total                                                  4,761,284      4,740,037
   Construction work in progress                             1,147,903      1,032,234
   Intangible assets, net of accumulated amortization           87,201         86,782
   Nuclear fuel, net of accumulated amortization                58,689         49,282
                                                            ----------     ----------
      Net property, plant and equipment                      6,055,077      5,908,335
                                                            ----------     ----------

Deferred Debits
   Regulatory assets                                           316,800        342,383
   Other deferred debits                                        71,007         64,597
                                                            ----------     ----------
      Total deferred debits                                    387,807        406,980
                                                            ----------     ----------

Total Assets                                                $8,168,444     $7,981,748
                                                            ==========     ==========
</TABLE>

See Notes to Condensed Consolidated Financial Statements.

                                       -4-
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                      CONDENSED CONSOLIDATED BALANCE SHEETS

                             LIABILITIES AND EQUITY
                             (dollars in thousands)

<TABLE>
<CAPTION>
                                                                  March 31,      December 31,
                                                                    2002             2001
                                                                 -----------      -----------
                                                                 (unaudited)
<S>                                                              <C>              <C>
Current Liabilities
   Accounts payable                                              $   151,583      $   269,124
   Accrued taxes                                                     138,464           96,729
   Accrued interest                                                   42,358           48,806
   Short-term borrowings                                             152,300          405,762
   Current maturities of long-term debt                                6,885          126,140
   Customer deposits                                                  32,014           30,232
   Deferred income taxes                                               3,244            3,244
   Liabilities from risk management and trading activities            25,556           35,994
   Other current liabilities                                          97,988           74,898
                                                                 -----------      -----------
      Total current liabilities                                      650,392        1,090,929
                                                                 -----------      -----------

Long-Term Debt Less Current Maturities                             3,264,626        2,673,078
                                                                 -----------      -----------

Deferred Credits and Other
   Liabilities from risk management and trading activities -
     long-term                                                       184,055          207,576
   Deferred income taxes                                           1,072,670        1,064,993
   Unamortized gain - sale of utility plant                           62,916           64,060
   Other                                                             384,361          381,789
                                                                 -----------      -----------
      Total deferred credits and other                             1,704,002        1,718,418
                                                                 -----------      -----------

Commitments and contingencies (Note 12)

Common Stock Equity
   Common stock, no par value                                      1,533,454        1,531,038
   Retained earnings                                               1,052,719        1,032,850
   Accumulated other comprehensive loss                              (36,749)         (64,565)
                                                                 -----------      -----------
      Total common stock equity                                    2,549,424        2,499,323
                                                                 -----------      -----------

Total Liabilities and Equity                                     $ 8,168,444      $ 7,981,748
                                                                 ===========      ===========
</TABLE>

See Notes to Condensed Consolidated Financial Statements.

                                       -5-
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
                 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (unaudited)
                             (dollars in thousands)

                                                    Three Months Ended March 31,
                                                    ----------------------------
                                                       2002             2001
                                                     ---------        ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income before accounting change                      $  53,757        $  62,205
   Items not requiring cash
      Depreciation and amortization                     99,913          104,781
      Nuclear fuel amortization                          7,484            7,581
      Deferred income taxes--net                       (10,434)          (6,250)
      Mark-to-market gains--trading                     (2,724)         (52,425)
      Mark-to-market gains--system                        (366)          (1,629)
   Changes in current assets and liabilities
      Customer and other receivables--net               53,815           69,118
      Accrued utility revenues                          12,423           12,966
      Materials, supplies and fossil fuel                  476           (4,128)
      Other current assets                              (2,937)          20,790
      Accounts payable                                (117,731)         (50,899)
      Accrued taxes                                     41,735           56,567
      Accrued interest                                  (6,448)         (28,933)
      Other current liabilities                         24,872           37,795
   Increase in real estate investments                  (8,340)         (19,789)
   Increase in regulatory assets                        (2,096)          (2,856)
   Other--net                                           (7,314)         (15,685)
                                                     ---------        ---------
Net Cash Flow Provided By Operating Activities         136,085          189,209
                                                     ---------        ---------

CASH FLOWS FROM INVESTING ACTIVITIES
   Trust fund for bond redemption                     (121,668)        (117,510)
   Capital expenditures                               (219,923)        (189,924)
   Capitalized interest                                (14,123)         (10,427)
   Other--net                                           26,706          (14,747)
                                                     ---------        ---------
Net Cash Flow Used For Investing Activities           (329,008)        (332,608)
                                                     ---------        ---------

CASH FLOWS FROM FINANCING ACTIVITIES
   Issuance of long-term debt                          603,430          387,000
   Short-term borrowings--net                         (253,462)          95,850
   Dividends paid on common stock                      (33,888)         (31,785)
   Repayment of long-term debt                        (133,749)        (184,206)
   Other--net                                            2,416           (1,940)
                                                     ---------        ---------
Net Cash Flow Provided By Financing Activities         184,747          264,919
                                                     ---------        ---------
Net Cash Flow                                           (8,176)         121,520
Cash and Cash Equivalents at Beginning of Period        28,619           10,363
                                                     ---------        ---------
Cash and Cash Equivalents at End of Period           $  20,443        $ 131,883
                                                     =========        =========

Supplemental Disclosure of Cash Flow Information:
   Cash paid during the period for:
      Interest, net of amounts capitalized           $  35,212        $  57,839
      Income taxes                                   $  30,557        $  16,077

See Notes to Condensed Consolidated Financial Statements.

                                       -6-
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION
              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.   The condensed consolidated financial statements include the accounts of the
Company and its subsidiaries: APS, Pinnacle West Energy, APSES, SunCor, and El
Dorado. All significant intercompany accounts and transactions have been
eliminated. We have reclassified certain prior-year amounts to conform to the
current-year presentation.

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 (see Note 10). 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 2001 10-K.

3.   Weather conditions and trading and wholesale marketing activities can have
significant impacts on our results for interim periods. Results for interim
periods do not necessarily represent results to be expected for the year.

4.   On February 8, 2002, Pinnacle West issued $215 million of 4.5% Notes due
2004. On March 1, 2002, APS issued $375 million of 6.5% Notes due 2012. As of
March 31, 2002, APS deposited $122 million, plus interest, with the trustee
under its Mortgage for the redemption in April 2002 of its First Mortgage Bonds,
8.75% Series due 2024. The above items represent the primary changes in
capitalization for the three months ended March 31, 2002.

5.   Regulatory Matters

ELECTRIC INDUSTRY RESTRUCTURING

STATE

     OVERVIEW. On September 21, 1999, the ACC approved Rules that provide a
framework for the introduction of retail electric competition in Arizona. On
September 23, 1999, the ACC approved a comprehensive settlement agreement among
APS and various parties related to the implementation of retail electric
competition in Arizona. Under the Rules, as modified by the 1999 Settlement
Agreement, APS is required to transfer all of its competitive electric assets
and services either to an unaffiliated party or to a separate corporate
affiliate no later than December 31, 2002. Consistent with that requirement, APS
has been addressing the legal and regulatory requirements necessary to complete
the transfer of its generation assets to Pinnacle West Energy on or before that
date.

     In February 2002, the ACC opened a "generic" docket to "determine if
changed circumstances require the [ACC] to take another look at electric
restructuring in Arizona." The ACC Staff filed a report with the ACC in this
docket stating, among other things, that transfers of generation assets required
by the Rules would be "unwise" at the present time and that such transfers

                                      -7-
<PAGE>
should be stayed pending the completion of the generic docket. On June 17, 2002,
ACC hearings are scheduled to begin on various issues, including APS' planned
divestiture of generation assets to Pinnacle West Energy. These regulatory
developments have raised uncertainty about the status and pace of retail
electric competition in Arizona, including APS' transfer of generation assets to
Pinnacle West Energy.

     These matters are discussed in more detail below.

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

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

     *    Unbundled rates being charged by 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.

     *    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.

     *    APS will be permitted to defer for later recovery prudent and
          reasonable costs of complying with the ACC electric competition rules,
          system benefits costs in excess of the levels included in then-current
          (1999) rates, and costs associated with the "provider of last resort"
          and standard-offer obligations for service after July 1, 2004. These
          costs are to be recovered through an adjustment clause or clauses
          commencing on July 1, 2004.

     *    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 electric competition rules

                                      -8-
<PAGE>
          (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.

     *    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. APS will not be
          allowed to recover $183 million net present value of the above
          amounts. The 1999 Settlement Agreement provides that APS will have the
          opportunity to recover $350 million net present value through a
          competitive transition charge that will remain in effect through
          December 31, 2004, at which time it will terminate. The costs subject
          to recovery under the adjustment clause described above will be
          decreased or increased by any over/under-recovery due to sales volume
          variances.

     *    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 transfer no later than December 31, 2002.
          Consistent with that requirement, APS has been addressing the legal
          and regulatory requirements necessary to complete the transfer of its
          generation assets to Pinnacle West Energy on or before that date.
          However, as noted above and discussed in greater detail below, the
          ACC's recent establishment of a "generic" docket to consider electric
          industry restructuring in Arizona could affect APS' ability to
          transfer assets to Pinnacle West Energy. APS will be allowed to defer
          and later collect, beginning July 1, 2004, sixty-seven percent of its
          costs to accomplish the required transfer of generation assets to an
          affiliate.

     RETAIL ELECTRIC COMPETITION RULES. The Rules approved by the ACC include
the following major provisions:

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

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

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

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

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

                                      -9-
<PAGE>
     *    Absent an ACC waiver, prior to January 1, 2001, each affected utility
          (except certain electric cooperatives) must transfer all competitive
          electric assets and services either to an unaffiliated party or to a
          separate corporate affiliate. Under the 1999 Settlement Agreement, APS
          received a waiver to allow transfer of its competitive electric assets
          and services to affiliates no later than December 31, 2002.

     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.

     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 APSES, 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. 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
telecommunications case has been appealed to the Arizona Supreme Court, where a
decision is pending.

     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 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, or material changes in
APS' cost of service for ACC-regulated services resulting from federal, tribal,
state or local laws; regulatory requirements; judicial decisions, actions or
orders. Energy prices in the western wholesale market vary and, during the
course of the last two years, have been volatile. At various times, prices in
the spot wholesale market have significantly exceeded the amount included in
APS' current retail rates. In the event of shortfalls due to unforeseen
increases in load demand or generation 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.

     PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. Commencing on the
transfer of the fossil-fueled generating assets and the receipt of certain
regulatory approvals, Pinnacle West Energy expects to sell its power at

                                      -10-
<PAGE>
wholesale to Pinnacle West's marketing and trading division, which, in turn, is
expected to sell power to APS and to non-affiliated power purchasers. In a
filing with the ACC on October 18, 2001, APS requested the ACC to:

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

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

APS requested these ACC actions to ensure ongoing reliable service to APS
standard-offer, full-service customers in a volatile generation market and to
recognize Pinnacle West Energy's significant investment to serve APS load.

     GENERIC DOCKET. In February 2002, the ACC opened a "generic" docket to
"determine if changed circumstances require the [ACC] to take another look at
electric restructuring in Arizona." Also, in February 2002, the ACC docket
relating to APS' October 2001 filing was consolidated with several other pending
ACC dockets, including the generic docket. On April 19, 2002, APS filed a motion
in the consolidated docket addressing the following issues, among others:

     *    APS confirmed its position that whether or not the ACC approved the
          matters requested in its October 2001 filing, APS would proceed with
          the divestiture of its generation assets by the end of 2002.

     *    APS also advised the ACC that whether or not the ACC approved the
          matters requested in its October 2001 filing, APS would implement a
          competitive bidding process later in 2002 to the extent legally
          required.

     *    APS noted that Pinnacle West Energy, the affiliate to which APS
          intends to transfer the generation assets, had committed to a $1
          billion investment in generating capacity to meet APS customer needs
          in reliance on the 1999 Settlement Agreement and in accordance with an
          ACC Rule that prohibited APS' ownership of new generation assets. APS
          further noted that it had taken numerous actions in reliance on the
          1999 Settlement Agreement and the ACC retail electric competition
          rules, including writing off $234 million of prudently incurred costs,
          reducing retail rates by approximately $120 million in a still-ongoing
          series of rate reductions, and incurring tens of millions of dollars
          in expenses related to the expected generation asset transfer. APS
          stated that if the ACC elects to reverse course on retail electric
          competition or attempts to stay the transfer of APS' generation
          assets, the ACC would be legally required to address just compensation
          to APS and Pinnacle West Energy, which would include, at a minimum:

          *    recognizing the transfer to APS of all assets that Pinnacle West
               Energy constructed to meet APS' load-serving requirements, and

                                      -11-
<PAGE>
               subsequently including such units in APS' rate base in accordance
               with traditional rate-of-return regulation;

          *    reversing APS' $234 million write-off and providing for the
               recovery of such amounts in future rates; and

          *    providing for the recovery of all costs incurred as a result of
               the transition to competition, including 100 percent of the costs
               incurred in preparation for divestiture (and not just the
               two-thirds of costs permitted under the 1999 Settlement
               Agreement).

     *    APS recommended that the ACC confirm whether or not Arizona would
          proceed with the transition to a competitive electric market, and
          proposed a procedural plan in response to issues identified by the ACC
          Staff in a previous report.

     On April 26, 2002, the ACC issued a procedural order in which the ACC
stayed the previously-scheduled April 29, 2002 hearing on the matters raised in
APS' October 2001 ACC filing (see "Proposed Rule Variance and Purchase Power
Agreement" above). On May 2, 2002, the ACC issued a procedural order stating
that hearings will begin on June 17, 2002 on various issues ("Track A Issues"),
including APS' planned divestiture of generation assets to Pinnacle West Energy
and associated market and affiliate issues. The procedural order stated that the
schedule is designed to have a recommended order issued by the administrative
law judge by approximately July 22, 2002, with comments on the recommended order
due from affected parties on July 31, 2002. Under this schedule, August 1, 2002
is the earliest date the ACC could consider a decision on the Track A Issues.

     The procedural order also stated that consideration of the competitive
bidding process (the "Track B Issues") required by the Rules would proceed
concurrently with the Track A Issues. The objectives and process of the Track B
Issues will be determined in one or more meetings of affected parties beginning
the week of May 20, 2002, with a "target completion date" of October 21, 2002.

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

FEDERAL

     In June 2001, the FERC adopted a price mitigation plan that constrains the
price of electricity in the wholesale spot electricity market in the western
United States. The plan remains in effect until September 30, 2002. We cannot
accurately predict the overall financial impact of the plan on the various
aspects of our business, including our wholesale and purchased power activities.

                                      -12-
<PAGE>
GENERAL

     We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete in the new
regulatory environment.

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 $200 million and the balance by
an industry-wide retrospective assessment program. If losses at any nuclear
power plant covered by the programs exceed the accumulated funds, 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 upon 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
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 two principal business segments (determined by products, services
and regulatory environment) which consist of regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
includes activities related to electricity transmission and distribution, as
well as electricity generation. Our marketing and trading business segment
includes activities related to wholesale marketing and trading and APSES'
competitive energy services. The other amounts include activities relating to
SunCor and El Dorado. Financial data for the business segments is provided as
follows (dollars in millions):

                                      -13-
<PAGE>
                                  Three Months Ended    Twelve Months Ended
                                  ------------------    -------------------
                                       March 31,             March 31,
                                    2002      2001        2002      2001
                                   -------   -------     -------   -------
     Operating Revenues:
          Retail                   $   380   $   413     $ 2,531   $ 2,572
          Marketing and trading        200       494       1,525     1,420
          Other                         41        32         178       149
                                   -------   -------     -------   -------
              Total                $   621   $   939     $ 4,234   $ 4,141
                                   =======   =======     =======   =======

     Income Before
     Accounting Change:
          Retail                   $    31   $     3     $   179   $   199
          Marketing and trading         21        58         134       122
          Other                          2         1           5       (10)
                                   -------   -------     -------   -------
              Total                $    54   $    62     $   318   $   311
                                   =======   =======     =======   =======

                                    As of March 31,      As of December 31,
                                         2002                  2001
                                        ------                ------
     Assets:
       Retail                           $7,261                $7,077
       Marketing and trading               411                   417
       Other                               496                   488
                                        ------                ------
          Total                         $8,168                $7,982
                                        ======                ======

8.   Accounting Matters

     On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." We have no goodwill recorded and have separately disclosed
other intangible assets in our consolidated balance sheets. This new standard
has no material impact on our financial statements, and the required disclosures
are provided in Note 13.

     On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the accounting and reporting provisions for the disposal of
a segment of a business. This standard did not impact our financial statements
at adoption.

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

                                      -14-
<PAGE>
     In 2001, the American Institute of Certified Public Accountants issued an
exposure draft of a proposed Statement of Position, "Accounting for Certain
Costs Related to Property, Plant, and Equipment." This proposed Statement of
Position would create a project timeline framework for capitalizing costs
related to property, plant and equipment construction, which 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. The American Institute of
Certified Public Accountants plans to issue the final Statement of Position in
the fourth quarter of 2002.

9.   Off-Balance Sheet Financing

     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. In February 2002, the
FASB discussed issues related to SPEs. It is expected that the FASB will issue
additional guidance on accounting for SPEs later this year. As a result of
future FASB actions, we may be required to consolidate the Palo Verde SPEs in
our financial statements. If consolidation is required, the assets and
liabilities of the SPEs that relate to the sale-leaseback transactions would be
reflected on our consolidated balance sheets. The SPE debt that is not reflected
on our consolidated balance sheets is approximately $300 million at March 31,
2002. Rating agencies have already considered this debt when evaluating our
credit ratings. This is the Company's only significant off-balance sheet
financing activity.

10.  Derivative Instruments

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

     Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133 requires that
entities recognize all derivatives as either assets or liabilities on the
balance sheets and measure those instruments at fair value. Changes in the fair
value of derivative financial instruments are either recognized periodically in
income or shareholders' equity (as a component of other comprehensive income),
depending on whether or not the derivative meets specific hedge accounting
criteria. We use cash flow hedges to limit our exposure to cash flow variability
on forecasted transactions. Hedge effectiveness is related to the degree to
which the derivative contract and the hedged item are correlated. It is measured
based on the relative changes in fair value between the derivative contract and
the hedged item over time. We exclude the time value of certain options from our
assessment of hedge effectiveness. Any change in the fair value resulting from
ineffectiveness is recognized immediately in net income.

                                      -15-
<PAGE>
     On January 1, 2001, we recorded a $3 million after-tax loss in net income
and a $64 million after-tax gain in equity (as a component of other
comprehensive income), both as a cumulative effect of a change in accounting
principle. The gain resulted from unrealized gains on cash flow hedges.

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

     In December 2001, the FASB issued revised guidance on the accounting for
electricity contracts with option characteristics and the accounting for
contracts that combine a forward contract and a purchased option contract. The
effective date for the revised guidance is April 1, 2002. We are currently
evaluating the new guidance to determine what impact, if any, it will have on
our financial statements.

     The change in derivative fair value included in the consolidated statements
of income for the three and twelve months ended March 31, 2002 and 2001 are
comprised of the following (dollars in thousands):

                                    Three Months Ended     Twelve Months Ended
                                        March 31,                March 31,
                                   --------------------    --------------------
                                     2002        2001        2002        2001
                                   --------    --------    --------    --------
Losses on the ineffective
  portion of derivatives
  qualifying for hedge
  accounting                       $ (2,548)   $ (4,764)   $ (6,155)   $ (4,764)

Losses from the
  discontinuance of cash
  flow hedges for
  forecasted transactions
  that will not occur                  (899)         --     (10,425)         --

Prior period mark-to-
  market losses realized
  upon delivery of
  commodities                         3,813       6,393      23,368       6,393
                                   --------    --------    --------    --------
Total pretax gain                  $    366    $  1,629    $  6,788    $  1,629
                                   ========    ========    ========    ========

     As of March 31, 2002,  the maximum length of time over which we are hedging
our exposure to the variability in future cash flows for forecasted transactions
is  thirty-three  months.  During the twelve  months  ending March 31, 2003,  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.

                                      -16-
<PAGE>
     The following table summarizes our assets and liabilities from risk
management and trading activities related to trading and system (retail and
traditional wholesale activities) as of March 31, 2002 (dollars in thousands):

                 Current                   Current        Other       Net Asset/
                 Assets    Investments   Liabilities   Liabilities   (Liability)
                ---------  -----------   -----------   -----------   -----------
Mark-to-
  market:
    Trading     $  44,858   $ 165,479     $ (11,610)    $ (57,968)    $ 140,759
    System         13,662         247       (13,946)      (60,694)      (60,731)

Cost-emission
    allowances
    and other          --      60,756            --       (65,393)       (4,637)
                ---------   ---------     ---------     ---------     ---------
Total           $  58,520   $ 226,482     $ (25,556)    $(184,055)    $  75,391
                =========   =========     =========     =========     =========

11.  Comprehensive Income

     Components of comprehensive income for the three and twelve months ended
March 31, 2002 and 2001, are as follows (dollars in thousands):

<TABLE>
<CAPTION>
                                             Three Months Ended       Twelve Months Ended
                                                  March 31,                March 31,
                                            ---------------------    ----------------------
                                              2002        2001         2002         2001
                                            ---------   ---------    ---------    ---------
<S>                                         <C>         <C>          <C>          <C>
Net income                                  $  53,757   $  59,450    $ 306,473    $ 307,712
                                            ---------   ---------    ---------    ---------
Other comprehensive income (losses):
  Minimum pension liability, net of tax            --          --         (966)          --
  Cumulative effect of change in
     accounting for derivatives, net
     of tax                                        --      64,700        7,777       64,700
  Unrealized gains (losses) on
     derivative instruments, net of
     tax                                       26,826     (10,453)     (47,161)     (10,453)

  Reclassification of net realized
     (gains) losses to income, net of
     tax                                          990     (16,822)     (33,824)     (16,822)
                                            ---------   ---------    ---------    ---------

Total other comprehensive income (losses)      27,816      37,425      (74,174)      37,425
                                            ---------   ---------    ---------    ---------

Comprehensive income                        $  81,573   $  96,875    $ 232,299    $ 345,137
                                            =========   =========    =========    =========
</TABLE>

                                      -17-
<PAGE>
12.  Commitments and Contingencies

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

     On March 19, 2002, the State of California filed a complaint with the FERC
alleging that wholesale sellers of power and energy, including Pinnacle West,
failed to properly file rate information at the FERC in connection with sales to
California from 2000 to the present. STATE OF CALIFORNIA V. BRITISH COLUMBIA
POWER EXCHANGE ET. AL., Docket No. EL02-71-000. The complaint requests the FERC
to require the wholesale sellers to refund any rates that are "found to exceed
just and reasonable levels." The complaint indicates that Pinnacle West sold
approximately $106 million of power to the California Department of Water
Resources from January 17, 2001 to October 31, 2001 and does not allege any
amount above "just and reasonable levels." We believe that the claims as they
relate to Pinnacle West are without merit. 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 Trading and Marketing, LLP (and other
Duke entities), filed cross-claims against various other participants in the
California 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.

     By letter dated March 7, 2001, Citizens, which owns a utility in Arizona,
advised APS that it believes APS has overcharged Citizens by over $50 million
under a power service agreement. APS believes that 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 that,
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 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.

13.  Intangible Assets

     On January 1, 2002, we adopted SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses financial accounting and reporting for
acquired goodwill and other intangible assets and supersedes APB Opinion No. 17,
"Intangible Assets." The Company's gross intangible assets (which are primarily
software) were $179 million at March 31, 2002 and $175 million at December 31,
2001. The related accumulated amortization was $92 million at March 31, 2002 and
$88 million at December 31, 2001. Amortization expense for the three-month
period ended March 31 was $4 million in 2002 compared with $5 million in 2001.
Amortization expense for the twelve-month period ended March 31 was $21 million
in 2002 and $20 million in 2001. Estimated amortization expense on existing

                                      -18-
<PAGE>
intangible assets over the next five years is $17 million in 2002, $16 million
in 2003, $15 million in 2004, $13 million in 2005 and $11 million in 2006.

14.  Earnings Per Share

     The following table presents earnings per weighted average common share
outstanding (EPS):

                                     Three Months Ended     Twelve Months Ended
                                          March 31,              March 31,
                                     ------------------     -------------------
                                      2002        2001       2002         2001
                                     ------      ------     ------       ------
Basic EPS:
  Income before accounting change    $ 0.63      $ 0.73     $ 3.76       $ 3.66
  Cumulative effect of change in
    accounting                           --       (0.03)     (0.14)       (0.03)
                                     ------      ------     ------       ------
Earnings per share - basic           $ 0.63      $ 0.70     $ 3.62       $ 3.63
                                     ======      ======     ======       ======

Diluted EPS:
  Income before accounting change    $ 0.63      $ 0.73     $ 3.76       $ 3.65
  Cumulative effect of change in
    accounting                           --       (0.03)     (0.15)       (0.03)
                                     ------      ------     ------       ------
Earnings per share - diluted         $ 0.63      $ 0.70     $ 3.61       $ 3.62
                                     ======      ======     ======       ======

The following table reconciles average common shares outstanding - basic to
average common shares outstanding - diluted that are used in the EPS calculation
to the consolidated income statement (in thousands):

                                      Three Months Ended     Twelve Months Ended
                                           March 31,              March 31,
                                      ------------------     -------------------
                                       2002        2001       2002         2001
                                      ------      ------     ------       ------
Average common shares outstanding -
  basic                               84,735      84,727     84,719       84,732
Diluted stock options                    149         239        191          242
                                      ------      ------     ------       ------
Average common shares outstanding -
  diluted                             84,884      84,966     84,910       84,974
                                      ======      ======     ======       ======

                                      -19-
<PAGE>
                        PINNACLE WEST CAPITAL CORPORATION

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

Introduction

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

     *    the changes in our earnings for the three and twelve months ended
          March 31, 2002 and 2001;

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

     *    our capital needs, liquidity and capital resources;

     *    our business outlook; and

     *    our management of market risks.

     We suggest this section be read along with the 2001 10-K. Throughout this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, 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 periods ended March 31, 2002 and March
31, 2001 are available on the Company's website (www.pinnaclewest.com) and in
the Company's Current Report on Form 8-K dated March 31, 2002.

OVERVIEW OF OUR BUSINESS

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

     Our other major subsidiaries are:

     *    Pinnacle West Energy, through which we conduct our unregulated
          electricity generation operations;

     *    APSES, which provides commodity energy and energy-related products to
          key customers in competitive markets in the western United States;

                                      -20-
<PAGE>
     *    SunCor, a developer of residential, commercial, and industrial real
          estate projects in Arizona, New Mexico, and Utah; and

     *    El Dorado, an investment firm.

     Pinnacle West's marketing and trading division sells in the wholesale
market APS and Pinnacle West Energy generation production output that is not
needed for APS' native load, which includes loads for retail customers and
traditional cost-of-service wholesale customers. Subject to specified risk
parameters established by our Board of Directors, the marketing and trading
division also engages in activities to hedge purchases and sales of electricity,
fuels, and emissions allowances and credits and to profit from market price
movements. We explain in detail below the historical and prospective
contribution of marketing and trading activities to our financial results.

     APS is required to transfer its competitive electric assets and services to
one or more corporate affiliates no later than December 31, 2002. Consistent
with that requirement, APS has been addressing the legal and regulatory
requirements necessary to complete the transfer of its generation assets to
Pinnacle West Energy before that date. As we discuss in greater detail in Note
5, recent Arizona regulatory developments have raised uncertainty about the
status and pace of retail electric competition in Arizona, including APS'
transfer of generation assets to Pinnacle West Energy.

EARNINGS CONTRIBUTIONS BY SUBSIDIARY

     The following table summarizes net income for the three and twelve months
ended March 31, 2002 and the comparable prior-year periods for Pinnacle West and
each of its subsidiaries (dollars in millions):

                                     Three Months              Twelve Months
                                         Ended                    Ended
                                       March 31,                 March 31,
                                  -------------------      --------------------
                                   2002        2001         2002         2001
                                  -------     -------      -------      -------
Arizona Public Service (APS)      $    32     $    65      $   248      $   338
Pinnacle West Energy                    1          --           19           (2)
APS Energy Services (APSES)             2          (8)          --          (20)
SunCor                                  2          --            5            7
El Dorado                              --           1           --          (17)
Parent Company (a)                     17           4           46            5
                                  -------     -------      -------      -------
Income before accounting
  change                               54          62          318          311
Cumulative effect of change
  in accounting - net of
  income taxes                         --          (3)         (12)          (3)
                                  -------     -------      -------      -------
Net income                        $    54     $    59      $   306      $   308
                                  =======     =======      =======      =======

----------
(a)  These amounts primarily include marketing and trading activities. APS also
     includes some marketing and trading activities in 2001.

                                      -21-
<PAGE>
BUSINESS SEGMENTS

     We have two principal business segments determined by products, services
and regulatory environment, which consist of our regulated retail electricity
business and related activities (retail business segment) and competitive
business activities (marketing and trading segment). Our retail business segment
includes activities related to electricity transmission and distribution, as
well as electricity generation. Our marketing and trading segment includes
activities related to wholesale marketing and trading and APSES' competitive
energy services. The other amounts include activity relating to Suncor and El
Dorado.

     The following table summarizes net income by business segment for the three
and twelve months ended March 31, 2002 and the comparable prior-year periods
(dollars in millions):

                                     Three Months             Twelve Months
                                        Ended                     Ended
                                       March 31,                 March 31,
                                  -------------------      --------------------
                                   2002        2001         2002         2001
                                  -------     -------      -------      -------
Retail                            $    31     $     3      $   179      $   199
Marketing and trading                  21          58          134          122
Other                                   2           1            5          (10)
                                  -------     -------      -------      -------
Income before accounting
  change                               54          62          318          311
Cumulative effect of a change
  in accounting - net of
  income taxes                         --          (3)         (12)          (3)
                                  -------     -------      -------      -------
Net income                        $    54     $    59      $   306      $   308
                                  =======     =======      =======      =======

OPERATING RESULTS

     OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 2002 COMPARED WITH
     THREE-MONTH PERIOD ENDED MARCH 31, 2001

     Our consolidated net income for the three months ended March 31, 2002 was
$54 million compared with $59 million for the same period in the prior year. In
2001, we recognized a $3 million after-tax loss in net income as the cumulative
effect of a change in accounting for derivatives, as required by SFAS No.133.

     Income before accounting change for the three months ended March 31, 2002
was $54 million compared with $62 million for the same period in the prior year.
The period-to-period decrease is the result of lower marketing and trading
earnings contributions and a retail electricity price decrease. These negative
factors were partially offset by lower costs for replacement power due to lower
market prices and less outages, power plant maintenance, and generation
reliability. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):

                                      -22-
<PAGE>
<TABLE>
<CAPTION>
                                                                                 Increase
                                                                                (Decrease)
                                                                                ----------
<S>                                                                             <C>
Increases (decreases) in electric revenues, net of purchased power and fuel
expense due to:
  Marketing and trading activities:
    Decrease from generation sales other than native load due to lower
      market prices and resulting lower sales volumes                           $      (46)
    Increase in other realized marketing and trading in the current period
      primarily due to higher unit margins on increased volumes                         38(a)
    Change in prior-period mark-to-market gains for contracts delivered
      during the current period (b)                                                    (35)(a)
    Lower mark-to-market gains for future-period deliveries (b)                        (24)
                                                                                ----------
    Net decrease in marketing and trading                                              (67)
  Lower replacement power costs for plant outages due to lower
    market prices and fewer unplanned outages                                           50
  Increased fuel costs related to higher hedged natural gas and
    purchased power prices                                                             (11)
  Change in mark-to-market for hedged natural gas and purchased power
    costs for future-period deliveries related to accounting for
    derivatives                                                                          3
  Effects of milder weather on retail sales                                             (6)
  Higher retail sales volumes due to customer growth and higher
    average usage excluding weather effects                                              4
  Retail price reductions effective July 1, 2001                                        (5)
  Miscellaneous factors - net                                                            1
                                                                                ----------
Total decrease in electric revenues, net of purchased power and fuel expense           (31)
Lower operations and maintenance expenses primarily related to reliability,
  outage and maintenance costs, and the absence of a provision for credit
  expense, partially offset by higher employee benefit costs                             8
Lower depreciation and amortization primarily due to lower regulatory asset
  amortization                                                                           5
Miscellaneous items, net                                                                 4
                                                                                ----------
  Decrease in income before income taxes                                               (14)
Lower income taxes primarily due to lower income                                         6
                                                                                ----------
  Decrease in income before accounting change                                   $       (8)
                                                                                ==========
</TABLE>

----------
(a)  Net marketing and trading gains (excluding the effects of generation sales
     other than native load) realized during the current period increased $3
     million.
(b)  Essentially all of our marketing and trading activities are structured
     activities. This means our portfolio of forward sales positions is hedged
     with a portfolio of forward purchases that protects the economic value of
     the sales transactions.

                                      -23-
<PAGE>
     Electric operating revenues decreased approximately $327 million primarily
because of:

*    changes in marketing and trading revenues ($294 million, net decrease) due
     to:
     -    decreased revenues related to generation sales other than native load
          due to lower market prices and resulting lower sales volumes ($79
          million);
     -    decreased realized revenues related to other realized marketing and
          trading in the current period primarily due to lower prices ($165
          million);
     -    change in prior-period mark-to-market gains on contracts delivered
          during the current period ($28 million decrease);
     -    lower mark-to-market gains for future-period deliveries primarily as a
          result of lower market price volatility ($22 million);
*    decreased revenues related to other wholesale sales as a result of lower
     sales volumes and lower prices ($27 million);
*    decreased retail revenues related to milder weather ($9 million);
*    increased retail revenues related to customer growth and higher usage
     excluding weather effects ($7 million);
*    decreased retail revenues related to a reduction in retail electricity
     prices ($5 million); and
*    other miscellaneous factors ($1 million increase).

     Purchased power and fuel expenses decreased approximately $296 million
primarily because of:

*    changes in purchased power and fuel costs related to marketing and trading
     activities ($227 million, net decrease) due to:
     -    decreased fuel costs related to generation sales other than native
          load primarily because of lower sales volumes and lower natural gas
          prices ($33 million);
     -    decreased purchased power costs related to other realized marketing
          and trading in the current period primarily due to lower prices ($203
          million);
     -    change in prior-period mark-to-market fuel costs for current-period
          deliveries related to accounting for derivatives ($7 million
          increase);
     -    change in mark-to-market fuel costs for future-period deliveries
          related to accounting for derivatives ($2 million increase);
*    decreased costs related to other wholesale sales as a result of lower sales
     volumes and lower prices ($27 million);
*    increased fuel costs related to higher hedged natural gas and purchased
     power prices ($11 million);
*    change in mark-to-market for hedged natural gas and purchased power costs
     for future-period deliveries related to accounting for derivatives ($3
     million decrease);
*    decreased costs related to the effects of milder weather on retail sales
     ($3 million);
*    increased costs related to retail sales growth excluding weather effects
     ($3 million); and
*    decreased replacement power costs for power plant outages due to lower
     market prices and fewer unplanned outages ($50 million).

                                      -24-
<PAGE>
     The decrease in operations and maintenance expenses of $8 million primarily
related to costs incurred in 2001 for the generation reliability program (the
addition of generation capacity to enhance reliability for the summer of 2001)
and plant outages and maintenance ($7 million); and the absence of a provision
for credit exposure related to the California energy situation recorded in 2001
($5 million). These factors were partially offset by increased employee benefit
and other costs in the current period ($4 million).

     The decrease in depreciation and amortization expenses of $5 million
primarily related to lower regulatory asset amortization, in accordance with
APS' 1999 Settlement Agreement.

     OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2002 COMPARED WITH
     TWELVE-MONTH PERIOD ENDED MARCH 31, 2001

     Our consolidated net income for the twelve months ended March 31, 2002 was
$306 million compared with $308 million for the same period in the prior year.
We recognized $12 million after-tax loss in the twelve months ended March 31,
2002 and a $3 million after-tax loss in the twelve months ended March 31, 2001
as cumulative effects of change in accounting for derivatives, as required by
SFAS No.133.

     Income before accounting change for the twelve months ended March 31, 2002
was $318 million compared with $311 million for the same period a year earlier.
The period-to-period comparison benefited from favorable marketing and trading
results, including significant benefits in the third quarter of 2001 from
structured trading activities; lower replacement power costs; and retail
customer growth. These factors were partially offset by continuing retail
electricity price decreases; higher hedged purchased power and fuel costs, costs
of generation reliability measures; and charges related to Enron and its
affiliates. The major factors that increased (decreased) income before
accounting change were as follows (dollars in millions):

                                      -25-
<PAGE>
<TABLE>
<CAPTION>
                                                                                 Increase
                                                                                (Decrease)
                                                                                ----------
<S>                                                                             <C>
Increases (decreases) in electric revenues, net of purchased power and fuel
expense due to:
  Marketing and trading activities:
    Decrease from generation sales other than native load due to
      lower market prices and resulting lower sales volumes                     $      (66)
    Increase in other realized marketing and trading in the current
      period primarily due to higher unit margins on increased sales
      volumes                                                                           80(a)
    Change in prior-period mark-to-market gains for contracts
      delivered in the current period (b)                                              (24)(a)
    Change in prior-period mark-to-market value related to trading with
      Enron and its affiliates (c)                                                      (8)
    Increase in mark-to-market gains for future-period deliveries (b)                   42
                                                                                ----------
    Net increase in marketing and trading                                               24
  Lower replacement power costs for plant outages related to lower
    market prices and fewer unplanned outages                                           24
  Retail price reductions effective July 1, 2001 and 2000                              (27)
  Charges related to purchased power contracts with Enron and its
    affiliates(c)                                                                      (13)
  Change in mark-to-market for hedged natural gas and purchased
    power costs for future-period deliveries related to accounting for
    derivatives                                                                         (9)
  Higher retail sales primarily related to customer growth and
    weather impacts, partially offset by lower usage and higher
    hedged cost of purchased power and fuel                                             20
                                                                                ----------
Total increase in electric revenues, net of purchased power and fuel                    19
  expense
Higher operations and maintenance expense primarily related to 2001
  generation reliability program                                                       (57)
Lower depreciation and amortization primarily due to lower regulatory
  asset amortization                                                                    11
Lower net interest expense primarily due to higher capitalized interest                 15
Lower other net expense primarily related to El Dorado                                  33
Miscellaneous items, net                                                                (4)
                                                                                ----------
  Net increase in income before income taxes                                            17
Higher income taxes primarily due to higher income                                     (10)
                                                                                ----------
  Net increase in income before accounting change                               $        7
                                                                                ==========
</TABLE>

----------
(a)  Net marketing and trading gains (excluding the effects of generation sales
     other than native load) realized during the current period increased $56
     million.
(b)  Essentially all of our marketing and trading activities are structured
     activities. This means our portfolio of forward sales positions is hedged
     with a portfolio of forward purchases that protects the economic value of
     the sales transactions.
(c)  We recorded charges totaling $21 million for exposure to Enron and its
     affiliates in the fourth quarter of 2001.

                                      -26-
<PAGE>
     Electric operating revenues increased approximately $64 million primarily
because of:

*    changes in marketing and trading revenues ($105 million, net increase) due
     to:
     -    decreased revenues related to generation sales other than native load
          as a result of lower market prices and resulting lower sales volumes
          ($125 million);
     -    increased realized revenues related to other marketing and trading in
          the current period primarily due to higher sales volumes ($212
          million);
     -    decrease in prior-period mark-to-market value related to trading with
          Enron and its affiliates ($8 million);
     -    change in prior-period mark-to-market gains for contracts delivered
          during the current period ($14 million decrease);
     -    increased mark-to-market gains for future-period deliveries primarily
          because of higher sales volumes ($40 million);
*    decreased wholesale and other revenues as a result of lower sales volumes
     ($69 million);
*    higher retail sales related to customer growth and weather impacts,
     partially offset by lower average residential usage ($55 million); and
*    decreased retail revenues related to reductions in retail electricity
     prices effective July 1, 2001 and 2000 ($27 million).

     Purchased power and fuel expenses increased approximately $45 million
primarily because of:

*    changes in purchased power and fuel costs related to marketing and trading
     activities ($81 million, net increase) due to:
     -    decreased fuel costs related to generation sales other than native
          load as a result of lower sales volumes ($59 million);
     -    increased fuel and purchased power costs related to other realized
          marketing and trading in the current period primarily due to higher
          sales volumes ($132 million);
     -    change in prior-period mark-to-market fuel costs for current-period
          deliveries related to accounting for derivatives ($10 million
          increase);
     -    change in mark-to-market fuel costs for future-period deliveries
          related to accounting for derivatives ($2 million decrease);
*    decreased costs related to other wholesale sales as a result of lower sales
     volumes ($69 million);
*    lower replacement power costs primarily due to lower market prices and
     fewer unplanned outages ($24 million);
*    higher costs related to retail sales as a result of the higher hedged cost
     of purchased power and fuel and higher retail sales volumes related to
     customer growth and weather impacts ($35 million);
*    change in mark-to-market for hedged natural gas and purchased power costs
     for future-period deliveries related to accounting for derivatives ($9
     million increase) and;
*    charges related to purchased power contracts with Enron and its affiliates
     ($13 million).

     The increase in operations and maintenance expenses of $57 million
primarily related to the 2001 generation reliability program (the addition of
generating capability to enhance reliability for the summer of 2001) and

                                      -27-
<PAGE>
scheduled plant outages and maintenance ($39 million); and increased employee
benefit and other costs ($28 million). These factors were partially offset by a
provision for our credit exposure related to the California energy situation
recorded in the prior period ($10 million).

     The decrease in depreciation and amortization expenses of $11 million
primarily related to lower regulatory asset amortization, in accordance with
APS' 1999 regulatory settlement agreement.

     Net other expense decreased $33 million primarily because of a change in
the market value of El Dorado's investment in a technology-related venture
capital partnership in the prior period and an insurance recovery of
environmental remediation costs, partially offset by other non-operating costs.
The major investment in the venture capital partnership was sold in the first
quarter of 2001.

     Net interest expense decreased by $15 million primarily because of the
increase in capitalized interest ($23 million) related to our generation
expansion program and the effects of lower interest rates. The reductions in net
interest expense more than offset the increases in interest expense for higher
debt balances that were related primarily to our generation expansion program.

LIQUIDITY AND CAPITAL RESOURCES

     CAPITAL EXPENDITURE REQUIREMENTS

     The following table summarizes the actual capital expenditures for the
three months ended March 31, 2002 and estimated capital expenditures for the
next three years (dollars in millions):

                                      Three-              Estimated
                                      Months     ----------------------------
                                      Ended        Years Ended December 31,
                                     March 31,   ----------------------------
                                       2002       2002       2003       2004
                                      ------     ------     ------     ------
APS
  Delivery                            $   92     $  349     $  271     $  280
  Existing generation (a)                 27        149         --         --
                                      ------     ------     ------     ------
      Subtotal                           119        498        271        280
                                      ------     ------     ------     ------
Pinnacle West Energy (b)
  Generation expansion                    98        411        255        113(e)
  Existing generation (a)                 --         --        107         99
                                      ------     ------     ------     ------
      Subtotal                            98        411        362        212
                                      ------     ------     ------     ------
SunCor (c)                                17         79         48         52
Other (d)                                  4         35         15         16
                                      ------     ------     ------     ------
Total                                 $  238     $1,023     $  696     $  560
                                      ======     ======     ======     ======

                                      -28-
<PAGE>
----------
(a)  Pursuant to the 1999 Settlement Agreement, APS is required to transfer its
     competitive electric assets and services no later than December 31, 2002.
     See Note 5.
(b)  See further discussion below of Pinnacle West Energy's generation expansion
     program and "Capital Resources and Cash Requirements - Pinnacle West
     Energy" below.
(c)  Consists primarily of capital expenditures for land development and retail
     and office building construction reflected in the "Increase in real estate
     investments" in the condensed consolidated statements of cash flows.
(d)  Primarily Pinnacle West and APSES.
(e)  This amount does not include an expected reimbursement by SNWA of $100
     million of these costs in 2004 in exchange for SNWA's purchase of a 25%
     interest in the Silverhawk project at that time.

     APS and the other Palo Verde participants are currently considering issues
related to replacement of the steam generators in Units 1 and 3. Although a
final determination of whether Units 1 and 3 will require steam generator
replacement to operate over their current full licensed lives has not yet been
made, APS and the other participants have approved an expenditure in 2002 to
procure long lead-time materials for fabrication of a spare set of steam
generators for either Unit 1 or 3. APS' portion of this expenditure is
approximately $7 million and is included in the estimated expenditures above.
This action will provide the Palo Verde participants an option to replace the
steam generators at either Unit 1 or 3 as early as fall 2005 should they
ultimately choose to do so. If the participants decide to proceed with steam
generator replacement at both Units 1 and 3, we have estimated that our portion
of the fabrication and installation costs and associated power uprate
modifications would be approximately $130 million over the next seven years,
which would be funded with internally-generated cash or external financings. See
Note 5.

     Existing generation capital expenditures are comprised of multiple
improvements for our existing fossil and nuclear plants. Examples of the types
of projects included in this category are additions, upgrades and capital
replacements of various power plant equipment such as turbines, boilers, and
environmental equipment. The existing generation also contains nuclear fuel
expenditures of approximately $30 million annually in 2002, 2003, and 2004.

     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
included in the forecast include T&D lines and substations, line extensions to
new residential and commercial developments, and upgrades to customer
information systems. In addition, we began several major transmission projects
in 2001. These projects are periodic in nature and are driven by strong regional
customer growth. We expect to spend about $150 million on major transmission
projects during the 2002-2004 time frame.

                                      -29-
<PAGE>
     CAPITAL RESOURCES AND CASH REQUIREMENTS

     The following table summarizes actual cash commitments for the three months
ended March 31, 2002 and estimated commitments for the next three years (dollars
in millions):

                                         Three               Estimated
                                         Months     ----------------------------
                                         Ended        Years Ended December 31,
                                        March 31,   ----------------------------
                                          2002       2002       2003       2004
                                         ------     ------     ------     ------
Long-term debt payments
  APS                                    $  125     $  247     $   --     $  205
  Pinnacle West                              --         --        276        216
  SunCor                                     --         --         42         86
                                         ------     ------     ------     ------
Total long-term debt payments               125        247        318        507
Operating leases payments                     5         68         66         65
Fuel and purchase power commitments          55        270        124         80
                                         ------     ------     ------     ------
Total cash commitments                   $  185     $  585     $  508     $  652
                                         ======     ======     ======     ======

          PINNACLE WEST

     The parent company's cash requirements and its ability to fund those
requirements are discussed under "Capital Needs and Resources" in Management's
Discussion and Analysis of Financial Condition and Results of Operation in Part
II, Item 7 of the 2001 10-K.

     During the three months ended March 31, 2002, the parent company increased
its outstanding indebtedness by about $215 million. On February 8, 2002, we
issued $215 million of 4.5% Notes due 2004. See the cash commitments table above
for the parent company's debt repayment requirements. The majority of these
borrowings were used to fund Pinnacle West Energy capital expenditures.

          APS

     APS' cash requirements and its ability to fund those requirements are
discussed under "Capital Needs and Resources" in Management's Discussion and
Analysis of Financial Condition and Results of Operation in Part II, Item 7 of
the 2001 10-K.

     During the three months ended March 31, 2002, APS increased its outstanding
indebtedness by about $375 million. On March 1, 2002, APS issued $375 million of
6.50% Notes due 2012. See the cash commitments table above for APS' debt
repayments. Based on market conditions and optional call provisions, APS may
make optional redemptions of long-term debt from time to time.

                                      -30-
<PAGE>
     As of March 31, 2002, APS deposited $122 million, plus interest, with the
trustee under its Mortgage for the redemption in April 2002 of its First
Mortgage Bonds, 8.75% Series due 2024.

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

     PINNACLE WEST ENERGY

     Pinnacle West Energy has completed or announced plans to build about 3,420
MW of natural gas-fired generating capacity from 2001 through 2007 at an
estimated cost of about $1.9 billion. This does not reflect an expected
reimbursement in 2004 by SNWA of $100 million of Pinnacle West Energy's
cumulative capital expenditures in the Silverhawk project in exchange for SNWA's
purchase of a 25% interest in the project. Our expansion plan will be sized to
meet native load growth, cash flow and market conditions. Pinnacle West Energy
is currently funding its capital requirements through capital infusions from
Pinnacle West, which finances those infusions through debt financings and
internally-generated cash. As Pinnacle West Energy develops and obtains
additional generation assets, including APS' existing generation assets,
Pinnacle West Energy expects to fund its capital requirements through
internally-generated cash and its own debt issuances. See the Capital
Expenditures Table above for actual capital expenditures through March 31, 2002
and projected capital expenditures for the next three years.

     Pinnacle West Energy has completed or is currently planning the following
projects:

     *    A 650 MW expansion of the West Phoenix Power Plant in Phoenix. The 120
          MW West Phoenix Unit 4 began commercial operation on June 1, 2001.
          Construction has begun on the 530 MW West Phoenix Unit 5, with
          commercial operation expected to begin in mid-2003.

     *    The construction of a four-unit combined cycle 2,120 MW generating
          station near Palo Verde, called Redhawk. Construction of Units 1 and 2
          began in December 2000, and commercial operation is currently
          scheduled for the summer of 2002. Although Pinnacle West Energy
          currently plans to bring Units 3 and 4 on line in or before the first
          quarter of 2007, equipment procurement, engineering and construction
          plans will allow for these units to come on line as early as 2005 if
          warranted by market conditions.

     *    The construction of an 80 MW simple-cycle power plant at Saguaro in
          Southern Arizona. Commercial operation is currently scheduled for the
          summer of 2002.

     *    Development of an electric generating station 20 miles north of Las
          Vegas, Nevada. Construction of the 570 MW Silverhawk combined-cycle
          plant is expected to begin in the spring of 2002, with an expected
          commercial operation date of mid-2004. Pinnacle West Energy has signed
          a 25% participation agreement with Las Vegas-based SNWA.

                                      -31-
<PAGE>
     *    A Pinnacle West Energy affiliate is exploring the possibility of
          creating an underground natural gas storage facility on Company-owned
          land west of Phoenix. A feasibility study is in progress to determine
          if the proposed acreage can support a natural gas storage cavern.

          OTHER SUBSIDIARIES

     During the past three years, both SunCor and El Dorado funded all of their
cash requirements with cash from operations and, in the case of SunCor, its own
external financings. APSES funded its cash requirements with cash infusions from
Pinnacle West.

     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, 2002 and projected capital expenditures for the next three
years. SunCor expects to fund its capital requirements with cash from operations
and external financings.

     El Dorado does not have any capital requirements over the next three years.
El Dorado intends to focus on prudently realizing the value of its existing
investments. El Dorado's future investments are expected to be related to the
energy sector.

     APSES' 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 APSES' capital expenditures.

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 determination
of the appropriate accounting for our derivative instruments, mark-to-market
accounting and the impacts of regulatory accounting on our consolidated
financial statements. See Note 1 in the 2001 10-K.

BUSINESS OUTLOOK

     We currently believe that it will be a challenge for us in 2002 to repeat
our 2001 earnings. For 2001, our reported income before accounting change was
$327 million, or $3.85 per diluted share of common stock, and included charges
totaling $21 million before income taxes, or $0.15 per diluted share, that we do
not expect to recur related to our exposure to Enron and its affiliates. Our
earnings in 2002 are expected to be negatively affected by a significant
decrease in the earnings contribution from our marketing and trading activities
and retail electricity price decreases. These negative factors are expected to
be substantially offset in 2002 by the absence of significant expenses for
reliability and power plant outages that we incurred in 2001 that we do not
expect to recur in 2002 and by retail customer growth, although the pace of
growth is expected to be slower than in the past. These factors are described in
more detail below.

                                      -32-
<PAGE>
     In 2001, our marketing and trading activities contributed about one-half of
our income before accounting change before the Enron-related charges. These
activities are currently expected to provide about one-fourth of our earnings in
2002. The drivers of such reduced earnings contributions from our marketing and
trading activities in 2002 are significant reductions in wholesale market prices
for electricity that occurred during 2001; wholesale market liquidity, which
affects our ability to buy and resell electricity; and market volatility, which
affects our ability to capture profitable structured trading activities. These
reductions in regional market factors were due, in large part, to conservation
measures in California and throughout the West; more generating plants in
service in the West; lower natural gas prices; and the price mitigation plan
that took effect in June 2001 as mandated by the FERC.

     During 2001, in order to meet the highest customer demand in APS' history,
we incurred significant expenses for our summer reliability program and for
higher replacement power costs related to power plant outages. These efforts
cost approximately $140 million before income taxes, which is not expected to be
repeated in 2002.

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

     As of December 31, 2001, the indicated annual dividend rate on our common
stock was $1.60 per share. Since 1994, we have increased the dividend on our
common stock ten cents per share per year. We currently plan to continue annual
dividend increases of relatively consistent amounts, which would continue
dividend growth at a pace above the industry average.

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

     COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING

     See "Business Outlook - Competition and Industry Restructuring" in Item 7
of the 2001 10-K and Note 5 above for a discussion of developments affecting
retail and wholesale electric competition.

     GENERATION EXPANSION

     See "Capital Resources and Cash Requirements - Pinnacle West Energy" above
for information regarding our generation expansion plans. The planned additional
generation is expected to increase revenues, fuel expenses, operating expenses,
and financing costs.

                                      -33-
<PAGE>
     FACTORS AFFECTING OPERATING REVENUES

     Electric operating revenues are derived from sales of electricity in
regulated retail markets in Arizona, and from competitive retail and wholesale
bulk power markets in the western United States. These revenues are expected to
be affected by electricity sales volumes related to customer mix, customer
growth and average usage per customer, as well as electricity prices and
variations in weather from period to period.

     In APS' regulated retail market area, APS will provide electricity services
to standard-offer, full-service customers and to energy delivery customers who
have chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in APS' service territory averaged about 4% a year
for the three years 1999 through 2001; we currently expect customer growth to be
about 3.2% in 2002 and between 3.5% and 4.0% a year in 2003 and 2004. We
currently estimate that retail electricity sales in kilowatt-hours will grow
3.5% to 5.5% a year in 2002 through 2004, before the retail effects of weather
variations. The customer growth and sales growth referred to in this paragraph
apply to energy delivery customers. As industry restructuring evolves in the
regulated market area, we cannot predict the number of APS' standard-offer
customers that will switch to unbundled service. As previously noted, under the
1999 Settlement Agreement, we have retail electricity price reductions of 1.5%
annually through July 1, 2003 (see Note 5).

     Competitive sales of energy and energy-related products and services are
made by APSES in western states that have opened to competitive supply. Such
activities currently are not material to our consolidated financial results.

     OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS

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

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

     Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property, changes in regulatory
asset amortization, and our generation expansion program.

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

     Interest expense is affected by the amount of debt outstanding and the
interest rates on that debt. The primary factors affecting borrowing levels in
the next several years are expected to be our generation expansion program 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.

                                      -34-
<PAGE>
     The annual earnings contribution from APSES is expected to be modest, yet
positive, over the next several years due primarily to a number of retail
electricity contracts in California. APSES' pretax losses were $10 million in
2001 and $13 million in 2000.

     The annual earnings contribution from SunCor is expected to remain modest
over the next several years. SunCor's earnings were $3 million in 2001, $11
million in 2000 and $6 million in 1999.

     El Dorado's historical results are not necessarily indicative of future
performance for El Dorado. El Dorado's strategies focus on prudently realizing
the value of its existing investments. Any future investments are expected to be
related to the energy sector.

     We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, results of operations, or liquidity. As
competition in the electric industry continues to evolve, we will continue to
evaluate strategies and alternatives that will position us to compete
effectively in a restructured industry.

     Our financial results may be affected by the application of SFAS No. 133.
See Note 10 for further information.

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

RATE MATTERS

     See Note 5 for a discussion of a price reduction effective as of July 1,
2001, and for a discussion of the 1999 Settlement Agreement that will, among
other things, result in five annual price reductions over a four-year period
ending July 1, 2003.

FORWARD-LOOKING STATEMENTS

     The above discussion contains forward-looking statements based on current
expectations and we assume no obligation to update these statements. Because
actual results may differ materially from expectations, we caution readers not
to place undue reliance on these statements. A number of factors could cause
future results to differ materially from historical results, or from results or
outcomes currently expected or sought by us. These factors include the ongoing
restructuring of the electric industry, including the introduction of retail
electric competition in Arizona; the outcome of regulatory and legislative
proceedings relating to the restructuring; state and federal regulatory and
legislative decisions and actions, including the price mitigation plan adopted
by the FERC in June 2001; regional economic and market conditions, including the
California energy situation and completion of generation construction in the
region, which could affect customer growth and the cost of power supplies; the
cost of debt and equity capital; weather variations affecting local and regional
customer energy usage; conservation programs; power plant performance; the
successful completion of our generation expansion program; regulatory issues

                                      -35-
<PAGE>
associated with generation expansion, such as permitting and licensing; our
ability to compete successfully outside traditional regulated markets (including
the wholesale market); technological developments in the electric industry; and
the strength of the real estate market in SunCor's market areas, which include
Arizona, New Mexico and Utah.

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

ITEM 3. MARKET RISKS

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

     We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage risks associated with
these market fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into derivative
transactions to hedge purchases and sales of electricity, fuels, and emissions
allowances and credits. The changes in market value of such contracts have a
high correlation to price changes in the hedged commodity.

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

     The following schedule shows the changes in mark-to-market of our trading
positions during the three months ended March 31, 2002 (dollars in millions):

                                                                     For Three
                                                                    Months Ended
                                                                      March 31,
                                                                        2002
                                                                    ------------
Mark-to-market of net trading
  positions at beginning of period                                    $    138
Prior period mark-to-market gains
  realized during the period                                               (22)
Change in mark-to-market gains for
  future period deliveries                                                  25
                                                                      --------
Mark-to-market of net trading
  positions at end of period                                          $    141
                                                                      ========

                                      -36-
<PAGE>
     Net gains at inception include a reasonable marketing margin and were
approximately $8 million for the three months ended March 31, 2002. See Note 10
for mark-to-market on system hedges and for disclosure of risk management
activities recorded on the consolidated balance sheets.

     The table below shows the maturities of our trading positions as of March
31, 2002, by the type of valuation that is performed to calculate the fair value
of the contract (millions of dollars):

                                                            2005 and     Total
                                                             years        fair
Source of Fair Value          2002      2003      2004     thereafter     value
--------------------         ------    ------    ------    ----------    ------
Prices actively quoted       $  (34)   $   --    $   --      $   --      $  (34)
Prices provided by other
  external sources                1        (1)        7          12          19
Prices based on models and
  other valuation methods        58        28        21          49         156
                             ------    ------    ------      ------      ------
Total by maturity            $   25    $   27    $   28      $   61      $  141
                             ======    ======    ======      ======      ======

     The table below shows the impact that hypothetical price movements of 10%
would have on the market value of our risk management and trading assets and
liabilities included on the consolidated balance sheets at March 31, 2002
(dollars in millions):

                                                         March 31, 2002
                                                --------------------------------
                                                           Gain (Loss)
                                                --------------------------------
Commodity                                       Price Up 10%      Price Down 10%
---------                                       ------------      --------------
  Trading (a):
    Electric                                      $    (2)           $     2
    Natural gas                                        (1)                 1
    Other                                               1                 (1)
  System (b):
    Natural gas
      hedges                                           26                (24)
                                                  -------            -------

    Total                                         $    24            $   (22)
                                                  =======            =======

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

     We are exposed to losses in the event of nonperformance or nonpayment by
counterparties. We have risk management and trading contracts with many
counterparties, including one counterparty for which a worst case exposure

                                      -37-
<PAGE>
represents approximately 44% of our $285 million of risk management and trading
assets as of March 31, 2002. We use a risk management process to assess and
monitor the financial exposure of this and all other counterparties. Despite the
fact that the great majority of trading counterparties are rated as investment
grade by the credit rating agencies, including the counterparty 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. Credit reserves are established
representing our estimated credit losses on our overall exposure to
counterparties.

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

                                      -38-
<PAGE>
                           PART II - OTHER INFORMATION

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.

     COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING

     See Note 5 of Notes to Condensed Consolidated Financial Statements in Part
I, Item 1 of this report for a discussion of regulatory developments regarding
the introduction of retail electric competition in Arizona and related matters.

     PALO VERDE NUCLEAR GENERATING STATION

     In February 2002, the U. S. Secretary of Energy recommended to President
Bush that the Yucca Mountain, Nevada site be developed as a permanent repository
for spent nuclear fuel. See Note 10 of Notes to Consolidated Financial
Statements of the 2001 10-K. The President transmitted this recommendation to
Congress and the State of Nevada has vetoed the President's recommendation. A
congressional decision on whether to override the Nevada veto is expected
sometime during the summer of 2002. We cannot currently predict what further
steps will be taken in this area.

     ENVIRONMENTAL MATTERS

     The EPA reviewed an "Annex" to the GCVTC recommendations and, on April 26,
2002, the EPA proposed to accept the GCVTC's Annex, submitted by the Western
Regional Air Partnership (successor to GCVTC) in September 2000. See
"Environmental Matters - EPA Environmental Regulations - Clean Air Act" in Part
I, Item 1 of the 2001 10-K. The Annex specifies regional sulfur dioxide emission
reduction milestones. The EPA's final approval of the Annex would allow the
GCVTC states and tribes to pursue the alternate implementation of the regional
haze rules through 2018. Any states and tribes that implement this option would
have to submit state implementation plans by 2003 to address visibility in areas
identified in the GCVTC process, and revised implementation plans in 2008 to
address Class I Areas which were not included in the GCVTC process. The State of
Arizona is in the process of developing a State Implementation Plan to implement
the provisions of the Annex. Because Four Corners is located on the Navajo
Reservation and is currently regulated by EPA Region IX, the provisions of the
Annex currently could become applicable to Four Corners only through a Federal
Implementation Plan promulgated by EPA Region IX. At this time, it is uncertain
how the State of Arizona and/or EPA Region IX will proceed to implement the
Annex, so the actual impact on APS cannot yet be determined.

     In February 2001, the U.S. Supreme Court found, among other things, that
the EPA implementation policy for revised ozone standards was unlawful, and
remanded this issue for consideration along with other preserved challenges to
the National Ambient Air Quality Standards. See "Environmental Matters - EPA
Environmental Regulation - Clean Air Act" in the 2001 10-K. On remand, on March
26, 2002, the U.S. Court of Appeals for the District of Columbia upheld the more
stringent eight-hour ozone standard and the particulate matter standard.

                                      -39-
<PAGE>
Because the actual level of emissions controls, if any, for any unit cannot be
determined at this time, APS currently cannot estimate the capital expenditures,
if any, which would result from the final rules. However, APS does not currently
expect these rules to have a material adverse effect on its financial position,
results of operations, or liquidity.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

     (a)  Exhibits

          Exhibit No.                        Description
          -----------                        -----------
          4.1               Amendment to Rights Agreement, effective as of
                            January 1, 2002

          10.1              Amendment No. 5 to the Amended and Restated
                            Decommissioning Trust Agreement (PVNGS Unit 2),
                            dated as of June 30, 2000

          10.2              Amendment No. 3 to the Decommissioning Trust
                            Agreement (PVNGS Unit 1), dated as of March 18, 2002

          10.3              Amendment No. 6 to the Amended and Restated
                            Decommissioning Trust Agreement (PVNGS Unit 2),
                            dated as of March 18, 2002

          10.4              Amendment No. 3 to the Decommissioning Trust
                            Agreement (PVNGS Unit 3), dated as of March 18, 2002

          12.1              Ratio of Earnings to Fixed Charges

                                      -40-
<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

3.2           Bylaws, amended as of       4.1 to the Company's          1-8962      1-20-00
              December 15, 1999           Registration Statement
                                          on Form S-8 No. 333-95035
</TABLE>

     (b)  Reports on Form 8-K

     During the quarter ended March 31, 2002, and the period from April 1
through May 15, 2002, we filed the following reports on Form 8-K:

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

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

     Report dated March 31, 2002 regarding (i) exhibits comprised of financial
information and earnings variance explanations, (ii) an exhibit of a slide
presentation for use at an analyst conference, and (iii) a motion filed by APS
in a consolidated ACC docket.

     Report dated April 26, 2002 regarding ACC procedural orders.

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

                                      -41-
<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 15, 2002                     By: Chris N. Froggatt
                                            ------------------------------------
                                            Chris N. Froggatt
                                            Vice President and Controller
                                            (Principal Accounting Officer
                                            and Officer Duly Authorized
                                            to sign this Report)

                                      -42-

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.1
<SEQUENCE>3
<FILENAME>ex4-1.txt
<DESCRIPTION>AMENDMENT TO RIGHTS AGREEMENT
<TEXT>
                                                                     Exhibit 4.1

                          AMENDMENT TO RIGHTS AGREEMENT

     This Amendment to Rights Agreement (this  "Amendment") is made effective as
of January 1, 2002, by and among Pinnacle West Capital  Corporation,  an Arizona
corporation   ("Pinnacle  West"),   Fleet  National  Bank,   formerly  known  as
BankBoston, N.A. ("Fleet"), and EquiServe Trust Company, N.A. ("EquiServe"),  as
the new Rights Agent.  All  capitalized  terms used herein and not defined shall
have their meanings set forth in the Agreement (as defined below).

1.   GENERAL  BACKGROUND.  In  accordance  with  Section 27 of the  Amended  and
     Restated Rights Agreement between Pinnacle West and BankBoston, N.A., dated
     as of March 26, 1999 (the "Agreement"),  the parties hereto desire to amend
     the Agreement as set forth below.

2.   APPOINTMENT  OF  SUCCESSOR  RIGHTS  AGENT.  Pinnacle  West hereby  appoints
     EquiServe as the  successor  Rights Agent under the Agreement and EquiServe
     hereby accepts such  appointment and assumes and agrees to perform each and
     all of the obligations,  covenants and agreements of the Rights Agent under
     the Agreement, as such Agreement may be modified herein.

3.   REVISION.  Section 21 of the Agreement entitled "Change of Rights Agent" is
     hereby deleted in its entirety and replaced with the following:

     CHANGE OF RIGHTS AGENT.  The Rights Agent or any successor Rights Agent may
     resign and be discharged from its duties under this Agreement upon 30 days'
     notice in writing  mailed to the Company and to each transfer  agent of the
     Common Stock or Preferred  Stock by  registered  or  certified  mail,  and,
     following the Distribution  Date, to the holders of the Right  Certificates
     by  first-class  mail.  The  Company  may remove  the  Rights  Agent or any
     successor  Rights  Agent  upon 30 days'  notice in  writing,  mailed to the
     Rights Agent or  successor  Rights  Agent,  as the case may be, and to each
     transfer  agent of the Common Stock or  Preferred  Stock by  registered  or
     certified mail, and, following the Distribution Date, to the holders of the
     Right Certificates by first-class mail. If the Rights Agent shall resign or
     be removed or shall otherwise become incapable of acting, the Company shall
     appoint a successor to the Rights Agent.  If the Company shall fail to make
     such  appointment  within a period of 30 days after  giving  notice of such
     removal or after it has been  notified  in writing of such  resignation  or
     incapacity by the resigning or incapacitated  Rights Agent or by the holder
     of a Right Certificate (who shall,  with such notice,  submit such holder's
     Right  Certificate  for  inspection  by the Company),  then the  registered
     holder  of any  Right  Certificate  may  apply to any  court  of  competent
     jurisdiction  for the  appointment  of a new Rights  Agent.  Any  successor
     Rights  Agent or its agent,  whether  appointed by the Company or by such a
     court,  shall be a corporation,  bank or trust company  organized and doing
<PAGE>
     business  under the laws of the United States,  in good standing,  which is
     authorized  under such laws to exercise  corporate  trust or stock transfer
     powers and is subject to  supervision  or  examination  by federal or state
     authority and which has  individually  or combined with an affiliate at the
     time of its  appointment as Rights Agent a combined  capital and surplus of
     at least $100 million  dollars.  After  appointment,  the successor  Rights
     Agent  shall  be  vested  with  the  same   powers,   rights,   duties  and
     responsibilities as if it had been originally named as Rights Agent without
     further act or deed;  but the  predecessor  Rights Agent shall  deliver and
     transfer to the successor  Rights Agent any property at the time held by it
     hereunder, and execute and deliver any further assurance,  conveyance,  act
     or deed necessary for the purpose. Not later than the effective date of any
     such  appointment the Company shall file notice thereof in writing with the
     predecessor  Rights  Agent and each  transfer  agent of the Common Stock or
     Preferred  Stock,  and,  following  the  Distribution  Date,  mail a notice
     thereof  in writing to the  registered  holders of the Right  Certificates.
     Failure to give any notice provided for in this Section 21, however, or any
     defect  therein,   shall  not  affect  the  legality  or  validity  of  the
     resignation  or  removal  of the  Rights  Agent or the  appointment  of the
     successor Rights Agent, as the case may be.

4.   Except as  explicitly  amended  hereby,  the Agreement and all schedules or
     exhibits thereto shall remain in full force and effect.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed
in  their  names  and on their  behalf  by and  through  their  duly  authorized
officers, as of the date first set forth above.

PINNACLE WEST CAPITAL CORPORATION       FLEET NATIONAL BANK (FORMERLY KNOWN AS
                                        BANKBOSTON, N.A.)

Faye Widenmann                          Dennis V. Moccia
---------------------------------       ----------------------------------------
By: Faye Widenmann                      By: Dennis V. Moccia
Title: Vice President & Secretary       Title: Managing Director


                                        EQUISERVE TRUST COMPANY, N.A.

                                        Dennis V. Moccia
                                        ----------------------------------------
                                        By: Dennis V. Moccia
                                        Title: Managing Director

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.1
<SEQUENCE>4
<FILENAME>ex10-1.txt
<DESCRIPTION>AMENDMENT NO 5 - DECOMMISSIONING TRUST AGR UNIT 2
<TEXT>
                                                                    Exhibit 10.1

     This  Amendment  No.  5,  dated as of June 30,  2000,  to the  Amended  and
Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of January 31,
1992,  as amended  by  Amendment  No. 1 thereto  dated as of  November  1, 1992,
Amendment  No. 2 thereto  dated as of November 1, 1994,  Amendment No. 3 thereto
dated as of June 20, 1996,  and Amendment No. 4 thereto dated as of December 16,
1996 (the  "Decommissioning  Trust  Agreement";  terms  used  herein as  therein
defined), is entered into between Arizona Public Service Company ("APS"),  State
Street  Bank and Trust  Company,  as  successor  to The First  National  Bank of
Boston,   as  Owner   Trustee  and  as  Lessor,   and  Mellon  Bank,   N.A.,  as
Decommissioning Trustee ("Decommissioning Trustee").

                                R E C I T A L S:

     WHEREAS, the parties hereto wish to amend the investment parameters for the
Decommissioning  Trust Fund and the Second  Fund  contained  in Exhibit B to the
Decommissioning Trust Agreement;

     NOW,  THEREFORE,  in  consideration  of the  premises and of other good and
valuable   consideration,   receipt   and   sufficiency   of  which  are  hereby
acknowledged, the parties hereto agree as follows:

                              A G R E E M E N T S:

     SECTION 1. Amendment.

     Paragraph (l) of Exhibit B to the Decommissioning Trust Agreement is hereby
deleted and is replaced in its entirety by the following:

     (l)  (x)  corporate  equity  securities,  including,  but not  limited  to,
          investment in units of common or collective  trust funds  investing in
          corporate  equity  securities;  including,  but not  limited  to,  the
          Decommissioning  Trustee's Nuclear  Decommissioning Trust Equity Index
          Fund (the "NDT Equity Index Fund") and (y) obligations not included in
          clauses (a) through (k) issued or guaranteed by a person controlled or
          supervised by and acting as an instrumentality of the United States of
          America  pursuant to  authority  granted by the Congress of the United
          States of America,  including Federal  Intermediate Credit Bank, Banks
          for Cooperatives, Federal Land Banks, Federal Home Loan Banks, Federal
          Home Loan  Mortgage  Corporation;  provided,  that no more than  fifty
          percent (50%) of the aggregate  assets of the Funds may be invested in
          securities  described in (x) and (y) of this  subparagraph  (l) during
          the period from June 27, 1996 through  December 31, 2003, no more than
          thirty  percent  (30%)  during the period from January 1, 2004 through
          December 31, 2006,  and no more than fifteen  percent (15%) during the
          period from  January 1, 2007 through  January 31,  2010;  and provided
          further that after January 31, 2010, no  investments  shall be made in
          such securities.
<PAGE>
     SECTION 2. Effectiveness.

     This Amendment No. 5 shall become  effective as of the date hereof upon the
execution and delivery of a counterpart  of this  Amendment No. 5 by each of the
parties hereto.

     SECTION 3. Miscellaneous

     (a)  Full Force and Effect.

     Except as expressly  provided herein, the  Decommissioning  Trust Agreement
shall  remain  unchanged  and in full force and effect.  Each  reference  in the
Decommissioning  Trust Agreement and in any exhibit or schedule thereto to "this
Agreement,"  "hereto,"  "hereof" and terms of similar  import shall be deemed to
refer to the Decommissioning Trust Agreement as amended hereby.

     (b)  Counterparts.

     This Amendment No. 5 may be executed in any number of counterparts,  all of
which taken together shall  constitute one and the same  instrument,  and any of
the  parties  hereto  may  execute  this  Amendment  No. 5 by  signing  any such
counterpart.

     (c)  Arizona Law.

     This Amendment No. 5 shall be construed in accordance  with and governed by
the law of the State of Arizona.

     IN WITNESS WHEREOF,  the parties hereto have caused this Amendment No. 5 to
the  Decommissioning  Trust Agreement to be duly executed as of the day and year
first above written.

                                        ARIZONA PUBLIC SERVICE COMPANY


                                        By Barbara M. Gomez
                                           -------------------------------------

                                        Title Treasurer
                                              ----------------------------------

                                      -2-
<PAGE>
                                        MELLON BANK N.A., as
                                        Decommissioning Trustee


                                        By Gerald T. McDermott
                                           -------------------------------------

                                        Title Vice President
                                              ----------------------------------


                                        STATE STREET BANK AND TRUST COMPANY,  as
                                        Owner  Trustee  under a Trust  Agreement
                                        with Security  Pacific  Capital  Leasing
                                        Corporation   and  as  Lessor   under  a
                                        Facility   Lease  with  Arizona   Public
                                        Service Company


                                        By John Correia
                                           -------------------------------------

                                        Title Assistant Vice President
                                              ----------------------------------


                                        STATE STREET BANK AND TRUST COMPANY,  as
                                        Owner  Trustee  under a Trust  Agreement
                                        with  Emerson  Finance Co. and as Lessor
                                        under  a  Facility  Lease  with  Arizona
                                        Public Service Company


                                        By John Correia
                                           -------------------------------------

                                        Title Assistant Vice President
                                              ----------------------------------


                                      -3-
<PAGE>
STATE OF ARIZONA         )
                         )  ss.
County of Maricopa       )

     The  foregoing  instrument  was  acknowledged  before  me  this  8th day of
December,  2000, by Barbara M. Gomez,  the Treasurer of ARIZONA  PUBLIC  SERVICE
COMPANY, an Arizona corporation, on behalf of said corporation.


                                        Suzanne W. Debes
                                        ----------------------------------------
                                        Notary Public

My commission expires:

June 20, 2003
----------------------



STATE OF PENNSYLVANIA               )
                                    ) ss.
County of Allegheny                 )

     The  foregoing  instrument  was  acknowledged  before  me this  14th day of
December,  2000, by Gerald T. McDermott, a Trust Officer of MELLON BANK, N.A., a
corporation having trust powers, as Decommissioning  Trustee,  on behalf of said
corporation.


                                        Leona Esken
                                        ----------------------------------------
                                        Notary Public

My commission expires:

11-18-02
----------------------

                                      -4-
<PAGE>
STATE OF MASSACHUSETTS              )
                                    )  ss.
County of Suffolk                   )

     The  foregoing  instrument  was  acknowledged  before  me  this  7th day of
December,  2000, by John Correia,  the Assistant  Vice President of STATE STREET
BANK AND TRUST COMPANY, a Massachusetts  trust company, in its capacity as Owner
Trustee  under  a  Trust   Agreement  with  Security   Pacific  Capital  Leasing
Corporation,  and as Lessor under a Facility  Lease with Arizona  Public Service
Company, on behalf of said association in such capacities.


                                        James M. Coolidge
                                        ----------------------------------------
                                        Notary Public

My commission expires:

June 19, 2003
----------------------



STATE OF MASSACHUSETTS              )
                                    )  ss.
County of Suffolk                   )

     The  foregoing  instrument  was  acknowledged  before  me  this  7th day of
December,  2000, by John Correia,  the Assistant  Vice President of STATE STREET
BANK AND TRUST COMPANY, a Massachusetts  trust company, in its capacity as Owner
Trustee under a Trust  Agreement with Emerson Finance Co., and as Lessor under a
Facility  Lease  with  Arizona  Public  Service  Company,   on  behalf  of  said
association in such capacities.


                                        James M. Coolidge
                                        ----------------------------------------
                                        Notary Public

My commission expires:

June 19, 2003
----------------------

                                      -5-

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.2
<SEQUENCE>5
<FILENAME>ex10-2.txt
<DESCRIPTION>AMENDMENT NO 3 DECOMMISSIONING TRUST AGR UNIT 1
<TEXT>
                                                                    Exhibit 10.2

                                 AMENDMENT NO. 3

                         Decommissioning Trust Agreement
                                 (PVNGS Unit 1)

     This Amendment No. 3 dated as of March 18, 2002, to the Decommissioning
Trust Agreement (PVNGS Unit 1), dated as of July 1, 1991, as amended by
Amendment No. 1 thereto dated as of December 1, 1994 and Amendment No. 2 thereto
dated as of December 16, 1996 (the "Decommissioning Trust Agreement", terms used
herein as therein defined), is entered into between Arizona Public Service
Company ("APS") and Mellon Bank, N.A., as Decommissioning Trustee
("Decommissioning Trustee").

                                R E C I T A L S:

     WHEREAS, the parties hereto wish to amend the Agreement.

     NOW, THEREFORE, in consideration of the premises and of other good and
valuable consideration, receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:

     SECTION 1. Amendment.

     (a)  The period at the end of clause (iii) in Section 8, paragraph (a) is
          deleted and ";or" is added in its place and the following subparagraph
          (iv) shall be added to Section 8, paragraph (a):

               "(iv) in any property safekept or settled outside of the United
               States".

     (b)  The third and fifth sentences of clause (ii) of Paragraph (c) of
          Section 8 shall be restated as follows;

               Upon proper notification from the Investment Manager(s),
               Decommissioning Trustee shall execute and deliver instruments in
               accordance with the appropriate trading authorizations; provided
               that the Trustee shall not follow any direction that would result
               in assets of the Second Fund being invested in assets other than
               those investments permitted for a qualified nuclear
               decommissioning reserve fund under Section 468A of the Code and
               the regulations thereunder.

               Such notification shall be proper authority for Decommissioning
               Trustee to pay for portfolio securities purchased against receipt
               thereof, and to deliver portfolio securities sold against payment
               therefor, as the case may be.

     (c)  Clause (ii) of Paragraph (d) of Section 8 shall be restated as
          follows:

          (ii) Decommissioning Trustee is required to supervise and review the
               securities and other assets and investments authorized for
               purchase by the Investment Managers(s) within two weeks of the
               end of the calendar month during which such purchase was made to
<PAGE>
               determine that such securities, assets and/or investments are
               Permitted Investments and satisfy the further conditions of this
               Agreement as set out in Exhibit B. Upon the completion of such
               review, the Decommissioning Trustee shall promptly notify APS in
               writing if any securities, assets or investments are not
               Permitted Investments or fail to satisfy such further conditions.

     (d)  The following shall be added to Section 11:

               Notwithstanding the foregoing, if the Decommissioning Trustee
               advances cash or securities for any purpose or in the event that
               the Decommissioning Trustee shall incur or be assessed taxes,
               interest, charges, expenses, assessments, or other liabilities in
               connection with the performance of this Agreement, except such as
               may arise from its own negligent action, negligent failure to act
               or willful misconduct, any property at any time held for the
               Funds or under this Agreement shall be security therefor and the
               Decommissioning Trustee shall be entitled to collect from the
               Funds sufficient cash for reimbursement, and if such cash is
               insufficient, dispose of the assets held under this Agreement to
               the extent necessary to obtain reimbursement. To the extent the
               Decommissioning Trustee advances funds to the Funds for
               disbursements or to effect the settlement of purchase
               transactions, the Decommissioning Trustee shall be entitled to
               collect from the Funds an amount equal to what would have been
               earned on the sums advanced (an amount approximating the "federal
               funds" interest rate).

     (e)  The second sentence of the fourth paragraph of Section 21 shall be
          restated as follows:

               Decommissioning Trustee shall promptly advise APS if it has
               actual knowledge that any of the investments do not constitute
               Permitted Investments or otherwise satisfy the further conditions
               of this Agreement.

     (f)  The first sentence of Section 23 shall be restated as follows:

               Decommissioning Trustee shall not be liable for any acts,
               omissions, or defaults of any agent (other than its officers and
               employees), provided such agent was selected with reasonable care
               and the performance and status of such agent is monitored with
               reasonable care.

     (g)  Clause (b) of the second paragraph of Section 23 shall be restated as
          follows:

               (b) any direct damages and any consequential damages permitted
               under Section 28 arising from the violation of the restrictions
               on the investment of Fund assets under this Agreement 1) where
               the decision to invest Fund assets in such investments was made
               by the Decommissioning Trustee, or 2) if not made by the
               Decommissioning Trustee, such damages could have been prevented
               by the Decommissioning Trustee through the exercise of reasonable
               care in the exercise of its duties hereunder, including but not
               limited to its duties of supervision and review under Section 8
               hereof, and/or
<PAGE>
     (h)  The following Section 28 shall be added:

               Section 28: Notwithstanding anything in this Agreement to the
               contrary, the Decommissioning Trustee shall not be responsible or
               liable for its failure to perform under this Agreement or for any
               losses to the Funds resulting from any event beyond the
               reasonable control of the Decommissioning Trustee, its agents or
               subcustodians, including but not limited to nationalization,
               strikes, expropriation, devaluation, seizure, or similar action
               by any governmental authority, de facto or de jure; or enactment,
               promulgation, imposition or enforcement by any such governmental
               authority of currency restrictions, exchange controls, levies or
               other charges affecting the Funds' property; or the breakdown,
               failure or malfunction of any utilities or telecommunications
               systems; or any order or regulation of any banking or securities
               industry including changes in market rules and market conditions
               affecting the execution or settlement of transactions; or acts of
               war, terrorism, insurrection or revolution; or acts of God; or
               any other similar event. The Decommissioning Trustee shall not be
               liable for any indirect, consequential, or special damages with
               respect to its role as Decommissioning Trustee to the extent such
               damages exceed the Trustee's annual compensation under this
               Agreement for the previous calendar year. This Section shall
               survive the termination of this Agreement.

     (i)  EXHIBIT B to the Decommissioning Trust Agreement is hereby deleted and
          replaced in its entirety by EXHIBIT B hereto.

     SECTION 2. Miscellaneous

          (a)  Full Force and Effect.

     Except as expressly provided herein, the Decommissioning Trust Agreement
shall remain unchanged and in full force and effect. Each reference in the
Decommissioning Trust Agreement and in any exhibit or schedule thereto to `this
Agreement," "hereto," "hereof" and terms of similar import shall be deemed to
refer to the Decommissioning Trust Agreement as amended hereby.

          (b)  Counterparts/Representations.

     The Amendment No. 3 may be executed in any number of counterparts, all of
which taken together shall constitute one and the same instrument, and any of
the parties hereto may execute this Amendment No. 3 by signing any such
counterpart. Each party represents and warrants to the other that it has full
authority to enter into this Amendment upon the terms and conditions hereof and
that the individual executing this Amendment on its behalf has the requisite
authority to bind that Party.
<PAGE>
     IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 3 to
the Decommissioning Trust Agreement to be duly executed as of the day and year
first above written.


                                        ARIZONA PUBLIC SERVICE COMPANY


                                        By Barbara M. Gomez
                                           -------------------------------------

                                        Title Treasurer
                                              ----------------------------------


                                        MELLON BANK, N.A. as
                                        Decommissioning Trustee


                                        By Robert F. Sass
                                           -------------------------------------

                                        Title Vice President
                                              ----------------------------------
<PAGE>
STATE OF ARIZONA           )
                           )  ss:
County of Maricopa         )


     The foregoing instrument was acknowledged before me this 20th day of March,
2002, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an
Arizona corporation, on behalf of said corporation.


                                        Suzanne W. Debes
                                        ----------------------------------------
                                        Notary Public


My commission expires:

June 20, 2003
----------------------



COMMONWEALTH OF PENNSYLVANIA        )
                                    )  ss:
County of Allegheny                 )


     The foregoing instrument was acknowledged before me this 28th day of March,
2002, by Robert F. Sass, a Vice President of Mellon Bank, N.A. a national
banking association having trust powers, as Decommissioning Trustee, on behalf
of said national banking association.


                                        Julie Ann Mosco
                                        ----------------------------------------
                                        Notary Public


My commission expires:

October 13, 2003
----------------------
<PAGE>
                                    EXHIBIT B
                                     UNIT 1

                          PERMITTED INVESTMENTS FOR THE
                 DECOMMISSIONING TRUST FUND AND THE SECOND FUND


     The Second Fund must meet all applicable requirements of the Code, and
applicable rules and regulations promulgated by the Internal Revenue Service
with respect to a Nuclear Decommissioning Reserve Fund.

     Subject to the foregoing, the Decommissioning Trust Fund and the Second
Fund may invest in any of the following:

SECURITIES

     Except as may be constrained elsewhere in these guidelines, the following
types of taxable or tax-exempt securities are eligible for investment, including
any investment in a common or collective trust fund (including but not limited
to, any such fund maintained by the Decommissioning Trustee or any of its
affiliates, including but not limited to, the Decommissioning Trustee's Nuclear
Decommissioning Trust Equity Index Fund) holding any securities listed in items
1 through 3 below:

     1.   Debt Obligations of

          -    The U.S. Government and its agencies or instrumentalities

          -    States, U.S. possessions, District of Columbia, and any agency or
               political subdivision thereof

          -    Domestic corporations

          -    Municipalities and municipal agencies

     2.   Asset-backed and mortgage-backed securities

     3.   Equities

     4.   FDIC Certificates of Deposit, including but not limited to, those of
          the Decommissioning Trustee or any of its affiliates

     5.   Shares of regulated investment companies, including but not limited
          to, mutual funds, including but not limited to, those for which the
          Decommissioning Trustee performs advisory management or other services
          for a fee
<PAGE>
     6.   Cash equivalent securities, including but not limited to, the
          Decommissioning Trustee's STIF accounts or those of any of its
          affiliates

QUALITY

     1.   Debt obligations other than U.S. Government and agency securities must
          have a rating of at least A by both Moody's Investors Services, Inc.
          ("Moody's") and Standard & Poor's Ratings Group ("S & P") at time of
          purchase. This limitation shall not apply to securities that have been
          pre-refunded where a third party trustee holds direct U.S. Government
          or agency obligations sufficient to pay debt service and the specified
          call price to a specific call or maturity date.

     2.   Commercial paper must be rated at least A-1 by S&P and P-1 by Moody's.

     3.   Certificates of Deposit must be at a bank with a minimum of one
          billion dollars in assets as of such bank's most recent report of
          condition.

DIVERSIFICATION

No investment shall represent more than 10% of the aggregate assets held under
this Decommissioning Trust Agreement, the Unit 2 Trust Agreement, and the Unit 3
Trust Agreement combined, except for:

     1.   Positions in securities issued by the U.S. Government or fully
          government backed securities or instruments fully pre-refunded where a
          third party trustee holds direct U.S. Government or agency obligations
          sufficient to pay debt service and the specified call price to a
          specific call or maturity date.

     2.   Units of a common or collective trust fund.

Equity securities are limited to 60% of the aggregate assets held under this
Decommissioning Trust Agreement, the Unit 2 Trust Agreement, and the Unit 3
Trust Agreement combined.

     Notwithstanding the foregoing, the following restrictions are placed on the
investment of the assets of the Funds:

     1.   Securities of APS, APS' parent corporation, Pinnacle West Capital
          Corporation, or its affiliates, are not permitted.

     2.   Securities issued by Maricopa County, Arizona Pollution Control
          Corporation in connection with the financing of certain facilities at
          the Palo Verde Nuclear Generation Station are not permitted.
<PAGE>
     3.   Securities issued by or on behalf of any participant in the Palo Verde
          Nuclear Generating Station are not permitted.

     4.   Investments in any bank, savings and loan association, or other
          financial institution whose deposits are not insured by the Federal
          Deposit Insurance Corporation or other comparable federal agency are
          not permitted, except that this restriction does not apply to
          investments in the Decommissioning Trustee's STIF.

     5.   Property that is settled or safekept outside of the United States is
          not permitted.

     6.   The following securities and transactions are explicitly prohibited
          unless engaged in in the ordinary course by a common or collective
          trust fund described under the heading "Securities" above:

          (a)  put and call options on securities, securities indices and
               foreign currencies;

          (b)  financial futures contracts including bond, bond index, foreign
               currency futures contracts and options thereon;

          (c)  spot and forward currency transactions both to effect securities
               transactions and to manage currency;

          (d)  private placements;

          (e)  preferred stock;

          (f)  warrants;

          (g)  margin purchases or borrowing money; and

          (h)  short selling or securities lending.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.3
<SEQUENCE>6
<FILENAME>ex10-3.txt
<DESCRIPTION>AMENDMENT NO 6 DECOMMISSIONING TRUST AGR UNIT 2
<TEXT>
                                                                    Exhibit 10.3


                                 AMENDMENT NO. 6

                         Decommissioning Trust Agreement
                                 (PVNGS Unit 2)

     This Amendment No. 6 dated as of March 18, 2002, to the Amended and
Restated Decommissioning Trust Agreement (PVNGS Unit 2), dated as of January 31,
1992, as amended by Amendment No. 1 thereto dated as of November 1, 1992,
Amendment No. 2 thereto dated as of November 1, 1994, Amendment No. 3 thereto
dated as of June 20, 1996, Amendment No. 4 thereto dated as of December 16,
1996, and Amendment No. 5 thereto dated as of June 30, 2000 (the
"Decommissioning Trust Agreement", terms used herein as therein defined), is
entered into between Arizona Public Service Company ("APS"), State Street Bank
and Trust Company, as successor to The First National Bank of Boston, as Owner
Trustee and as Lessor, and Mellon Bank, N.A., as Decommissioning Trustee
("Decommissioning Trustee").

                                    RECITALS:

          WHEREAS, the parties hereto wish to amend the Agreement.

     NOW, THEREFORE, in consideration of the premises and of other good and
valuable consideration, receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:

     SECTION 1. Amendment.

     (a)  The third and fifth sentences of clause (ii) of Paragraph (c) of
          Section 9 shall be restated as follows;

               Upon proper notification from the Investment Manager(s),
               Decommissioning Trustee shall execute and deliver instruments in
               accordance with the appropriate trading authorizations; provided
               that the Trustee shall not follow any direction that would result
               in assets of the Second Fund being invested in assets other than
               those investments permitted for a qualified nuclear
               decommissioning reserve fund under Section 468A of the Code and
               the regulations thereunder.

               Such notification shall be proper authority for Decommissioning
               Trustee to pay for portfolio securities purchased against receipt
               thereof, and to deliver portfolio securities sold against payment
               therefor, as the case may be.

     (b)  Clause (ii) of Paragraph (d) of Section 9 shall be restated as
          follows:

          (ii) Decommissioning Trustee is required to supervise and review the
               securities and other assets and investments authorized for
               purchase by the Investment Managers(s) within two weeks of the
               end of the calendar month during which such purchase was made to
               determine that such securities, assets and/or investments are
               Permitted Investments and satisfy the further conditions of this
               Agreement as set out in Exhibit B. Upon the completion of such
               review, the Decommissioning Trustee shall promptly notify APS and
               the Secured Parties and Equity Participants in writing if any
<PAGE>
               securities, assets or investments are not Permitted Investments
               or fail to satisfy such further conditions.

     (c)  The second sentence of the fourth paragraph of Section 24 shall be
          restated as follows:

               Within two weeks of the end of each calendar quarter, the
               Decommissioning Trustee shall send a written statement to APS and
               the Secured Parties and Equity Participants indicating whether
               during that previous quarter such securities, assets and/or
               investments held in the Funds during that quarter were Permitted
               Investments and satisfied the further conditions of this
               Agreement; provided however, the Decommissioning Trustee shall
               promptly advise APS and the Secured Parties and Equity
               Participants if it has actual knowledge that any of the
               investments do not constitute Permitted Investments or otherwise
               satisfy the further conditions of this Agreement.

     (d)  The words "any such consequences" shall be added after the words "as
          provided in this Agreement or" and before the words "could have been
          prevented" in clause (b) of the first sentence of the second paragraph
          of Section 26.

     (e)  The following Section 33 shall be added:

               Section 33: Notwithstanding anything in this Agreement to the
               contrary, the Decommissioning Trustee shall not be responsible or
               liable for its failure to perform under this Agreement or for any
               losses to the Funds resulting from any event beyond the
               reasonable control of the Decommissioning Trustee, its agents or
               subcustodians, including but not limited to nationalization,
               strikes, expropriation, devaluation, seizure, or similar action
               by any governmental authority, de facto or de jure; or enactment,
               promulgation, imposition or enforcement by any such governmental
               authority of currency restrictions, exchange controls, levies or
               other charges affecting the Funds' property; or the breakdown,
               failure or malfunction of any utilities or telecommunications
               systems; or any order or regulation of any banking or securities
               industry including changes in market rules and market conditions
               affecting the execution or settlement of transactions; or acts of
               war, terrorism, insurrection or revolution; or acts of God; or
               any other similar event. The Decommissioning Trustee shall not be
               liable for any indirect, consequential, or special damages with
               respect to its role as Decommissioning Trustee to the extent such
               damages exceed the Trustee's annual compensation under this
               Agreement for the previous calendar year. This Section shall
               survive the termination of this Agreement.

     (f)  EXHIBIT B to the Decommissioning Trust Agreement is hereby deleted and
          replaced in its entirety by EXHIBIT B hereto.
<PAGE>
     SECTION 2. Miscellaneous

     (a)  Full Force and Effect.

     Except as expressly provided herein, the Decommissioning Trust Agreement
shall remain unchanged and in full force and effect. Each reference in the
Decommissioning Trust Agreement and in any exhibit or schedule thereto to "this
Agreement," "hereto," "hereof" and terms of similar import shall be deemed to
refer to the Decommissioning Trust Agreement as amended hereby.

     (b)  Counterparts/Representations.

     The Amendment No. 6 may be executed in any number of counterparts, all of
which taken together shall constitute one and the same instrument, and any of
the parties hereto may execute this Amendment No. 6 by signing any such
counterpart. Each party represents and warrants to the other that it has full
authority to enter into this Amendment upon the terms and conditions hereof and
that the individual executing this Amendment on its behalf has the requisite
authority to bind that Party.


     IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 6 to
the Decommissioning Trust Agreement to be duly executed as of the day and year
first above written.


                                        ARIZONA PUBLIC SERVICE COMPANY


                                        By Barbara M. Gomez
                                           -------------------------------------

                                        Title Treasurer
                                              ----------------------------------
<PAGE>
                                        MELLON BANK, N.A. as
                                        Decommissioning Trustee


                                        By Robert F. Sass
                                           -------------------------------------

                                        Title Vice President
                                              ----------------------------------


                                        STATE STREET BANK AND TRUST COMPANY, as
                                        Owner Trustee under a Trust Agreement
                                        with Security Pacific Capital Leasing
                                        Corporation and as Lessor under a
                                        Facility Lease with Arizona Public
                                        Service Company


                                        By Kenneth R. Ring
                                           -------------------------------------

                                        Title Assistant Vice President
                                              ----------------------------------


                                        STATE STREET BANK AND TRUST COMPANY, as
                                        Owner Trustee under a Trust Agreement
                                        with Emerson Finance Co. and as Lessor
                                        under a Facility Lease with Arizona
                                        Public Service Company


                                        By Kenneth R. Ring
                                           -------------------------------------

                                        Title Assistant Vice President
                                              ----------------------------------
<PAGE>
STATE OF ARIZONA                  )
                                  )  ss:
County of Maricopa                )


     The foregoing instrument was acknowledged before me this 20th day of March,
2002, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an
Arizona corporation, on behalf of said corporation.


                                        Suzanne W. Debes
                                        ----------------------------------------
                                        Notary Public


My commission expires:

June 20, 2003
----------------------



COMMONWEALTH OF PENNSYLVANIA       )
                                   ) ss:
County of Allegheny                )


     The foregoing instrument was acknowledged before me this 28th day of March,
2002, by Robert F. Sass, a Vice President of Mellon Bank, N.A. a national
banking association having trust powers, as Decommissioning Trustee, on behalf
of said national banking association.


                                        Julie Ann Mosco
                                        ----------------------------------------
                                        Notary Public


My commission expires:

October 13, 2003
----------------------
<PAGE>
COMMONWEALTH OF MASSACHUSETTS      )
                                   ) ss:
County of Suffolk                  )


     The foregoing instrument was acknowledged before me this 18th day of March,
2002, by Kenneth R. Ring, an Assistant Vice President of State Street Bank and
Trust Company, a Massachusetts trust company, in its capacity as Owner Trustee
under a Trust Agreement with Security Pacific Capital Leasing Corporation and as
Lessor under a Facility Lease with Arizona Public Service Company, on behalf of
said association in such capacities.


                                        James M. Coolidge
                                        ----------------------------------------
                                        Notary Public


My commission expires:

June 19, 2003
----------------------



COMMONWEALTH OF MASSACHUSETTS      )
                                   ) ss:
County of Suffolk                  )


     The foregoing instrument was acknowledged before me this 18th day of March,
2002, by Kenneth R. Ring, an Assistant Vice President of State Street Bank and
Trust Company, a Massachusetts trust company, in its capacity as Owner Trustee
under a Trust Agreement with Emerson Finance Company and as Lessor under a
Facility Lease with Arizona Public Service Company, on behalf of said
association in such capacities.


                                        James M. Coolidge
                                        ----------------------------------------
                                        Notary Public


My commission expires:

June 19, 2003
----------------------
<PAGE>
                                    EXHIBIT B
                                     UNIT 2

                          PERMITTED INVESTMENTS FOR THE
                 DECOMMISSIONING TRUST FUND AND THE SECOND FUND


     The Second Fund must meet all applicable requirements of the Code, and
applicable rules and regulations promulgated by the Internal Revenue Service
with respect to a Nuclear Decommissioning Reserve Fund.

     Subject to the foregoing, the Decommissioning Trust Fund and the Second
Fund may invest in any of the following obligations or securities maturing at
such time or times as to enable payments or transfers to be made from the Funds
or which shall be readily marketable prior to the final maturity thereof:

     (a) bills, notes, bonds and savings bonds of the Treasury of the United
States of America;

     (b) obligations of the United States of America not included in clause (a)
taken into consideration for purposes of determining the public debt limit of
the United States of America;

     (c) time or demand deposits in a bank (as defined in Section 581 of the
Code) or an insured credit union (within the meaning of Section 101(6) of the
Federal Credit Union Act, 12 U.S.C. 1752(7) (1982)) (for the purposes of this
paragraph, "time or demand deposits" shall include checking accounts, savings
accounts, certificates of deposit, and other time or demand deposits but shall
not include common or collective trust funds);

     (d) obligations of the Federal National Mortgage Association and Government
National Mortgage Association;

     (e) AAA rated collateralized mortgage obligations; interest only, principal
only, and inverse floaters are specifically prohibited;

     (f) commercial paper maturing within 60 days and rated the highest grade by
Moody's Investor's Services, Inc. ("Moody's") or Standard & Poor's Corporation
("S & P") or if one of such agencies does not rate such paper, rated the highest
grade by the other;

     (g) deposit accounts (which may be represented by certificates of deposit)
payable on demand or maturing within 180 days, in Federally insured national or
state banks; provided, however, if the aggregate amount of such deposit accounts
in a bank is $100,000 or more, such bank shall have combined capital and surplus
as of its last report of condition exceeding $250,000,000 and a senior unsecured
debt rating of Investment Grade;
<PAGE>
     (h) The Decommissioning Trustee's Short Term Investment Fund ("STIF")
account; provided, however, that no more than fifteen percent (15%) of the
aggregate assets of the Funds may be invested in the Decommissioning Trustee's
STIF account at any one time, except that the full amount of APS' quarterly
contribution to the Funds or any portion thereof may be invested in the
Decommissioning Trustee's STIF account for a period of up to seven (7) business
days after such contribution is made and, during such period, the amount of such
contribution or portion thereof that shall have been so invested shall not count
against the fifteen percent (15%) limitation in this paragraph (h):

     (i) repurchase agreements fully secured (and perfected) by any of the
foregoing obligations or securities maturing within 30 days with any Federally
insured national or state bank (including Decommissioning Trustee) or any other
financial institution that is a nationally recognized dealer that reports to the
Market Reports Division of the Federal Reserve Bank of New York; provided,
however, if the aggregate face amount of such repurchase agreements with an
issuer is $1,000,000 or more, the issuer shall have combined capital and surplus
as of its last report of condition exceeding $250,000,000 and a senior unsecured
debt rating of Investment Grade;

     (j) obligations rated Investment Grade of a State, a possession of the
United States of America, the District of Columbia or any political subdivision
of the foregoing, the interest on which is exempt from tax under Section 103(a)
of the Code;

     (k) corporate debt obligations rated Investment Grade; and

     (l) (x) corporate equity securities, including, but not limited to,
investment in units of common or collective trust funds investing in corporate
equity securities; including, but not limited to, the Decommissioning Trustee's
Nuclear Decommissioning Trust Equity Index Fund (the "NDT Equity Index Fund")
and (y) obligations not included in clauses (a) through (k) issued or guaranteed
by a person controlled or supervised by and acting as an instrumentality of the
United States of America pursuant to authority granted by the Congress of the
United States of America, including Federal Intermediate Credit Bank, Banks for
Cooperatives, Federal Land Banks, Federal Home Loan Banks, Federal Home Loan
Mortgage Corporation; provided, that no more than fifty percent (50%) of the
aggregate assets of the Funds may be invested in securities described in (x) and
(y) of this subparagraph (1) during the period from June 27, 1996 through
December 31, 2003, no more than thirty percent (30%) during the period from
January 1, 2004 through December 31, 2006, and no more than fifteen percent
(15%) during the period from January 1, 2007 through January 31, 2010; and
provided further that after January 31, 2010, no investments shall be made in
such securities.

     Notwithstanding the foregoing, the following restrictions are placed on the
investment of the assets of the Funds:

     1. Securities of APS, APS' parent corporation, Pinnacle West Capital
Corporation, or its affiliates, are not permitted.
<PAGE>
     2. Securities issued by Maricopa County, Arizona Pollution Control
Corporation in connection with the financing of certain facilities at the Palo
Verde Nuclear Generation Station are not permitted.

     3. Securities issued by or on behalf of any participant in the Palo Verde
Nuclear Generating Station are not permitted.

     4. Investments in any bank or other financial institution whose deposits
are not insured by the Federal Deposit Insurance Corporation or other comparable
federal agency are not permitted, except that this restriction does not apply to
investments in the Decommissioning Trustee's STIF.

     5. There shall be no short-selling, securities lending, options trading,
financial futures, over-the-counter derivative transactions, or other
specialized investment activity, except as specifically allowed in paragraphs
(a) through (1) hereof, or except as may be effected in the ordinary course of
operation of the Decommissioning Trustee's STIF account or its NDT Equity Index
Fund.

     6. No investment shall be made which would cause the holding of any one
issue (excluding obligations of the United States Government and agencies of or
guaranteed by the United States Government and excluding units of a common or
collective trust fund), to exceed ten percent (10%) of the aggregate assets held
under this Decommissioning Trust Agreement, the Unit 1 Trust Agreement, and the
Unit 3 Trust Agreement, valued at cost.

     7. Bank certificates of deposit must be at banks with a minimum of one
billion ($1,000,000,000) in assets as of such banks' most recent report of
condition.

     8. Short-term taxable and non-taxable debt securities are not permitted
unless such securities have a rating of at least P-1 by Moody's or at least A-1
by S&P.

     9. Long-term taxable and non-taxable debt securities are not permitted
unless such securities have a rating of at least "A" by Moody's or S&P.

     10. No investment shall be made which would cause sixty percent (60%) or
more of the aggregate assets held under this Decommissioning Trust Agreement and
the Unit 1 Trust Agreement and the Unit 3 Trust Agreement to be invested in
equity securities.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.4
<SEQUENCE>7
<FILENAME>ex10-4.txt
<DESCRIPTION>AMENDMENT NO 3 DECOMMISSIONING TRUST AGR UNIT 3
<TEXT>
                                                                    Exhibit 10.4


                                 AMENDMENT NO. 3

                         Decommissioning Trust Agreement
                                 (PVNGS Unit 3)


     This Amendment No. 3 dated as of March 18, 2002, to the Decommissioning
Trust Agreement (PVNGS Unit 3), dated as of July 1, 1991, as amended by
Amendment No. 1 thereto dated as of December 1, 1994 and Amendment No. 2 thereto
dated as of December 16, 1996 (the "Decommissioning Trust Agreement", terms used
herein as therein defined), is entered into between Arizona Public Service
Company ("APS") and Mellon Bank, N.A., as Decommissioning Trustee
("Decommissioning Trustee").

                                    RECITALS:

     WHEREAS, the parties hereto wish to amend the Agreement.

     NOW, THEREFORE, in consideration of the premises and of other good and
valuable consideration, receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:

     SECTION 1. Amendment.

     (a)  The period at the end of clause (iii) in Section 8, paragraph (a) is
          deleted and ";or" is added in its place and the following subparagraph
          (iv) shall be added to Section 8, paragraph (a):

               "(iv) in any property safekept or settled outside of the United
               States".

     (b)  The third and fifth sentences of clause (ii) of Paragraph (c) of
          Section 8 shall be restated as follows;

               Upon proper notification from the Investment Manager(s),
               Decommissioning Trustee shall execute and deliver instruments in
               accordance with the appropriate trading authorizations; provided
               that the Trustee shall not follow any direction that would result
               in assets of the Second Fund being invested in assets other than
               those investments permitted for a qualified nuclear
               decommissioning reserve fund under Section 468A of the Code and
               the regulations thereunder.

               Such notification shall be proper authority for Decommissioning
               Trustee to pay for portfolio securities purchased against receipt
               thereof, and to deliver portfolio securities sold against payment
               therefor, as the case may be.

     (c)  Clause (ii) of Paragraph (d) of Section 8 shall be restated as
          follows:

          (ii) Decommissioning Trustee is required to supervise and review the
               securities and other assets and investments authorized for
               purchase by the Investment Managers(s) within two weeks of the
               end of the calendar month during which such purchase was made to
               determine that such securities, assets and/or investments are
<PAGE>
               Permitted Investments and satisfy the further conditions of this
               Agreement as set out in Exhibit B. Upon the completion of such
               review, the Decommissioning Trustee shall promptly notify APS in
               writing if any securities, assets or investments are not
               Permitted Investments or fail to satisfy such further conditions.

     (d)  The following shall be added to Section 11:

               Notwithstanding the foregoing, if the Decommissioning Trustee
               advances cash or securities for any purpose or in the event that
               the Decommissioning Trustee shall incur or be assessed taxes,
               interest, charges, expenses, assessments, or other liabilities in
               connection with the performance of this Agreement, except such as
               may arise from its own negligent action, negligent failure to act
               or willful misconduct, any property at any time held for the
               Funds or under this Agreement shall be security therefor and the
               Decommissioning Trustee shall be entitled to collect from the
               Funds sufficient cash for reimbursement, and if such cash is
               insufficient, dispose of the assets held under this Agreement to
               the extent necessary to obtain reimbursement. To the extent the
               Decommissioning Trustee advances funds to the Funds for
               disbursements or to effect the settlement of purchase
               transactions, the Decommissioning Trustee shall be entitled to
               collect from the Funds an amount equal to what would have been
               earned on the sums advanced (an amount approximating the "federal
               funds" interest rate).

     (e)  The second sentence of the fourth paragraph of Section 21 shall be
          restated as follows:

               Decommissioning Trustee shall promptly advise APS if it has
               actual knowledge that any of the investments do not constitute
               Permitted Investments or otherwise satisfy the further conditions
               of this Agreement.

     (f)  The first sentence of Section 23 shall be restated as follows:

               Decommissioning Trustee shall not be liable for any acts,
               omissions, or defaults of any agent (other than its officers and
               employees), provided such agent was selected with reasonable care
               and the performance and status of such agent is monitored with
               reasonable care.

     (g)  Clause (b) of the second paragraph of Section 23 shall be restated as
          follows:

               (b) any direct damages and any consequential damages permitted
               under Section 28 arising from the violation of the restrictions
               on the investment of Fund assets under this Agreement 1) where
               the decision to invest Fund assets in such investments was made
               by the Decommissioning Trustee, or 2) if not made by the
               Decommissioning Trustee, such damages could have been prevented
               by the Decommissioning Trust through the exercise of reasonable
               care in the exercise of its duties hereunder, including but not
               limited to its duties of supervision and review under Section 8
               hereof, and/or

     (h)  The following Section 28 shall be added:

               Section 28: Notwithstanding anything in this Agreement to the
               contrary, the Decommissioning Trustee shall not be responsible or
<PAGE>
               liable for its failure to perform under this Agreement or for any
               losses to the Funds resulting from any event beyond the
               reasonable control of the Decommissioning Trustee, its agents or
               subcustodians, including but not limited to nationalization,
               strikes, expropriation, devaluation, seizure, or similar action
               by any governmental authority, de facto or de jure; or enactment,
               promulgation, imposition or enforcement by any such governmental
               authority of currency restrictions, exchange controls, levies or
               other charges affecting the Funds' property; or the breakdown,
               failure or malfunction of any utilities or telecommunications
               systems; or any order or regulation of any banking or securities
               industry including changes in market rules and market conditions
               affecting the execution or settlement of transactions; or acts of
               war, terrorism, insurrection or revolution; or acts of God; or
               any other similar event. The Decommissioning Trustee shall not be
               liable for any indirect, consequential, or special damages with
               respect to its role as Decommissioning Trustee to the extent such
               damages exceed the Trustee's annual compensation under this
               Agreement for the previous calendar year. This Section shall
               survive the termination of this Agreement.

     (i)  EXHIBIT B to the Decommissioning Trust Agreement is hereby deleted and
          replaced in its entirety by EXHIBIT B hereto.

     SECTION 2. Miscellaneous

     (a)  Full Force and Effect.

     Except as expressly provided herein, the Decommissioning Trust Agreement
shall remain unchanged and in full force and effect. Each reference in the
Decommissioning Trust Agreement and in any exhibit or schedule thereto to "this
Agreement," "hereto," "hereof" and terms of similar import shall be deemed to
refer to the Decommissioning Trust Agreement as amended hereby.

     (b)  Counterparts/Representations.

     The Amendment No. 3 may be executed in any number of counterparts, all of
which taken together shall constitute one and the same instrument, and any of
the parties hereto may execute this Amendment No. 3 by signing any such
counterpart. Each party represents and warrants to the other that it has full
authority to enter into this Amendment upon the terms and conditions hereof and
that the individual executing this Amendment on its behalf has the requisite
authority to bind that Party.


     IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 3 to
the Decommissioning Trust Agreement to be duly executed as of the day and year
first above written.


                                        ARIZONA PUBLIC SERVICE COMPANY


                                        By Barbara M. Gomez
                                           -------------------------------------

                                        Title Treasurer
                                              ----------------------------------


                                        MELLON BANK, N.A. as
                                        Decommissioning Trustee


                                        By Robert F. Sass
                                           -------------------------------------

                                        Title Vice President
                                              ----------------------------------
<PAGE>
STATE OF ARIZONA                   )
                                   ) ss:
County of Maricopa                 )


     The foregoing instrument was acknowledged before me this 20th day of March,
2002, by Barbara M. Gomez, the Treasurer of ARIZONA PUBLIC SERVICE COMPANY, an
Arizona corporation, on behalf of said corporation.


                                        Suzanne W. Debes
                                        ----------------------------------------
                                        Notary Public


My commission expires:

June 20, 2003
----------------------



COMMONWEALTH OF PENNSYLVANIA       )
                                   ) ss:
County of Allegheny                )


     The foregoing instrument was acknowledged before me this 28th day of March,
2002, by Robert F. Sass, a Vice President of Mellon Bank, N.A. a national
banking association having trust powers, as Decommissioning Trustee, on behalf
of said national banking association.


                                        Julie Ann Mosco
                                        ----------------------------------------
                                        Notary Public


My commission expires:

October 13, 2003
----------------------
<PAGE>
                                    EXHIBIT B
                                     UNIT 3

                          PERMITTED INVESTMENTS FOR THE
                 DECOMMISSIONING TRUST FUND AND THE SECOND FUND


     The Second Fund must meet all applicable requirements of the Code, and
applicable rules and regulations promulgated by the Internal Revenue Service
with respect to a Nuclear Decommissioning Reserve Fund.

     Subject to the foregoing, the Decommissioning Trust Fund and the Second
Fund may invest in any of the following:

SECURITIES

     Except as may be constrained elsewhere in these guidelines, the following
types of taxable or tax-exempt securities are eligible for investment, including
any investment in a common or collective trust fund (including but not limited
to, any such fund maintained by the Decommissioning Trustee or any of its
affiliates, including but not limited to, the Decommissioning Trustee's Nuclear
Decommissioning Trust Equity Index Fund) holding any securities listed in items
1 through 3 below:

     1.   Debt Obligations of

          -    The U.S. Government and its agencies or instrumentalities

          -    States, U.S. possessions, District of Columbia, and any agency or
               political subdivision thereof

          -    Domestic corporations

          -    Municipalities and municipal agencies

     2.   Asset-backed and mortgage-backed securities

     3.   Equities

     4.   FDIC Certificates of Deposit, including but not limited to, those of
          the Decommissioning Trustee or any of its affiliates

     5.   Shares of regulated investment companies, including but not limited
          to, mutual funds, including but not limited to, those for which the
          Decommissioning Trustee performs advisory management or other services
          for a fee
<PAGE>
     6.   Cash equivalent securities, including but not limited to, the
          Decommissioning Trustee's STIF accounts or those of any of its
          affiliates

QUALITY

     1.   Debt obligations other than U.S. Government and agency securities must
          have a rating of at least A by both Moody's Investors Services, Inc.
          ("Moody's") and Standard & Poor's Ratings Group ("S & P") at time of
          purchase. This limitation shall not apply to securities that have been
          pre-refunded where a third party trustee holds direct U.S. Government
          or agency obligations sufficient to pay debt service and the specified
          call price to a specific call or maturity date.

     2.   Commercial paper must be rated at least A-1 by S&P and P-1 by Moody's.

     3.   Certificates of Deposit must be at a bank with a minimum of one
          billion dollars in assets as of such bank's most recent report of
          condition.

DIVERSIFICATION

No investment shall represent more than 10% of the aggregate assets held under
this Decommissioning Trust Agreement, the Unit 2 Trust Agreement, and the Unit 1
Trust Agreement combined, except for:

     1.   Positions in securities issued by the U.S. Government or fully
          government backed securities or instruments fully pre-refunded where a
          third party trustee holds direct U.S. Government or agency obligations
          sufficient to pay debt service and the specified call price to a
          specific call or maturity date.

     2.   Units of a common or collective trust fund.

Equity securities are limited to 60% of the aggregate assets held under this
Decommissioning Trust Agreement, the Unit 2 Trust Agreement, and the Unit 1
Trust Agreement combined.

     Notwithstanding the foregoing, the following restrictions are placed on the
investment of the assets of the Funds:

     1.   Securities of APS, APS' parent corporation, Pinnacle West Capital
          Corporation, or its affiliates, are not permitted.

     2.   Securities issued by Maricopa County, Arizona Pollution Control
          Corporation in connection with the financing of certain facilities at
          the Palo Verde Nuclear Generation Station are not permitted.
<PAGE>
     3.   Securities issued by or on behalf of any participant in the Palo Verde
          Nuclear Generating Station are not permitted.

     4.   Investments in any bank, savings and loan association, or other
          financial institution whose deposits are not insured by the Federal
          Deposit Insurance Corporation or other comparable federal agency are
          not permitted, except that this restriction does not apply to
          investments in the Decommissioning Trustee's STIF.

     5.   Property that is settled or safekept outside of the United States is
          not permitted.

     6.   The following securities and transactions are explicitly prohibited
          unless engaged in in the ordinary course by a common or collective
          trust fund described under the heading "Securities" above:

          (a)  put and call options on securities, securities indices and
               foreign currencies;

          (b)  financial futures contracts including bond, bond index, foreign
               currency futures contracts and options thereon;

          (c)  spot and forward currency transactions both to effect securities
               transactions and to manage currency;

          (d)  private placements;

          (e)  preferred stock;

          (f)  warrants;

          (g)  margin purchases or borrowing money; and

          (h)  short selling or securities lending.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12.1
<SEQUENCE>8
<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
                                    ($000's)

<TABLE>
<CAPTION>
                                                     THREE
                                                     MONTHS
                                                     ENDED
                                                    3/31/02       2001        2000        1999        1998        1997
                                                    --------    --------    --------    --------    --------    --------
<S>                                                 <C>         <C>         <C>         <C>         <C>         <C>
Income From Continuing Operations                   $ 53,757    $327,367    $302,332    $269,772    $242,892    $235,856
Income Taxes                                          35,228     213,535     194,200     141,592     138,589     126,943
Fixed Charges                                         52,802     211,958     202,804     194,070     201,184     215,201
                                                    --------    --------    --------    --------    --------    --------
    Total                                           $141,787    $752,860    $699,336    $605,434    $582,665    $578,000

Fixed Charges:
  Interest Expense                                  $ 44,688    $175,822    $166,447    $157,142    $163,975    $177,383
  Estimated Interest Portion of Annual Rents           8,114      36,136      36,357      36,928      37,209      37,818
                                                    --------    --------    --------    --------    --------    --------
    Total Fixed Charges                             $ 52,802    $211,958    $202,804    $194,070    $201,184    $215,201

Ratio of Earnings to Fixed Charges (rounded down)       2.68        3.55        3.44        3.11        2.89        2.68
                                                    ========    ========    ========    ========    ========    ========
</TABLE>

</TEXT>
</DOCUMENT>
</SUBMISSION>
