<SUBMISSION>
<ACCESSION-NUMBER>0000950147-00-500096
<TYPE>10-Q
<PUBLIC-DOCUMENT-COUNT>3
<PERIOD>20000930
<FILING-DATE>20001114
<FILER>
<COMPANY-DATA>
<CONFORMED-NAME>PINNACLE WEST CAPITAL CORP
<CIK>0000764622
<ASSIGNED-SIC>4911
<IRS-NUMBER>860512431
<STATE-OF-INCORPORATION>AZ
<FISCAL-YEAR-END>1231
</COMPANY-DATA>
<FILING-VALUES>
<FORM-TYPE>10-Q
<ACT>34
<FILE-NUMBER>001-08962
<FILM-NUMBER>766379
</FILING-VALUES>
<BUSINESS-ADDRESS>
<STREET1>400 E VAN BUREN ST PO BOX 52132
<STREET2>P O BOX 52132
<CITY>PHOENIX
<STATE>AZ
<ZIP>85072-2132
<PHONE>6023792616
</BUSINESS-ADDRESS>
<MAIL-ADDRESS>
<STREET1>400 E VAN BUREN ST
<STREET2>PO BOX 52132
<CITY>PHOENIX
<STATE>AZ
<ZIP>85072-2132
</MAIL-ADDRESS>
<FORMER-COMPANY>
<FORMER-CONFORMED-NAME>AZP GROUP INC
<DATE-CHANGED>19870506
</FORMER-COMPANY>
</FILER>
<DOCUMENT>
<TYPE>10-Q
<SEQUENCE>1
<FILENAME>e-5680.txt
<DESCRIPTION>QUARTERLY REPORT FOR THE QTR ENDED 9/30/00
<TEXT>

                                    FORM 10-Q
                       Securities and Exchange Commission
                             Washington, D.C. 20549

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

     For the quarterly period ended September 30, 2000

                                       OR

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

     For the transition period from _________________ to ________________

     Commission file number 1-8962

                        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 E. Van Buren St., P.O. Box 52132, Phoenix, Arizona            85072-2132
------------------------------------------------------            ----------
      (Address of principal executive offices)                    (Zip Code)

       Registrant's telephone number, including area code: (602) 379-2500

              ----------------------------------------------------
              (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 November 10, 2000: 84,710,644
<PAGE>
                                    Glossary

ACC - Arizona Corporation Commission

ACC Staff - Staff of the Arizona Corporation Commission

APS - Arizona Public Service Company, a Pinnacle West subsidiary

APS Energy Services - APS Energy Services Company, Inc., a Pinnacle West
subsidiary

Company - Pinnacle West Capital Corporation

CPUC - California Public Utilities Commission

EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the
Pricing of Electricity -- Issues Related to the Application of FASB Statements
No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises -- Accounting for the Discontinuation of Application of
FASB Statement No. 71"

El Dorado - El Dorado Investment Company, a Pinnacle West subsidiary

EPA - United States Environmental Protection Agency

FASB - Financial Accounting Standards Board

FERC - United States Federal Energy Regulatory Commission

Four Corners - Four Corners Power Plant

ITC - Investment tax credit

June 10-Q - Pinnacle West Capital Corporation Quarterly Report on Form 10-Q for
the fiscal quarter ended June 30, 2000

MW - Megawatts

NGS - Navajo Generating Station

1999 10-K - Pinnacle West Capital Corporation Annual Report on Form 10-K for the
fiscal year ended December 31, 1999

Palo Verde - Palo Verde Nuclear Generating Station

Pinnacle West - Pinnacle West Capital Corporation

Pinnacle West Energy - Pinnacle West Energy Corporation, a Pinnacle West
subsidiary

SCE - Southern California Edison Company, a subsidiary of Edison International

SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"

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

Salt River Project - Salt River Project Agricultural Improvement and Power
District

Settlement Agreement - APS' Settlement Agreement approved by the ACC in 1999

SunCor - SunCor Development Company, a Pinnacle West subsidiary
<PAGE>
                                      -2-

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
                                                                    September 30,
                                                              -------------------------
                                                                  2000           1999
                                                              -----------     ---------
<S>                                                           <C>             <C>
Operating Revenues
  Electric                                                    $ 1,567,960     $ 867,630
  Real estate                                                      39,396        26,640
                                                              -----------     ---------
     Total                                                      1,607,356       894,270
                                                              -----------     ---------
Operating Expenses
  Fuel and purchased power                                      1,079,436       400,961
  Operations and maintenance                                      113,670       109,006
  Real estate operations                                           33,980        26,757
  Depreciation and amortization                                    98,628        95,068
  Taxes other than income taxes                                    25,641        22,184
                                                              -----------     ---------
     Total                                                      1,351,355       653,976
                                                              -----------     ---------
Operating Income                                                  256,001       240,294

Other Income (Expense)                                            (14,778)        1,040
                                                              -----------     ---------
Income From Continuing Operations Before
  Interest and Income Taxes                                       241,223       241,334
                                                              -----------     ---------
Interest Expense
  Interest charges                                                 42,773        39,614
  Capitalized interest                                             (5,240)       (1,990)
                                                              -----------     ---------
     Total                                                         37,533        37,624
                                                              -----------     ---------

Income From Continuing Operations Before Income Taxes             203,690       203,710
Income Taxes                                                       87,641        78,131
                                                              -----------     ---------
Income From Continuing Operations                                 116,049       125,579

Income Tax Benefit From Discontinued Operations                        --        38,000

Extraordinary Charge - Net of Income Taxes of $94,115                  --      (139,885)
                                                              -----------     ---------

Net Income                                                    $   116,049     $  23,694
                                                              ===========     =========

Average Common Shares Outstanding - Basic                          84,745        84,759

Average Common Shares Outstanding  - Diluted                       85,012        84,989

Earnings Per Average Common Share Outstanding
  Continuing Operations - Basic                               $      1.37     $    1.48
  Net Income - Basic                                          $      1.37     $    0.28
  Continuing Operations - Diluted                             $      1.37     $    1.48
  Net Income - Diluted                                        $      1.37     $    0.28

Dividends Declared Per Share                                  $      0.35     $      --
</TABLE>

See Notes to Condensed Consolidated Financial Statements.
<PAGE>
                                      -3-

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

<TABLE>
<CAPTION>
                                                                 Nine Months Ended
                                                                    September 30,
                                                            ---------------------------
                                                               2000             1999
                                                            -----------     -----------
<S>                                                         <C>             <C>
Operating Revenues
  Electric                                                  $ 2,734,362     $ 1,793,047
  Real estate                                                   117,659          83,870
                                                            -----------     -----------
     Total                                                    2,852,021       1,876,917
                                                            -----------     -----------
Operating Expenses
  Fuel and purchased power                                    1,495,218         636,062
  Operations and maintenance                                    331,754         319,212
  Real estate operations                                        101,374          78,393
  Depreciation and amortization                                 293,607         289,361
  Taxes other than income taxes                                  76,643          73,028
                                                            -----------     -----------
     Total                                                    2,298,596       1,396,056
                                                            -----------     -----------
Operating Income                                                553,425         480,861
                                                            -----------     -----------
Other Income (Expense)
  Preferred stock dividend requirements of APS                       --          (1,016)
  Net other income and expense                                   13,785            (898)
                                                            -----------     -----------
     Total                                                       13,785          (1,914)
                                                            -----------     -----------
Income From Continuing Operations Before
  Interest and Income Taxes                                     567,210         478,947
                                                            -----------     -----------
Interest Expense
  Interest charges                                              126,996         121,488
  Capitalized interest                                          (13,875)        (10,253)
                                                            -----------     -----------
     Total                                                      113,121         111,235
                                                            -----------     -----------

Income From Continuing Operations Before Income Taxes           454,089         367,712
Income Taxes                                                    194,069         142,741
                                                            -----------     -----------
Income From Continuing Operations                               260,020         224,971

Income Tax Benefit From Discontinued Operations                      --          38,000

Extraordinary Charge - Net of Income Taxes of $94,115                --        (139,885)
                                                            -----------     -----------

Net Income                                                  $   260,020     $   123,086
                                                            ===========     ===========

Average Common Shares Outstanding - Basic                        84,735          84,715

Average Common Shares Outstanding  - Diluted                     84,901          85,087

Earnings Per Average Common Share Outstanding
  Continuing Operations - Basic                             $      3.07     $      2.66
  Net Income - Basic                                        $      3.07     $      1.45
  Continuing Operations - Diluted                           $      3.06     $      2.64
  Net Income - Diluted                                      $      3.06     $      1.45

Dividends Declared Per Share                                $      1.05     $     0.975
</TABLE>

See Notes to Condensed Consolidated Financial Statements.
<PAGE>
                                      -4-

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

<TABLE>
<CAPTION>
                                                                Twelve Months Ended
                                                                   September 30,
                                                            ---------------------------
                                                               2000             1999
                                                            -----------     -----------
<S>                                                         <C>             <C>
Operating Revenues
  Electric                                                  $ 3,234,499     $ 2,236,573
  Real estate                                                   163,958         126,705
                                                            -----------     -----------
     Total                                                    3,398,457       2,363,278
                                                            -----------     -----------

Operating Expenses
  Fuel and purchased power                                    1,655,265         752,832
  Operations and maintenance                                    459,319         425,239
  Real estate operations                                        142,497         118,454
  Depreciation and amortization                                 389,814         387,644
  Taxes other than income taxes                                 100,221          96,400
                                                            -----------     -----------
     Total                                                    2,747,116       1,780,569
                                                            -----------     -----------
Operating Income                                                651,341         582,709
                                                            -----------     -----------
Other Income (Expense)
  Preferred stock dividend requirements of APS                       --          (3,059)
  Net other income and expense                                   25,476          (3,329)
                                                            -----------     -----------
     Total                                                       25,476          (6,388)
                                                            -----------     -----------
Income From Continuing Operations Before
  Interest and Income Taxes                                     676,817         576,321
                                                            -----------     -----------
Interest Expense
  Interest charges                                              167,889         163,224
  Capitalized interest                                          (15,286)        (14,588)
                                                            -----------     -----------
     Total                                                      152,603         148,636
                                                            -----------     -----------

Income From Continuing Operations Before Income Taxes           524,214         427,685
Income Taxes                                                    219,393         167,186
                                                            -----------     -----------

Income From Continuing Operations                               304,821         260,499

Income Tax Benefit From Discontinued Operations                      --          38,000

Extraordinary Charge - Net of Income Taxes of $94,115                --        (139,885)
                                                            -----------     -----------

Net Income                                                  $   304,821     $   158,614
                                                            ===========     ===========

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

Average Common Shares Outstanding  - Diluted                     84,898          85,140

Earnings Per Average Common Share Outstanding
  Continuing Operations - Basic                             $      3.60     $      3.07
  Net Income - Basic                                        $      3.60     $      1.87
  Continuing Operations - Diluted                           $      3.59     $      3.06
  Net Income - Diluted                                      $      3.59     $      1.86

Dividends Declared Per Share                                $      1.40     $      1.30
</TABLE>

 See Notes to Condensed Consolidated Financial Statements.
<PAGE>
                                      -5-

                       PINNACLE WEST CAPITAL CORPORATION
                     CONDENSED CONSOLIDATED BALANCE SHEETS

                                     ASSETS
                             (Thousands of Dollars)

                                                     September 30,  December 31,
                                                         2000           1999
                                                      ----------     ----------
                                                      (Unaudited)
Current Assets
  Cash and cash equivalents                           $   87,682     $   20,705
  Customer and other receivables--net                    669,858        244,599
  Accrued utility revenues                               111,315         72,919
  Materials and supplies                                  73,506         69,977
  Fossil fuel                                             14,553         21,869
  Deferred income taxes                                   10,081          8,163
  Other current assets                                    71,531         60,562
                                                      ----------     ----------
     Total current assets                              1,038,526        498,794
                                                      ----------     ----------
Investments and Other Assets
  Real estate investments--net                           366,386        344,293
  Other assets                                           249,157        267,458
                                                      ----------     ----------
     Total investments and other assets                  615,543        611,751
                                                      ----------     ----------
Property, Plant and Equipment
  Plant in service and held for future use             7,727,739      7,546,314
  Less accumulated depreciation and
    amortization                                       3,194,323      3,026,194
                                                      ----------     ----------
     Total                                             4,533,416      4,520,120
  Construction work in progress                          362,472        209,281
  Nuclear fuel, net of amortization                       51,274         49,114
                                                      ----------     ----------
     Net property, plant and equipment                 4,947,162      4,778,515
                                                      ----------     ----------
Deferred Debits
  Regulatory assets                                      502,595        613,729
  Other deferred debits                                   70,954        105,717
                                                      ----------     ----------
     Total deferred debits                               573,549        719,446
                                                      ----------     ----------

Total Assets                                          $7,174,780     $6,608,506
                                                      ==========     ==========

See Notes to Condensed Consolidated Financial Statements.
<PAGE>
                                      -6-

                       PINNACLE WEST CAPITAL CORPORATION
                     CONDENSED CONSOLIDATED BALANCE SHEETS

                             LIABILITIES AND EQUITY
                             (Thousands of Dollars)

                                                      September 30, December 31,
                                                          2000          1999
                                                       ----------    ----------
                                                       (Unaudited)
Current Liabilities
  Accounts payable                                     $  498,161    $  186,524
  Accrued taxes                                           231,738        70,510
  Accrued interest                                         26,410        33,253
  Short-term borrowings                                     1,984        38,300
  Current maturities of long-term debt                      4,887       114,798
  Customer deposits                                        25,603        26,098
  Other current liabilities                                45,820        26,007
                                                       ----------    ----------
     Total current liabilities                            834,603       495,490
                                                       ----------    ----------

Long-Term Debt Less Current Maturities                  2,354,911     2,206,052
                                                       ----------    ----------
Deferred Credits and Other
  Deferred income taxes                                 1,108,274     1,183,855
  Unamortized gain - sale of utility plant                 69,780        73,212
  Other                                                   431,380       444,164
                                                       ----------    ----------
     Total deferred credits and other                   1,609,434     1,701,231
                                                       ----------    ----------
Commitments and Contingencies (Notes 6, 7, 9 and 10)

Common Stock Equity
  Common stock, no par value                            1,536,493     1,537,449
  Retained earnings                                       839,339       668,284
                                                       ----------    ----------
     Total common stock equity                          2,375,832     2,205,733
                                                       ----------    ----------

Total Liabilities and Equity                           $7,174,780    $6,608,506
                                                       ==========    ==========

See Notes to Condensed Consolidated Financial Statements.
<PAGE>
                                      -7-

                       PINNACLE WEST CAPITAL CORPORATION
                CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
                                  (Unaudited)
                             (thousands of dollars)

                                                           Nine Months Ended
                                                             September 30,
                                                        -----------------------
                                                           2000          1999
                                                        ---------     ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Income From Continuing Operations                       $ 260,020     $ 224,971
  Items not requiring cash
     Depreciation and amortization                        293,607       289,361
     Nuclear fuel amortization                             23,139        24,306
     Deferred income taxes--net                           (42,984)      (74,670)
     Other--net                                            (3,350)      (18,908)
  Changes in current assets and liabilities
     Customer and other receivables--net                 (425,259)     (106,815)
     Accrued utility revenues                             (38,396)      (33,543)
     Materials, supplies and fossil fuel                    3,787        (4,758)
     Other current assets                                 (10,969)      (12,055)
     Accounts payable                                     308,407        81,805
     Accrued taxes                                        161,228       130,371
     Accrued interest                                      (6,843)       (7,871)
     Other current liabilities                             24,845        13,964
  Change in El Dorado partnership investment              (11,897)           --
  Increase in land held                                   (21,073)       (4,237)
  Other--net                                               38,717        28,431
                                                        ---------     ---------
Net Cash Flow Provided By Operating Activities            552,979       530,352
                                                        ---------     ---------
CASH FLOWS FROM INVESTING ACTIVITIES
  Capital expenditures                                   (398,994)     (235,568)
  Capitalized interest                                    (13,875)      (10,253)
  Other--net                                               20,259        (5,567)
                                                        ---------     ---------
Net Cash Flow Used For Investing Activities              (392,610)     (251,388)
                                                        ---------     ---------
CASH FLOWS FROM FINANCING ACTIVITIES
  Issuance of long-term debt                              494,000       249,191
  Short-term borrowings--net                              (36,316)       44,670
  Dividends paid on common stock                          (88,963)      (82,652)
  Repayment of long-term debt                            (461,157)     (379,936)
  Redemption of preferred stock                                --       (96,499)
  Other--net                                                 (956)      (10,250)
                                                        ---------     ---------
Net Cash Flow Used For Financing Activities               (93,392)     (275,476)
                                                        ---------     ---------
Net Cash Flow                                              66,977         3,488
Cash and Cash Equivalents at Beginning of Period           20,705        20,538
                                                        ---------     ---------
Cash and Cash Equivalents at End of Period              $  87,682     $  24,026
                                                        =========     =========

Supplemental Disclosure of Cash Flow Information:
  Cash paid during the period for:
   Interest, net of amounts capitalized                 $ 109,778     $ 109,702
   Income taxes                                         $ 127,013     $  95,590

See Notes to Condensed Consolidated Financial Statements.
<PAGE>
                                      -8-

                        PINNACLE WEST CAPITAL CORPORATION

              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. The condensed consolidated financial statements include the accounts of
Pinnacle West and its subsidiaries: APS, Pinnacle West Energy, APS Energy
Services, SunCor, and El Dorado . All significant intercompany balances 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
extraordinary charge and the tax benefit from discontinued operations. 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 1999 10-K.

3. Weather conditions and wholesale power marketing and trading activities can
have significant impacts on our results for interim periods. El Dorado's
earnings are subject to stock market volatility (see Note 12). For these and
other reasons, results for interim periods do not necessarily represent results
to be expected for the year.

4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for
changes in capitalization for the nine months ended September 30, 2000.

5. Regulatory Accounting

For regulated operations, APS prepares its financial statements in accordance
with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the
impact of regulatory decisions in its financial statements.

During 1997, the Emerging Issues Task Force (EITF) of the FASB issued EITF 97-4.
EITF 97-4 requires that SFAS No. 71 be discontinued no later than when
legislation is passed or a rate order is issued that contains sufficient detail
to determine its effect on the portion of the business being deregulated, which
could result in write-downs or write-offs of physical and/or regulatory assets.
Additionally, the EITF determined that regulatory assets should not be written
off if they are to be recovered from a portion of the entity which continues to
apply SFAS No. 71.

The Settlement Agreement was approved by the ACC in September 1999 (see Note 6
for a discussion of the agreement). Consequently, APS has discontinued the
application of SFAS No. 71 for its generation operations. This application means
that the generation assets were tested for impairment and the portion of
regulatory assets deemed to be unrecoverable through ongoing regulated cash
flows was eliminated. APS determined that the generation assets were not
impaired. A regulatory disallowance removed $234 million pretax ($183 million
net present value) from ongoing regulatory cash flows and was recorded as a net
reduction of regulatory assets. This reduction ($140 million after income taxes)
was reported as an extraordinary charge on the consolidated income statement
during the third quarter of 1999. Prior to the Settlement Agreement, under the
1996 regulatory agreement (see Note 6), the ACC accelerated the amortization of
substantially all of APS' regulatory assets to an eight-year period ending June
30, 2004.
<PAGE>
                                       -9-

The regulatory assets to be recovered under the 1999 Settlement Agreement are
now being amortized as follows (millions of dollars):

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

The majority of APS' regulatory assets relate to deferred income taxes and rate
synchronization cost deferrals.

The condensed consolidated balance sheets include the amounts listed below for
generation assets not subject to SFAS No. 71 (thousands of dollars):

                                                   September 30,  December 31,
                                                       2000          1999
                                                    -----------   -----------
Electric plant in service & held for future use     $ 3,819,709   $ 3,770,234
Accumulated depreciation and amortization            (1,725,706)   (1,641,855)
Construction work in progress                           224,760        87,819
Nuclear fuel, net of amortization                        51,274        49,114


6. Regulatory Matters -- Electric Industry Restructuring

STATE

SETTLEMENT AGREEMENT. On May 14, 1999, APS entered into a comprehensive
Settlement Agreement with various parties, including representatives of major
consumer groups, related to the implementation of retail electric competition.
On September 23, 1999, the ACC voted to approve the Settlement Agreement, with
some modifications. On December 13, 1999, two parties filed lawsuits challenging
the ACC's approval of the Settlement Agreement. One of the parties questioned
the authority of the ACC to approve the Settlement Agreement and both parties
challenged several specific provisions of the Settlement Agreement. A decision
on the appeals to the Settlement Agreement is not expected until later this year
or next year.

The following are the major provisions of the 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
          electric price reductions of 1.5% beginning July 1, 1999 through July
          1, 2003, for a total of 7.5%. The first reduction of approximately $24
          million ($14 million after income taxes) included the July 1, 1999
          retail price decrease of approximately $11 million ($7 million after
          income taxes) related to the 1996 regulatory agreement. See "1996
          Regulatory Agreement" below. Based on the price reduction authorized
          in the Settlement Agreement, there
<PAGE>
                                      -10-

          was a retail price decrease of approximately $28 million ($17 million
          after taxes), or 1.5%, effective July 1, 2000. For customers having
          loads three MW or greater, standard offer rates will be reduced in
          varying annual increments that total 5% through 2002.

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

     *    There will be a moratorium on retail price changes for standard offer
          and unbundled competitive direct access services until July 1, 2004,
          except for the price reductions described above and certain other
          limited circumstances. Neither the ACC nor 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, 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.

     *    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 current
          rates, and costs associated with APS' "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 will be eligible for retail access in accordance
          with the phase-in adopted by the ACC under the electric competition
          rules (see "Retail Electric Competition Rules" below), with an
          additional 140 MW being made available to eligible non-residential
          customers. Unless subject to judicial or regulatory restraint, APS
          will open its distribution system to retail access for all customers
          on January 1, 2001.

     *    Prior to the Settlement Agreement, APS was recovering substantially
          all of its regulatory assets through July 1, 2004, pursuant to the
          1996 regulatory agreement. In addition, the 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 Settlement
          Agreement provides that APS will have the opportunity to recover $350
          million net present value through a competitive transition charge
          (CTC) that will remain in effect through December 31, 2004, at which
          time it will terminate. Any over/under-recovery will be
          credited/debited against the costs subject to recovery under the
          adjustment clause described above.

     *    APS will form a separate corporate affiliate or affiliates and
          transfer to such affiliate(s) its generating assets and competitive
          services at book value as of the date of transfer, which transfer
          shall take place no later than December 31, 2002.
<PAGE>
                                      -11-

          See Management's Discussion and Analysis of Financial Condition and
          Results of Operations below for a discussion of the planned timing of
          the transfer. 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.

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

As discussed in Note 5 above, APS has discontinued the application of SFAS No.
71 for its generation operations.

RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to
approve the rules that provide a framework for the introduction of retail
electric competition in Arizona (Rules). If any of the Rules conflict with the
Settlement Agreement, the terms of the Settlement Agreement govern. On December
8, 1999, APS filed a lawsuit to protect its legal rights regarding the Rules.
This lawsuit is pending, along with several other lawsuits on ACC orders
relating to stranded cost recovery, the adoption or amendment of the Rules and
the certification of competitive electric service providers.

On July 12, 2000, a Maricopa County Superior Court judge issued a preliminary
ruling and denied most of the substantive challenges to the Rules that had been
made by certain electric cooperatives. However, he concluded that some of the
Rules were invalid because of procedural deficiencies or were invalid in their
application. Specifically, the judge concluded that several non-ratemaking Rules
were required to be presented to the Arizona Attorney General for certification
prior to becoming effective. Additionally, the judge determined that the Arizona
Constitution requires the ACC to make findings regarding the fair value of
property in Arizona in establishing rates for competitive electric service
providers (ESPs), which rendered the rate setting provisions of the Rules
invalid in the application.

On November 2, 2000, the same Superior Court judge amended his July 12
preliminary ruling. This amended ruling indicated the Court's intent to accept
the substantive provisions of a form of final judgment submitted by the electric
cooperatives that finds the Rules in their entirety to be unconstitutional and
unlawful due to failure to establish fair value rate base and because certain of
the Rules were not submitted to the Arizona Attorney General for certification.
The cooperatives' proposed form of final judgment also invalidates all the ACC
orders authorizing competitive electric service providers in Arizona. We do not
believe either of the rulings affects the Settlement Agreement with the ACC. The
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 APS Settlement Agreement.
<PAGE>
                                      -12-

Although the ACC has not yet indicated what steps it intends to take after a
final judgment is issued, the ACC could appeal the ruling to the Court of
Appeals or could elect to take action to correct the deficiencies identified in
the judge's ruling. The cooperatives or the ESPs may also appeal the ruling. If
the order is appealed by the ACC or any of the ESPs, including APS Energy
Services, we believe that it will be automatically stayed pending further
judicial review.

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

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

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

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

     *    Residential customers were phased in at 1.25% per quarter calculated
          beginning on January 1, 1999, subject to the 20% requirement above.

     *    Electric service providers that get Certificates of Convenience and
          Necessity (CC&Ns) from the ACC can supply only competitive services,
          including electric generation, but not electric transmission and
          distribution.

     *    Affected utilities must file ACC tariffs that unbundle rates for
          non-competitive services.

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

     *    Absent an ACC waiver, prior to January 1, 2001, each affected utility
          (except certain electric cooperatives) must transfer all competitive
          generation assets and services either to an unaffiliated party or to a
          separate corporate affiliate. Under the Settlement Agreement, APS
          received a waiver to allow transfer of its generation and other
          competitive assets and services to affiliates no later than December
          31, 2002.
<PAGE>
                                      -13-

          See Management's Discussion and Analysis of Financial Condition and
          Results of Operations below for a discussion of the planned timing of
          the transfer.

1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and APS. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases
(approximate) as follows (millions of dollars):

         Annual Electric               Percentage
        Revenue Decrease                Decrease           Effective Date
        ----------------                --------           --------------
               $49                        3.4%              July 1, 1996
               $18                        1.2%              July 1, 1997
               $17                        1.1%              July 1, 1998
               $11                        0.7%              July 1, 1999 (a)

(a)  Included in the first rate reduction under the Settlement Agreement (see
     above).

The regulatory agreement also required the parent company to infuse $200 million
of common equity into APS in annual payments of $50 million from 1996 through
1999. All of these equity infusions were made by December 31, 1999.

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

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

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

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

GENERAL

We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, or results of operations. As competition in the
electric industry continues to
<PAGE>
                                      -14-

evolve, we will continue to evaluate strategies and alternatives that will
position the Company and our subsidiaries to compete in the new regulatory
environment.

FEDERAL

The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted
increased competition in the wholesale electric power markets. APS does not
expect these rules to have a material impact on its financial statements.

Several electric utility industry restructuring bills have been introduced
during the current congressional session. Several of these bills are written to
allow consumers to choose their electricity suppliers beginning in 2000 and
beyond. These bills, other bills that are expected to be introduced, and ongoing
discussions at the federal level suggest a wide range of opinion that will need
to be narrowed before any comprehensive restructuring of the electric utility
industry can occur.

7. Nuclear Insurance

The Palo Verde participants have insurance for public liability payments
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'
29.1% interest in the three Palo Verde units, APS' maximum potential assessment
per incident 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.
<PAGE>
                                      -15-

8. Business Segments

We have two principal business segments (determined by products, services and
regulatory environment) which consist of the transmission and distribution of
electricity and wholesale power marketing and trading activities (delivery
business segment) and the generation of electricity (generation business
segment). The other amounts include activity relating to the parent company and
other subsidiaries including APS Energy Services, SunCor and El Dorado.
Eliminations primarily relate to intersegment sales of electricity. Segment
information for the three, nine and twelve months ended September 30, 2000 and
1999 is as follows (millions of dollars):

<TABLE>
<CAPTION>
                                       3 Months Ended         9 Months Ended         12 Months Ended
                                        September 30,          September 30,           September 30,
                                      -----------------     -------------------     -------------------
                                        2000       1999       2000        1999        2000        1999
                                      -------     -----     -------     -------     -------     -------
Operating Revenues:
<S>                                   <C>         <C>       <C>         <C>         <C>         <C>
Delivery                              $ 1,566     $ 867     $ 2,731     $ 1,793     $ 3,231     $ 2,236
Generation                                322       266         750         662         942         852
Other                                      41        27         121          84         167         127
Eliminations                             (322)     (266)       (750)       (662)       (942)       (852)
                                      -------     -----     -------     -------     -------     -------
     Total                            $ 1,607     $ 894     $ 2,852     $ 1,877     $ 3,398     $ 2,363
                                      =======     =====     =======     =======     =======     =======

Income from Continuing Operations:
Delivery                              $    57     $  61     $   137     $   115     $   169     $   142
Generation                                 66        69         114         117         117         126
Other                                      (7)       (4)          9          (7)         19          (8)
                                      -------     -----     -------     -------     -------     -------
     Total                            $   116     $ 126     $   260     $   225     $   305     $   260
                                      =======     =====     =======     =======     =======     =======


                                                          As of September 30,     As of December 31,
                                                                 2000                   1999
                                                                 ----                   ----
Assets:
Delivery                                                        $4,238                 $3,796
Generation                                                       2,452                  2,342
Other                                                              485                    471
                                                                ------                 ------
     Total                                                      $7,175                 $6,609
                                                                ======                 ======
</TABLE>

9. Accounting Matters

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". In June 2000, the FASB issued SFAS No. 138,
which amends certain provisions of SFAS133 to clarify certain areas causing
difficulties in implementation. The amendment includes expanding the normal
purchase and sale exemption for supply contracts. We will adopt SFAS133 and the
corresponding amendments under SFAS138 on
<PAGE>
                                      -16-

January 1, 2001. We are currently determining the impact of SFAS133 on our
consolidated results of operations and financial position; however, certain
implementation issues are currently being resolved by the FASB's Derivatives
Implementation Group that will significantly affect its impact. This statement
should have no impact on consolidated cash flows.

10. Generation Expansion

Pinnacle West Energy has announced plans to build and acquire up to 4,000 MW of
generating capacity from 2001-2006 at an estimated cost of about $2 billion,
assuming all of the announced plants are built or acquired.

Pinnacle West Energy is also considering additional expansion over the next
several years, which may result in additional expenditures. Pinnacle West
Energy's expenditures are expected to be funded through internally generated
cash and debt issued directly by Pinnacle West Energy, as well as capital
infusions from Pinnacle West's internally generated cash and debt proceeds.

Pinnacle West Energy is currently planning a 650-megawatt expansion of the West
Phoenix Power Plant and the construction of a natural gas-fired electric
generating station of up to 2,120 megawatts near Palo Verde, called Redhawk .
Construction on West Phoenix Unit 4 began in June 2000, with commercial
operation of the unit expected in the summer of 2001. Pinnacle West Energy
expects construction to begin on Unit 5 in mid-2001, with commercial operation
in mid- 2003, and expects to partner with Calpine on West Phoenix Unit 5.
Pinnacle West Energy expects that construction will begin on the first two units
of Redhawk near the end of 2000, with commercial operation scheduled for the
summer of 2002.

See "Liquidity and Capital Resources -- Capital Expenditure Requirements" in
Management's Discussion and Analysis of Financial Condition and Results of
Operations below for projected capital expenditures for the above expansion
plans.

On April 27, 2000, Pinnacle West Energy entered into two separate agreements
with SCE to purchase SCE's 15.8% ownership interest in Palo Verde and its 48%
ownership interest in Units 4 and 5 of the Four Corners Power Plant. The
purchase price is $550 million in cash to be paid at closing, subject to certain
adjustments. The interests to be acquired represent 1,310 MW of generating
capacity (600 MW associated with SCE's Palo Verde interest, and 710 MW
associated with SCE's Four Corners interest). The transactions are expected to
close in 2001, subject to the approval of various governmental authorities,
including the CPUC, the FERC, the U.S. Nuclear Regulatory Commission, the
Internal Revenue Service, and the Navajo Nation.

The agreements between Pinnacle West Energy and SCE include the following
additional terms:

*    Prior to and up to 90 days following SCE's filing with the CPUC seeking
     approval of the transactions, which was made on May 15, 2000, SCE was
     allowed to solicit offers for, or indications of interest in, (a) its Four
     Corners interest or (b) its Four Corners interest and its Palo Verde
     interest. SCE's sale of its interest in Four Corners is also subject to a
     right of first refusal on the part of the other Four Corners participants,
     including APS. Pinnacle West Energy had the right to match any offer or
     indication of interest that SCE
<PAGE>
                                      -17-

     received during this period. This period expired without Pinnacle West
     Energy matching an indication of interest.

*    The Agreements permit SCE, for a period of up to 120 days (until late
     November), to engage in further negotiations and discussions with any
     party who submitted an indication of interest. Subject to CPUC approval,
     Pinnacle West Energy retains the right under the Agreements to match the
     terms of any binding agreement that SCE elects to enter into.

*    Pinnacle West Energy is not obligated to purchase SCE's Four Corners
     interest unless SCE also sells its Palo Verde interest to Pinnacle West
     Energy. SCE is not obligated to sell its Palo Verde interest to Pinnacle
     West Energy unless Pinnacle West Energy (or some other third party)
     purchases SCE's Four Corners interest.

*    SCE will transfer the assets of its Palo Verde decommissioning fund to
     Pinnacle West Energy, and Pinnacle West Energy will assume SCE's Palo Verde
     decommissioning obligations.

*    Pinnacle West Energy will assume SCE's obligations and liabilities
     associated with ownership of its interests in Palo Verde and Four Corners,
     subject to specified exceptions.

*    We guaranteed Pinnacle West Energy's obligations under each of the
     agreements, including Pinnacle West Energy's purchase price obligations.

The CPUC hearing on approval of the sale has been scheduled for February 2001.
The Utility Reform Network and the Utility Workers Union of America have jointly
filed a motion to dismiss, recommending that the CPUC reject the sale. The
California Office of Ratepayer Advocates has also joined in the motion to
dismiss.

11. Income Tax Benefit

In September 1999, we recorded a tax benefit of $38 million, or $0.45 per basic
or diluted share, which stemmed from the resolution of income tax matters
related to a former subsidiary, MeraBank, A Federal Savings Bank. This amount is
reflected as a tax benefit from discontinued operations in the income statement.

12. El Dorado Partnership Investment Income

Net other income consists primarily of El Dorado's share in the earnings of a
venture capital partnership. The partnership adjusts the value of its
investments at the end of each fiscal quarter. The value of El Dorado's
investment in the partnership is determined by various factors beyond our
control, including equity market conditions. Most of the partnership's
investments are in technology-related companies whose share prices are highly
volatile.

Prior to June 2000, we recorded our share of the earnings from the partnership,
as the partnership adjusted the value of its investment, on a one-quarter lag.
This procedure was followed due to time constraints in obtaining and analyzing
such results for inclusion in our
<PAGE>
                                      -18-

consolidated financial statements on a current basis. Beginning in the second
quarter of 2000, we requested a distribution of our share of the investments
held by the partnership, and we adjusted our investment to reflect the current
market value.

In the third quarter of 2000, we recognized a loss of $9 million after income
taxes, which was our share of the partnership's loss for the quarter. This loss
was the result of a reduction in the market value of the investments held by the
partnership. The book value of El Dorado's investment in the partnership at
September 30, 2000 was approximately $18 million.

El Dorado is currently seeking an amendment to the partnership agreement that
would result in El Dorado receiving a distribution of securities representing
substantially all of El Dorado's investment in the partnership. Upon El Dorado's
receipt of these securities, we will account for the securities as available for
sale with changes in value recorded in other comprehensive income. Gains and
losses from the ultimate sale of such securities will be reflected in our net
earnings.
<PAGE>
                                      -19-

                        PINNACLE WEST CAPITAL CORPORATION

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

In this section, we explain our 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 periods presented
     *    the factors impacting our business, including competition
     *    the effects of regulatory decisions on our results and outlook
     *    our capital needs and resources and
     *    our management of market risks.

APS, our major subsidiary and Arizona's largest electric utility, provides
retail and wholesale electric service to the entire state with the exception of
Tucson and about one-half of the Phoenix area. APS also generates, sells, and
delivers electricity to wholesale customers in the western United States. SunCor
is a developer of residential, commercial, and industrial real estate projects
in Arizona, New Mexico, and Utah. El Dorado is primarily a venture capital firm.
APS Energy Services was formed in 1998 and sells energy and energy-related
products and services in competitive retail markets in the western United
States. Pinnacle West Energy, which was formed in 1999, is the subsidiary
through which we intend to conduct our unregulated generation operations.

As discussed in Note 6, the Settlement Agreement and the Rules require APS to
transfer its generating assets and competitive services to one or more corporate
affiliates. We plan to complete the move of our wholesale power marketing and
trading activities from APS to the parent company by the end of 2000. APS plans
to move certain of its non-nuclear generating facilities and related assets, as
well as certain employees of APS' generation business unit, to Pinnacle West
Energy on January 1, 2001, or as soon thereafter as requisite approvals are
obtained. See Note 6 for information regarding lawsuits challenging the
Settlement Agreement and the Rules.

We suggest this section be read along with the 1999 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 RESULTS

The following table summarizes net income for the three-month, nine-month and
twelve-month periods ended September 30, 2000 and the comparable prior year
periods for Pinnacle West and each of its subsidiaries:
<PAGE>
                                      -20-

<TABLE>
<CAPTION>
                                        3 Months Ended      9 Months Ended      12 Months Ended
                                         September 30,       September 30,       September 30,
                                        ---------------     ---------------     ----------------
(Millions of Dollars)                   2000      1999      2000      1999      2000     1999(a)
                                        -----     -----     -----     -----     -----    -------
<S>                                     <C>       <C>       <C>       <C>       <C>       <C>
APS                                     $ 124     $ 130     $ 253     $ 232     $ 288     $ 268
Pinnacle West Energy                       (1)       --        (2)       --        (2)       --

APS Energy Services                        --        (2)       (4)       (5)       (8)       (5)
SunCor                                      2        --         8         4        11         7
El Dorado                                  (9)       --         7        --        18        --
Parent Company                             --        (2)       (2)       (6)       (2)       (9)
                                        -----     -----     -----     -----     -----     -----
Income From Continuing Operations         116       126       260       225       305       261
Income Tax Benefit From Discontinued
 Operations                                --        38        --        38        --        38

Extraordinary Charge - Net of Income
 Taxes of $94                              --      (140)       --      (140)       --      (140)
                                        -----     -----     -----     -----     -----     -----
Net Income                              $ 116     $  24     $ 260     $ 123     $ 305     $ 159
                                        =====     =====     =====     =====     =====     =====
</TABLE>

(a)  SunCor's 1999 earnings have been restated here to exclude a $37 million
     deferred tax benefit. In accordance with our intercompany tax sharing
     agreement, the offset resides with the parent company. There is no
     consolidated earnings effect as these tax benefits had already been
     reflected on a consolidated basis.


     OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED
     WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1999

Consolidated net income for the three months ended September 30, 2000 was $116
million compared with $24 million for the same period in the prior year. The
increase primarily relates to an extraordinary charge recorded in the third
quarter of 1999, partially offset by lower income from continuing operations in
the third quarter of 2000, as well as an income tax benefit from discontinued
operations also recorded in the third quarter of 1999.

The extraordinary charge related to a regulatory disallowance that resulted from
APS' comprehensive Settlement Agreement that was approved by the ACC in
September 1999. See Notes 5 and 6 for additional information about the
regulatory disallowance and the Settlement Agreement.

The income tax benefit from discontinued operations resulted from the resolution
of income tax matters related to a former subsidiary, MeraBank. See Note 11.

Income from continuing operations decreased $10 million over the comparable
prior year period primarily because of a loss at El Dorado, the completion of
the amortization of ITCs in 1999, an electricity price reduction, and
miscellaneous factors. Partially offsetting these factors was an increase in the
contribution of wholesale power marketing and trading activities. See Note 6 for
information on the price reduction. See "Income Taxes" below for a discussion of
the ITC amortization.

Electric operating revenues increased $ 700 million because of:

     *    increased power marketing, trading, and wholesale revenues ($664
          million)
<PAGE>
                                      -21-

     *    increases in the number of customers and the average amount of
          electricity used by customers ($33 million)
     *    warmer weather impacts ($9 million) and
     *    miscellaneous factors ($2 million).

As mentioned above, these positive factors were partially offset by the effect
of a reduction in retail electricity prices ($8 million).

The increase in power marketing, trading, and wholesale revenues resulted from
higher prices and increased activity in the western U.S. wholesale power
markets. The revenues were accompanied by an increase in purchased power and
fuel expenses of $602 million.

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

Operations and maintenance expenses increased primarily because of higher costs
related to customer growth.

Property tax expense increased because of higher tax rates.

Depreciation and amortization expense increased primarily because of higher
plant balances.

Net other income and expense decreased $16 million primarily because of a
decrease in the market value of El Dorado's investment in a technology-related
venture capital partnership. See Note 12.

     OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED
     WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1999

Consolidated net income for the nine months ended September 30, 2000 was $260
million compared with $123 million for the same period in the prior year. The
increase primarily relates to an extraordinary charge recorded in the third
quarter of 1999, higher income from continuing operations for the nine months
ended September 30, 2000, partially offset by an income tax benefit from
discontinued operations also recorded in the third quarter of 1999.

The extraordinary charge related to a regulatory disallowance that resulted from
APS' comprehensive Settlement Agreement that was approved by the ACC in
September 1999. See Notes 5 and 6 for additional information about the
regulatory disallowance and the Settlement Agreement.

The income tax benefit from discontinued operations resulted from the resolution
of income tax matters related to a former subsidiary, MeraBank. See Note 11.

Income from continuing operations increased $35 million over the comparable
prior year period primarily because of an increase in the contribution of
wholesale power marketing and trading activities and an increase in El Dorado's
earnings. These positive factors more than offset decreases due to the
completion of the amortization of ITCs in 1999, electricity
<PAGE>
                                      -22-

price reductions, higher operations and maintenance expense, and miscellaneous
factors. See Note 6 for information on the price reductions. See "Income Taxes"
below for a discussion of the ITC amortization.

Electric operating revenues increased $941 million because of:

     *    increased power marketing, trading, and wholesale revenues ($840
          million)
     *    increases in the number of customers and the average amount of
          electricity used by customers ($87 million)
     *    warmer weather impacts ($28 million) and
     *    miscellaneous factors ($4 million).

These positive factors were partially offset by the effect of a reduction in
retail electricity prices ($18 million).

The increase in power marketing, trading, and wholesale revenues resulted from
higher prices and increased activity in the western U.S. wholesale power
markets. The revenues were accompanied by an increase in purchased power and
fuel expenses of $734 million.

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

Operations and maintenance expenses increased primarily because of higher costs
primarily related to customer growth.

Net other income and expense increased $15 million primarily because of an
increase in the market value of El Dorado's investment in a technology-related
venture capital partnership. See Note 12.

     OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED
     WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1999

Consolidated net income for the twelve months ended September 30, 2000 was $305
million compared with $159 million for the same period in the prior year. The
increase primarily relates to an extraordinary charge recorded in the third
quarter of 1999, higher income from continuing operations in the twelve-month
period ended September 30, 2000, partially offset by an income tax benefit from
discontinued operations also recorded in the third quarter of 1999.

The extraordinary charge related to a regulatory disallowance that resulted from
APS' comprehensive Settlement Agreement that was approved by the ACC in
September 1999. See Notes 5 and 6 for additional information about the
regulatory disallowance and the Settlement Agreement.
<PAGE>
                                      -23-

The income tax benefit from discontinued operations resulted from the resolution
of income tax matters related to a former subsidiary, MeraBank. See Note 11.

Income from continuing operations increased $44 million over the comparable
prior year period primarily because of an increase in the contribution of
wholesale power marketing and trading activities, an increase in the number of
customers and in the average amount of electricity used by customers, and an
increase in El Dorado's earnings. These positive factors more than offset
decreases due to the completion of the amortization of ITCs in 1999, reductions
in retail electricity prices, higher operations and maintenance expenses and
miscellaneous factors. See Note 6 for information on the price reduction. See
"Income Taxes" below for a discussion of the ITC amortization.

Electric operating revenues increased $998 million because of:

     *    increased power marketing, trading, and wholesale revenues ($880
          million)
     *    increases in the number of customers and the average amount of
          electricity used by customers ($107 million)
     *    warmer weather impacts ($35 million) and
     *    miscellaneous factors ($4 million).

These positive factors were partially offset by the effect of a reduction in
retail prices ($28 million).

The increase in power marketing, trading, and wholesale revenues resulted
primarily from increased activity in western U.S. wholesale power markets and
higher prices. The revenues were accompanied by increases in purchased power and
fuel expenses of $769 million.

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

Operations and maintenance expenses increased primarily because of customer
growth, power marketing costs, and technology related costs.

Net other income and expense increased $29 million primarily because of an
increase in the market value of El Dorado's investment in a technology-related
venture capital partnership. See Note 12.

INCOME TAXES

As part of a 1994 rate settlement with the ACC, APS accelerated amortization of
substantially all deferred ITCs over a five-year period that ended on December
31, 1999. The ITC amortization decreased annual income tax expense by
approximately $24 million. Beginning in 2000, no further benefits from these
deferred ITCs will be reflected in income tax expense.
<PAGE>
                                      -24-

Liquidity and Capital Resources

     CAPITAL EXPENDITURE REQUIREMENTS

The following table summarizes the actual capital expenditures for the
nine-month period ended September 30, 2000 and estimated capital expenditures
for the next three years:

                              CAPITAL EXPENDITURES
                              (millions of dollars)

                                  Nine months ended      Twelve months ended
                                 September 30, 2000          December 31,
                                      (actual)               (estimated)(a)
                                 ------------------   --------------------------
                                                      2000       2001       2002
                                                      ----       ----       ----
APS (b)                                    $275       $464       $356       $364
Pinnacle West Energy (c)                    118        195        544        122
SunCor                                       42         53         43         51
                                           ----       ----       ----       ----
Total                                      $435       $712       $943       $537
                                           ====       ====       ====       ====

(a)  Includes approximately $40 - $50 million for capital improvements to
     existing fossil generating facilities in APS for 2000 and approximately $40
     - $50 million in capital improvements to existing fossil generating
     facilities in Pinnacle West Energy for each year thereafter.
(b)  Includes about $30 - $35 million each year for nuclear fuel expenditures
     and approximately $55 - $60 million each year for capital improvements to
     existing nuclear generating facilities.
(c)  Excludes the SCE purchase agreements of approximately $550 million in 2001.
     See Note 10 and "Capital Resources and Debt Financing - Pinnacle West
     Energy" below.

     CAPITAL RESOURCES AND DEBT FINANCING

          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 1999 10-K.

During the nine-months ended September 30, 2000, the parent company increased
long-term borrowings by about $65 million.

          APS

APS' long-term debt redemption requirements, optional repayments on long-term
debt, and payment obligations on a capitalized lease are: $354 million in 2000;
$252 million in 2001; and $125 million in 2002. During the nine months ended
September 30, 2000, APS redeemed all of its long-term debt requirements for 2000
with cash from operations and short-term borrowings. On August 7, 2000, APS
issued $300 million of its 7 5/8% Notes Due 2005.
<PAGE>
                                      -25-

APS expects to purchase Units 1, 2 and 3 of the West Phoenix Power Plant in
December 2000. These units are currently reflected as a capitalized lease.

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 announced plans to build and acquire up to 4,000 MW of
generating capacity from 2001-2006 at an estimated cost of about $2 billion,
assuming all announced plants are built or acquired.

Pinnacle West Energy is also considering additional expansion over the next
several years, which may result in additional expenditures. Pinnacle West
Energy's expenditures are expected to be funded through internally generated
cash and debt issued directly by Pinnacle West Energy, as well as capital
infusions from Pinnacle West's internally generated cash and debt proceeds.

Pinnacle West Energy is currently planning a 650-megawatt expansion of the West
Phoenix Power Plant and the construction of a natural gas-fired electric
generating station of up to 2,120 megawatts near Palo Verde, called Redhawk.
Construction on West Phoenix Unit 4 began in June 2000, with commercial
operation of the unit expected in the summer of 2001. Pinnacle West Energy
expects construction to begin on Unit 5 in mid-2001, with commercial operation
in mid-2003, and expects to partner with Calpine on West Phoenix Unit 5.
Pinnacle West Energy also expects that construction will begin on the first two
units of Redhawk near the end of 2000, with commercial operation scheduled for
the summer of 2002.

See the above table for expected capital expenditures for Pinnacle West Energy's
share of these expansions on the current schedule.

Pinnacle West Energy has signed two separate agreements with SCE to acquire
SCE's interest in the Palo Verde Nuclear Generating Station west of Phoenix and
the Four Corners Power Plant near Farmington, New Mexico. Pursuant to the
agreements, Pinnacle West Energy will acquire SCE's 15.8% interest in the three
unit Palo Verde plant and SCE's 48% interest in Four Corners Units 4 and 5, for
a total of approximately 1,300 MW at both plants. The total purchase price is
$550 million, subject to certain adjustments. The transactions are expected to
close in 2001 following the approval of various governmental authorities,
including the CPUC, the FERC, the U.S. Nuclear Regulatory Commission, the
Internal Revenue Service, and the Navajo Nation.

Prior to and up to 90 days following SCE's filing with the CPUC seeking approval
of the transactions, which was made on May 15, 2000, SCE was allowed to solicit
offers for, or indications of interest in, (a) its Four Corners interest or (b)
its Four Corners interest and its Palo Verde interest. SCE's sale of its
interest in Four Corners is also subject to a right of first refusal on the part
of the other Four Corners participants, including APS. Pinnacle West Energy had
the right to match any offer or indication of interest that SCE received during
this period. This period expired without Pinnacle West Energy matching an
indication of interest. The Agreements permit SCE, for a period of up to 120
days (until
<PAGE>
                                      -26-

late November), to engage in further negotiations and discussions with any party
who submitted an indication of interest. Subject to CPUC approval, Pinnacle West
Energy retains the right under the Agreements to match the terms of any binding
agreement that SCE elects to enter into. For additional information about the
transactions, see Note 10.

          SUNCOR

SunCor's capital needs consist primarily of capital expenditures for land
development, retail and office building construction, and home construction.
Capital resources to meet these requirements include funds from operations and
SunCor's own external financings.

FINANCIAL OUTLOOK

This section describes the major factors affecting our financial outlook. See
"Liquidity and Capital Resources" for expected capital expenditures and
financing requirements. See "Operating Results" for a summary of each
subsidiary's earnings for the three-month, nine-month, and twelve-month periods
ended September 30, 2000 and 1999.

The electric industry is restructuring to a competitive, customer-driven
environment from a regulated monopoly structure. See Note 6 for a discussion of
industry restructuring developments and their potential impacts on our financial
outlook. In addition to other issues, APS' Settlement Agreement sets forth
electricity prices for its regulated electricity services and the timing for
customer eligibility to select competitive energy providers.

We have announced plans to expand our electricity generation capacity. See Note
10 and "Liquidity and Capital Resources - Pinnacle West Energy" for details of
the generation expansion program. The planned additional generation is expected
to increase revenues, fuel expenses, operating expenses, and financing costs. We
have not announced the estimated effects of the generation expansion activities
on our financial outlook.

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. The 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 3.9% a year for
the three years 1997 through 1999; we currently expect customer growth to
average 3.5% to 4% a year for 2000 through 2002. We currently estimate that
electricity sales in kilowatt-hours will grow 4% to 5% a year in 2000 through
2002, before the effects of weather variations. The customer growth and sales
growth referred to in this paragraph apply to energy delivery customers. As
industry restructuring continues in the regulated market area, we cannot predict
the number of APS' standard offer customers that will switch to unbundled
service.
<PAGE>
                                      -27-

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

Competitive sales of energy and energy-related products and services are made by
APS Energy Services in western states that have opened to competitive supply.
Such activities are currently not material to our consolidated financial
results; however, we currently expect their contribution to grow modestly over
the next several years.

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

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

Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property, changes in regulatory
asset amortization, and our generation expansion program. See Note 5 for the
regulatory asset amortization that is being recorded in 1999 through 2004
pursuant to the Settlement Agreement. See Note 1 of Notes to Consolidated
Financial Statements in the 1999 10-K regarding current depreciation rates.

Taxes other than income taxes consist primarily of property taxes, which are
affected by tax rates and the value of property in service and under
construction. We expect property taxes to grow 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.

The annual earnings contribution from our real estate subsidiary, SunCor, is
expected to increase modestly over the next several years. SunCor's earnings for
1997, 1998 and 1999 were $5.3 million, $7.5 million (excluding the effects of a
deferred tax asset transfer), and $6.1 million, respectively.

El Dorado, our investment subsidiary, is affected by market conditions related
to its investments. See Note 12 for a discussion of recent events affecting El
Dorado's financial results and its outlook. Historical results are not
necessarily indicative of future performance for El Dorado.

Our financial results may be affected by a number of broad factors. See
"Forward-Looking Statements" for further information on such factors, which may
cause our actual future results to differ from those we currently seek or
anticipate.
<PAGE>
                                      -28-

COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING

See Note 5 for a discussion of regulatory accounting. See Note 6 for a
discussion of a Settlement Agreement related to the implementation of retail
electric competition and to Arizona and federal legal and regulatory
developments.

RATE MATTERS

See Note 6 for a discussion of a price reduction effective as of July 1, 2000,
and for a discussion of a 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 that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans,"
"believes," "projects," and similar expressions identify forward-looking
statements. These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric industry; the outcome of the regulatory
proceedings relating to the restructuring; regulatory, tax, and environmental
legislation; our ability to successfully compete outside traditional regulated
markets; regional economic conditions, which could affect customer growth; the
cost of debt and equity capital; weather variations affecting customer usage;
technological developments in the electric industry; the successful completion
of large-scale construction projects; the value of El Dorado's investment in a
technology-related venture capital partnership; successfully managing market
risks; and the strength of the real estate market.

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 commodity
prices, interest rates, and investments held by the 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 our risks associated with
these market fluctuations by utilizing various
<PAGE>
                                      -29-

commodity derivatives, including exchange-traded futures and options and
over-the-counter forwards, options, and swaps. As part of our overall risk
management program, we enter into these derivative transactions to hedge
purchases and sales of electricity, fuels and emissions allowances/credits. In
addition, we engage in trading activities intended to profit from favorable
movements of market prices.

As of September 30, 2000, a hypothetical adverse price movement of 10% in the
market price of our commodity derivative portfolio would decrease the fair
market value of these contracts by approximately $37 million. This analysis does
not include the favorable impact this same hypothetical price move would have on
the underlying physical exposures being hedged with the commodity derivative
portfolio. We plan to move our wholesale power marketing and trading activities
from APS to the parent company by the end of 2000.

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

Changing interest rates will affect interest paid on variable-rate debt and
interest earned by the nuclear decommissioning trust fund. Our policy is to
manage interest rates through the use of a combination of fixed-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.
<PAGE>
                                      -30-

                           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 6 of Notes to Condensed Consolidated Financial Statements in Part I,
Item 1 of this report for a discussion of competition and the rules regarding
the introduction of retail electric competition in Arizona and a settlement
agreement with the ACC.

     ENVIRONMENTAL MATTERS

     Purported Navajo Environmental Regulation

As previously reported, on June 29, 2000, at the request of the Court, APS filed
a motion to dismiss Four Corners from a Petition for Review of EPA's regulations
on the grounds that the impact of the regulations on pre-existing binding
agreements was not "ripe" for judicial resolution based on EPA's issuance of an
official notice indicating that it had not yet determined whether the
pre-existing binding agreements with Four Corners and NGS were abrogated by the
Clean Air Act. See "Environmental Matters--Purported Navajo Environmental
Regulation" in Part II, Item 5 of the June 10-Q. The Court recently dismissed
Four Corners on the above-mentioned grounds.

     WATER SUPPLY

As previously reported, APS and other parties petitioned the U.S. Supreme Court
for review of an Arizona Supreme Court decision regarding groundwater rights,
and an issue important to the claims to water in the Lower Gila River Watershed
in Arizona was pending on appeal before the Arizona Supreme Court. See
"Environmental Matters - Water Supply" in Part I - Item 1 of the 1999 10-K. The
U.S. Supreme Court denied the petition. In addition, the Arizona Supreme Court
issued a decision affirming the lower court's definition of groundwater. APS and
other parties have filed a motion for reconsideration on one aspect of that
decision.

     PURCHASED POWER AGREEMENTS

As previously reported, in July 2000 APS and PacifiCorp became involved in a
dispute relating to certain provisions of the Long-Term Power Transaction
Agreement dated September 1990. See "Purchased Power Agreements" in Part II,
Item 5 of the June 10-Q. APS and PacifiCorp have settled the issues related to
the dispute. The resolution of this matter will not have a material adverse
impact on our financial position or results of operations.
<PAGE>
                                      -31-

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

     (a)  Exhibits

          Exhibit No.       Description
          -----------       -----------
             10.1           Addendum to Settlement Agreement

             27.1           Financial Data Schedule

     In addition to those Exhibits shown above, the Company hereby incorporates
the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation
ss.229.10(d) by reference to the filings set forth below:

<TABLE>
<CAPTION>
EXHIBIT NO.     DESCRIPTION                      ORIGINALLY FILED AS EXHIBIT:    FILE NO(a)   DATE EFFECTIVE
-----------     -----------                      ----------------------------    ----------   --------------
<S>             <C>                              <C>                             <C>             <C>
    10.1        Articles of Incorporation        19.1 to the Company's           1-8962          11-14-88
                restated as of July 29, 1988     September 30, 1988
                                                 Form 10-Q Report

    10.2        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 September 30, 2000, and the period from October 1
through November 14, 2000, we filed the following reports on Form 8-K:

     Report dated July 12, 2000, relating to a preliminary ruling issued by a
Maricopa County Superior Court judge on cross-motions for summary judgment in
connection with lawsuits filed relating to the adoption or amendment of the
retail electric competition rules.

     Report dated October 26, 2000, regarding the written materials presented at
an analyst conference in Phoenix, Arizona.

----------
(a)  Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of
     the Securities and Exchange Commission located in Washington, D.C.
<PAGE>
                                      -32-

                                   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: November 14, 2000                By: Chris N. Froggatt
                                            ------------------------------------
                                            Chris N. Froggatt
                                            Vice President and Controller
                                            (Principal Accounting Officer
                                            and Officer Duly Authorized
                                            to sign this Report)
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.1
<SEQUENCE>2
<FILENAME>ex_10-1.txt
<DESCRIPTION>ADDENDUM TO SETTLEMENT AGREEMENT
<TEXT>

                                                                    Exhibit 10.1

                     [LETTERHEAD OF ARIZONA PUBLIC SERVICE]

                                December 1, 1999


Docket Control
Arizona Corporation Commission
1200 West Washington
Phoenix, Arizona 85007

     Re:  APS Settlement Proceeding
          ACC Docket Nos. E-01345A-98-0473, E-01345A-97-0773, RE-00000C-94-0165

Dear Sir or Madam:

     Pursuant to the Opinion and Order, Decision No. 61973 in the above
referenced Dockets, Arizona Public Service is filing an Addendum to the
Settlement Agreement incorporating the modifications required by that Decision.
This Addendum has been reviewed and executed by all signatories to the original
APS Settlement Agreement.

     If you have any questions regarding this filing, please contact me at
(602)250-2310.

                                        Sincerely,

                                        Jana Van Ness

                                        Jana Van Ness
                                        Manager
                                        State Regulations

Attachment

Cc:  Docket Control (18 copies plus original)
     Parties of Record
<PAGE>
                        ADDENDUM TO SETTLEMENT AGREEMENT

     This Addendum is to the Settlement Agreement dated May 14, 1999 (hereafter
"Agreement") between Arizona Public Service Company ("APS" or "Company") and the
various signatories to the Agreement (collectively with APS, the "Parties"). By
signing this Addendum to Settlement Agreement ("Addendum"), the Parties intend
to revise certain provisions of the Agreement as directed by the Arizona
Corporation Commission ("Commission") in Decision No. 61973 (October 6, 1999)
("Decision"). The Decision adopted and approved the Agreement subject to certain
modifications.

                                       I.
                            INTRODUCTION AND RECITALS

     1. On May 14, 1999, the Parties entered into the Agreement;

     2. On May 17, 1999, APS filed with the Commission a Notice of Filing
Application for Approval of Settlement Agreement and Request for Procedural
Order.

     3. Commencing on July 14, 1999, and pursuant to a Procedural Order issued
by the Hearing Division of the Commission, a full public evidentiary hearing on
the Agreement was conducted.

     4. On October 6, 1999, the Commission issued its Decision No. 61973
adopting and approving the Agreement as modified in the Decision.

     5. The Parties now wish to enter into this Addendum to revise the Agreement
as directed in the Decision.

                                       II.
                               ADDENDUM AGREEMENT

     1. METERING, METER READING, AND BILLING CREDITS

          A. The Company's revised unbundled rates and charges reflecting the
metering, meter reading, and billing credits required by the Decision are
attached hereto as Revised Exhibit A.

          B. The revised unbundled rates and charges in Revised Exhibit A to
this Addendum are substituted for the corresponding tariffs in Exhibit A to the
Agreement.

          C. Schedules A through C of Exhibit A to the Agreement are not
affected by this Addendum and were adopted and approved by the Commission in the
Decision as originally proposed in the Agreement.

                                        1
<PAGE>
     2. ADVANCED NOTICE FOR LARGE CUSTOMERS. Section 2.3 of the Agreement is
replaced with and superceded by the following provision:

          2.3. Customers greater than 3 MW who choose a direct access supplier
          must either (a) give APS one year's advance notice before being
          eligible to return to Standard Offer service, or (b) pay APS for all
          additional costs incurred as a result of the customer returning to
          Standard Offer service without providing APS at least one year's
          advance notice.

     3. DEFERRAL OF TRANSFER COSTS. Section 2.6(3) of the Agreement is replaced
with and superceded by the following provision:

          (3)  compliance with the Electric Competition Rules or
               Commission-ordered programs or directives related to the
               implementation of the Electric Competition Rules, as they may be
               amended from time to time, which costs shall be recovered from
               all customers receiving services from APS, provided however, that
               no more than sixty-seven percent (67%) of the costs to transfer
               generation assets to an affiliate or affiliates shall be allowed
               to be deferred for future collection under this provision; and

     4. RATE MATTERS. Section 2.8 of the Agreement is replaced with and
superceded by the following provision:

          2.8. Neither the Commission nor APS shall be prevented from seeking or
          authorizing a change in unbundled or Standard Offer rates prior to
          July 1, 2004, in the event of (a) conditions or circumstances which
          constitute an emergency, such as an inability to finance on reasonable
          terms, or (b) material changes in APS' cost of service for
          Commission-regulated services resulting from federal, tribal, state or
          local laws, regulatory requirements, judicial decisions, actions or
          orders. Except for the changes otherwise specifically contemplated by
          this Agreement, unbundled and Standard Offer rates shall remain
          unchanged until at least July 1, 2004.

                                        2
<PAGE>
     5. GENERATION AFFILIATE. Section 4.1 of the Agreement is replaced with and
superceded by the following provisions:

          4.1. Affiliates.

          (1)  The Commission will approve the formation of an affiliate or
               affiliates of APS to acquire at book value the competitive
               services and assets as currently required by the Electric
               Competition Rules. In order to facilitate the separation of such
               assets efficiently and at the lowest possible cost, the
               Commission shall grant APS a two-year extension of time until
               December 31, 2002, to accomplish such separation. A similar
               two-year extension shall be authorized for compliance with A.A.C.
               R14-2-1606(B).

          (2)  The affiliate or affiliates formed under this Section 4.1 shall
               be direct subsidiaries of Pinnacle West Capital Corporation, and
               not APS.

          (3)  After the extensions granted in this Section 4.1 have expired,
               APS shall procure generation for Standard Offer customers from
               the competitive market as provided for in the Electric
               Competition Rules. An affiliated generation company formed
               pursuant to this Section 4.1 may competitively bid for APS'
               Standard Offer load, but enjoys no automatic privilege outside of
               the market bid on account of its affiliation with APS.

     6. STATUTORY WAIVERS. Section 4.3 of the Agreement is deleted in its
entirety.

     7. WAIVERS OF AFFILIATE INTEREST RULES. The Revised Exhibit D to this
Addendum setting forth the Affiliate Rules Waivers is substituted for the
corresponding Exhibit D to the Agreement so that the proposed waiver of
R14-2-804(A) in the Agreement is deleted.

                                        3
<PAGE>
     8. CONFLICTS WITH ELECTRIC COMPETITION RULES. In reliance upon the
Commission's directive in Decision No. 61973 (page 9) that "We want to make it
clear that the Commission does not intend to revisit the stranded cost portion
of the Agreement. It is also not the Commission's intent to undermine the
benefits that parties have bargained for," Section 7.1 is replaced with and
superseded by the following provision:

          7.1. Approval of this Agreement by the Commission shall constitute a
          waiver of any existing Commission order, rule or regulation to the
          extent necessary to permit performance of the Agreement, as approved
          by the Commission. Any future Commission order, rule or regulation
          shall be construed and administered, insofar as possible, in a manner
          so as not to conflict with the specific provisions of this Agreement,
          as approved by the Commission. In the event any of the Parties deems a
          future Commission order, rule or regulation to be inconsistent with
          the specific provisions of this Agreement, a waiver of the new
          Commission order, rule or regulation shall be sought.

               Nothing in this Agreement is intended to otherwise interfere with
          the Commission's ability to exercise its regulatory authority by the
          issuance of orders, rules or regulations. The requirements of this
          Agreement shall be performed in accordance with the Commission's
          Electric Competition Rules including any specific waivers granted by
          the Commission's order approving this Agreement, except where a
          specific provision of this Agreement would excuse compliance.

     9. INTERIM CODE OF CONDUCT. Section 7.7 of the Agreement is replaced with
and superceded by the following provision:

          7.7. Within thirty (30) days of the date of the Commission decision
          approving this Agreement pursuant to Section 6.1, APS shall file an
          initial proposed Code of Conduct to address inter-affiliate
          relationships involving APS as a utility distribution company as
          required by the Electric Competition Rules and which includes
          provisions to govern the supply of generation during the two-year
          extension provided for by Section 4.1 of this Agreement. Interested
          parties may provide APS with comments on the initial proposed Code of
          Conduct within sixty (60) days of the date of the Commission decision
          approving this Agreement. APS will file a final proposed Code of
          Conduct for Commission approval within ninety (90) days of the date of
          the Commission decision approving this Agreement. Until the Commission
          approves a Code of Conduct for APS, APS will voluntarily comply with
          the initial proposed Code of Conduct or, once filed, the final
          proposed Code of Conduct.

                                        4
<PAGE>
     10. Effect of Addendum. Other than as specifically modified by this
Addendum, all provisions of the Agreement remain in full force and effect.

AGREED TO AS OF NOVEMBER 24, 1999:

RESIDENTIAL UTILITY                     ARIZONA PUBLIC SERVICE COMPANY
CONSUMER OFFICE


By Barbara Wytaske                      By Jack Davis
   -------------------------------         --------------------------------
Title Acting Director                   Title President Delivery & Sales
      ----------------------------            -----------------------------


ARIZONA COMMUNITY ACTION                (Party)
ASSOCIATION


By Betty Pruitt                         By
   -------------------------------         --------------------------------
Title Acting Executive Director         Title
      ----------------------------            -----------------------------

ARIZONANS FOR ELECTRIC CHOICE           (Party)
AND COMPETITION, a coalition of
companies and associations in support
of competition that includes Cable
Systems International, BHP Copper,      By
Motorola, Chemical Lime, Intel,            --------------------------------
Hughes, Honeywell, Allied Signal,       Title
Cyprus Climax Metals, Asarco, Phelps          -----------------------------
Dodge, Homebuilders of Central Arizona,
Arizona Mining Industry Gets Our
Support, Arizona Food Marketing
Alliance, Arizona Association of
Industries, Arizona Multi-housing
Association, Arizona Rock Products      (Party)
Association, Arizona Restaurant
Association, Arizona Retailers
Association, Boeing, Arizona School
Board Association, National Federation  By
of Independent Business, Arizona           --------------------------------
Hospital Association, Lockheed Martin,
Abbot Labs and Raytheon.                Title
                                              -----------------------------
By Stan Barnes
   -------------------------------
Title President
      ----------------------------

                                        5
<PAGE>
                                     Revised
                                    EXHIBIT D
                             Affiliate Rules Waivers

R14-2-801(5) and R14-2-803, such that the term "reorganization" does not
include, and no Commission approval is required for, corporate restructuring
that does not directly involve the utility distribution company ("UDC") in the
holding company. For example, the holding company may reorganize, form, buy or
sell non-UDC affiliates, acquire or divest interests in non-UDC affiliates,
etc., without Commission approval.

R14-2-805(A) shall apply only to the UDC

R14-2-805(A)(2)

R14-2-805(A)(6)

R14-2-805(A)(9), (10), and (11)

                      RECISION OF PRIOR COMMISSION ORDERS

Section X.C of the "Cogeneration and Small Power Production Policy" attached to
Decision No. 52345 (July 27, 1981) regarding reporting requirements for
cogeneration information.

Decision No. 55118 (July 24, 1986) - Page 15, Lines 5-1/2 through 13-1/2;
Finding of Fact No. 24 relating to reporting requirements under the abolished
PPFAC.

Decision No. 55818 (December 14, 1987) in its entirety. This decision related to
APS Schedule 9 (Industrial Development Rate) which was terminated by the
Commission in Decision No. 59329 (October 11, 1995).

9th and 10th Ordering Paragraphs of Decision No. 56450 (April 13, 1989)
regarding reporting requirements under the abolished PPFAC.
<PAGE>
                                                                          DA-GS1

                             ELECTRIC DELIVERY RATES

ARIZONA PUBLIC SERVICE COMPANY                     A.C.C. No. 5351
Phoenix, Arizona                                   Tariff or Schedule No. DA-GS1
Filed by:  Alan Propper                            Original Tariff
Title:  Director, Pricing and Regulation           Effective: October 1, 1999

                                  DIRECT ACCESS
                                 GENERAL SERVICE

AVAILABILITY

     This rate schedule is available in all certificated retail delivery service
territory served by Company at all points where facilities of adequate capacity
and the required phase and suitable voltage are adjacent to the premises served.

APPLICATION

     This rate schedule is applicable to customers receiving electric energy on
a direct access basis from any certificated Electric Service Provider (ESP) as
defined in A.A.C. R14-2-1603. This rate schedule is applicable to all electric
service required when such service is supplied at one point of delivery and
measured through one meter. For those customers whose electricity is delivered
through more than one meter, service for each meter shall be computed separately
under this rate unless conditions in accordance with the Company's Schedule #4
(Totalized Metering of Multiple Service Entrance Sections At a Single Premise
for Standard Offer and Direct Access Service) are met. For those service
locations where electric service has historically been measured through two
meters, when one of the meters was installed pursuant to a water heating rate
schedule no longer in effect, the electric service measured by such meters shall
be combined for billing purposes.

     This rate schedule shall become effective as defined in Company's Terms and
Conditions for Direct Access (Schedule #10).

     This rate schedule is not applicable to residential service, resale service
or direct access service which qualifies for Rate Schedule DA-GS10.

TYPE OF SERVICE

     Service shall be single or three phase, 60 Hertz, at one standard voltage
as may be selected by customer subject to availability at the customer's
premise. Three phase service is furnished under the Company's Conditions
Governing Extensions of Electric Distribution Lines and Services (Schedule #3).
Transformation equipment is included in cost of extension. Three phase service
is not furnished for motors of an individual rated capacity of less than 7-1/2
HP, except for existing facilities or where total aggregate HP of all connected
three phase motors exceed 12 HP. Three phase service is required for motors of
an individual rated capacity of more than 7-1/2 HP.

METERING REQUIREMENTS

     All customers shall comply with the terms and conditions for load profiling
or hourly metering specified in the Company's Schedule #10.

MONTHLY BILL

     The monthly bill shall be the greater of the amount computed under A. or B.
below, including the applicable Adjustments.

     A. RATE

     June - October Billing Cycles (Summer):

                                  Basic                             Competitive
                                 Delivery                 System     Transition
                                 Service   Distribution  Benefits      Charge
                                 -------   ------------  --------      ------
               $/month            $12.50

               Per kW over 5                $0.721

               Per kWh for the
               first 2,500 kWh              $0.04255

               Per kWh for the
               next 100 kWh
               per kW over 5                $0.04255

               Per kWh for the
               next 42,000 kWh              $0.02901

               Per kWh for all
               additional kWh               $0.01811

               Per all kWh                               $0.00115

               Per all kW                                              $2.43

                          (CONTINUED ON REVERSE SIDE)
<PAGE>
                                                                 DA-GS1
                                                                 A.C.C. No. 5351
                                                                 Page 2 of 3

     A. RATE (continued)

         November - May Billing Cycles (Winter):

                                  Basic                            Competitive
                                 Delivery                 System   Transition
                                 Service   Distribution  Benefits    Charge
                                 -------   ------------  --------    ------
               $/month            $12.50

               Per kW over 5                $0.652

               Per kWh for the
               first 2,500 kWh              $0.03827

               Per kWh for the
               next 100 kWh
               per kW over 5                $0.03827

               Per kWh for the              $0.02600
               next 42,000 kWh

               Per kWh for all              $0.01614
               additional  kWh

               Per all kWh                               $0.00115

               Per all kW                                             $2.43


                     PRIMARY AND TRANSMISSION LEVEL SERVICE:

     1.   For customers served at primary voltage (12.5kV to below 69kV), the
          Distribution charge will be discounted by 11.6%.

     2.   For customers served at transmission voltage (69kV or higher), the
          Distribution charge will be discounted 52.6%.

     3.   Pursuant to A.A.C. R14-2-1612.K.11, the Company shall retain ownership
          of Current Transformers (CT's) and Potential Transformers (PT's) for
          those customers taking service at voltage levels of more than 25kV.
          For customers whose metering services are provided by an ESP, a
          monthly facilities charge will be billed, in addition to all other
          applicable charges shown above, as determined in the service contract
          based upon the Company's cost of CT and PT ownership, maintenance and
          operation.

                               DETERMINATION OF KW

The kW used for billing purposes shall be the average kW supplied during the
15-minute period of maximum use during the month, as determined from readings of
the delivery meter.

     B. MINIMUM

     $12.50 plus $1.74 for each kW in excess of five of either the highest kW
     established during the 12 months ending with the current month or the
     minimum kW specified in the agreement for service, whichever is the
     greater.

                                   ADJUSTMENTS

     1.   When Metering, Meter Reading or Consolidated Billing are provided by
          the Customer's ESP, the monthly bill will be credited as follows:

                      Meter             $7.62 per month
                      Meter Reading     $1.69 per month
                      Billing           $1.33 per month

     2.   The monthly bill is also subject to the applicable proportionate part
          of any taxes, or governmental impositions which are or may in the
          future be assessed on the basis of gross revenues of the Company
          and/or the price or revenue from the electric service sold and/or the
          volume of energy delivered or purchased for sale and/or sold
          hereunder.

         SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS

     Customers served under this rate schedule are responsible for acquiring
their own generation and any other required competitively supplied services from
an ESP or under the Company's Open Access Transmission Tariff. The Company will
provide and bill its transmission and ancillary services on rates approved by
the Federal Energy Regulatory Commission to the Scheduling Coordinator who
provides transmission service to the Customer's ESP. The Customer's ESP must
submit a Direct Access Service Request pursuant to the terms and conditions in
Schedule #10.

                             (CONTINUED ON PAGE 3)
<PAGE>
ON-SITE GENERATION TERMS AND CONDITIONS

     Customers served under this rate schedule who have on-site generation
connected to the Company's electrical delivery grid shall enter into an
Agreement for Interconnection with the Company which shall establish all
pertinent details related to interconnection and other required service
standards. The Customer does not have the option to sell power and energy to the
Company under this tariff.

CONTRACT PERIOD

  0 - 1,999 kW:         As provided in Company's standard agreement for service.
  2,000 kW and above:   Three (3) years, or longer, at Company's option for
                        initial period when construction is required.  One (1)
                        year, or longer, at Company's option when construction
                        is not required.

TERMS AND CONDITIONS

     This rate schedule is subject to Company's Terms and Conditions for
Standard Offer and Direct Access Service (Schedule #1) and the Company's
Schedule #10. These Schedules have provisions that may affect customer's monthly
bill.
<PAGE>
                                                                       Exhibit A
                                                                           DA-R1

                             ELECTRIC DELIVERY RATES


ARIZONA PUBLIC SERVICE COMPANY                      A.C.C. No. 5350
Phoenix, Arizona                                    Tariff or Schedule No. DA-R1
Filed by:  Alan Propper                             Original Tariff
Title: Director, Pricing and Regulation             Effective: October 1, 1999

                                  DIRECT ACCESS
                               RESIDENTIAL SERVICE

AVAILABILITY

     This rate schedule is available in all certificated retail delivery service
territory served by Company and where facilities of adequate capacity and the
required phase and suitable voltage are adjacent to the premises served.

APPLICATION

     This rate schedule is applicable to customers receiving electric energy on
a direct access basis from any certificated Electric Service Provider (ESP) as
defined in A.A.C. R14-2-1603. This rate schedule is applicable only to electric
delivery required for residential purposes in individual private dwellings and
in individually metered apartments when such service is supplied at one point of
delivery and measured through one meter. For those dwellings and apartments
where electric service has historically been measured through two meters, when
one of the meters was installed pursuant to a water heating or space heating
rate schedule no longer in effect, the electric service measured by such meters
shall be combined for billing purposes.

     This rate schedule shall become effective as defined in Company's Terms and
Conditions for Direct Access (Schedule #10.)

TYPE OF SERVICE

     Service shall be single phase, 60 Hertz, at one standard voltage (120/240
or 120/208 as may be selected by customer subject to availability at the
customer's premise). Three phase service is furnished under the Company's
Conditions Governing Extensions of Electric Distribution Lines and Services
(Schedule #3). Transformation equipment is included in cost of extension. Three
phase service is required for motors of an individual rated capacity of 7-1/2 HP
or more.

METERING REQUIREMENTS

     All customers shall comply with the terms and conditions for load profiling
or hourly metering specified in Schedule #10.

MONTHLY BILL

     The monthly bill shall be the greater of the amount computed under A. or B.
below, including the applicable Adjustments.

     A. RATE

          May - October Billing Cycles (Summer):

                               Basic                            Competitive
                             Delivery                 System    Transition
                              Service   Distribution  Benefits    Charge
                              -------   ------------  --------    ------
               $/month        $10.00

               All kWh                   $0.04158     $0.00115   $0.00930


          November - April Billing Cycles (Winter):

                               Basic                            Competitive
                             Delivery                 System    Transition
                              Service   Distribution  Benefits    Charge
                              -------   ------------  --------    ------
               $/month        $10.00

               All kWh                   $0.03518     $0.00115   $0.00930



     B. MINIMUM $ 10.00 per month

                           (CONTINUED ON REVERSE SIDE)
<PAGE>
                                                                 DA-R1
                                                                 A.C.C. No. XXXX
                                                                 Page 2 of 2

     ADJUSTMENTS

          1.   When Metering, Meter Reading or Consolidated Billing are provided
               by the Customer's ESP, the monthly bill will be credited as
               follows:

                  Meter             $4.00 per month
                  Meter Reading     $1.69 per month
                  Billing           $1.33 per month

          2.   The monthly bill is also subject to the applicable proportionate
               part of any taxes, or governmental impositions which are or may
               in the future be assessed on the basis of gross revenues of the
               Company and/or the price or revenue from the electric service
               sold and/or the volume of energy delivered or purchased for sale
               and/or sold hereunder.

SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS

     Customers served under this rate schedule are responsible for acquiring
their own generation and any other required competitively supplied services from
an ESP. The Company will provide and bill its transmission and ancillary
services on rates approved by the Federal Energy Regulatory Commission to the
Scheduling Coordinator who provides transmission service to the Customer's ESP.
The Customer's ESP must submit a Direct Access Service Request pursuant to the
terms and conditions in Schedule #10.

ON-SITE GENERATION TERMS AND CONDITIONS

     Customers served under this rate schedule who have on-site generation
connected to the Company's electrical delivery grid shall enter into an
Agreement for Interconnection with the Company which shall establish all
pertinent details related to interconnection and other required service
standards. The Customer does not have the option to sell power and energy to the
Company under this tariff.

TERMS AND CONDITIONS

     This rate schedule is subject to the Company's Terms and Conditions for
Standard Offer and Direct Access Services (Schedule #1) and Schedule #10. These
schedules have provisions that may affect customer's monthly bill.
<PAGE>
                                                                       Exhibit A
                                                                         DA-GS10

                             ELECTRIC DELIVERY RATES


ARIZONA PUBLIC SERVICE COMPANY                    A.C.C. No. 5352
Phoenix, Arizona                                  Tariff or Schedule No. DA-GS10
Filed by:  Alan Propper                           Original Tariff
Title: Director, Pricing and Regulation           Effective: October 1, 1999

                                  DIRECT ACCESS
                           EXTRA LARGE GENERAL SERVICE

AVAILABILITY

     This rate schedule is available in all certificated retail delivery service
territory served by Company at all points where facilities of adequate capacity
and the required phase and suitable voltage are adjacent to the premises served.

APPLICATION

     This rate schedule is applicable to customers receiving electric energy on
a direct access basis from any certificated Electric Service Provider (ESP) as
defined in A.A.C. R14-2-1603. This rate schedule is applicable only to customers
whose monthly maximum demand is 3,000 kW or more for three (3) consecutive
months in any continuous twelve (12) month period ending with the current month.
Service must be supplied at one point of delivery and measured through one meter
unless otherwise specified by individual customer contract. For those customers
whose electricity is delivered through more than one meter, service for each
meter shall be computed separately under this rate unless conditions in
accordance with the Company's Schedule #4 (Totalized Metering of Multiple
Service Entrance Sections At a Single Premise for Standard Offer and Direct
Access Service) are met.

     This rate schedule is not applicable to resale service.

     This rate schedule shall become effective as defined in Company's Terms and
Conditions for Direct Access (Schedule #10).

TYPE OF SERVICE

     Service shall be three phase, 60 Hertz, at Company's standard voltages that
are available within the vicinity of customer's premise.

METERING REQUIREMENTS

     All customers shall comply with the terms and conditions for hourly
metering specified in Schedule #10.

MONTHLY BILL

     The monthly bill shall be the greater of the amount computed under A. or B.
below, including the applicable Adjustments.

     A. RATE

                                 Basic                             Competitive
                               Delivery                  System    Transition
                                Service   Distribution  Benefits     Charge
                                -------   ------------  --------     ------
                  $/month      $2,430.00

                  per kW                   $3.53                      $2.82

                  per kWh                  $0.00999     $0.00115


          PRIMARY AND TRANSMISSION LEVEL SERVICE:

          1.   For customers served at primary voltage (12.5kV to below 69kV),
               the Distribution charge will be discounted by 4.8%.

          2.   For customers served at transmission voltage (69kV or higher),
               the Distribution charge will be discounted 36.7%.

          3.   Pursuant to A.A.C. R14-2-1612.K.11, the Company shall retain
               ownership of Current Transformers (CT's) and Potential
               Transformers (PT's) for those customers taking service at voltage
               levels of more than 25 kV. For customers whose metering services
               are provided by an ESP, a monthly facilities charge will be
               billed, in addition to all other applicable charges shown above,
               as determined in the service contract based upon the Company's
               cost of CT and PT ownership, maintenance and operation.

          DETERMINATION OF KW

          The kW used for billing purposes shall be the greater of:

          1.   The kW used for billing purposes shall be the average kW supplied
               during the 15-minute period (or other period as specified by
               individual customer's contract) of maximum use during the month,
               as determined from readings of the delivery meter.

          2.   The minimum kW specified in the agreement for service or
               individual customer contract.

                           (CONTINUED ON REVERSE SIDE)
<PAGE>
                                                                 DA-GS10
                                                                 A.C.C. No. XXXX
                                                                 Page 2 of 2



     B. MINIMUM

          $2,430.00 per month plus $1.74 per kW per month.

         ADJUSTMENTS

          1.   When Metering, Meter Reading or Consolidated Billing are provided
               by the Customer's ESP, the monthly bill will be credited as
               follows:

                      Meter             $154.15 per month
                      Meter Reading     $  1.69 per month
                      Billing           $  1.33 per month

          2.   The monthly bill is also subject to the applicable proportionate
               part of any taxes, or governmental impositions which are or may
               in the future be assessed on the basis of gross revenues of the
               Company and/or the price or revenue from the electric service
               sold and/or the volume of energy delivered or purchased for sale
               and/or sold hereunder.

SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS

     Customers served under this rate schedule are responsible for acquiring
their own generation and any other required competitively supplied services from
an ESP. T he Company will provide and bill its transmission and ancillary
services on rates approved by the Federal Energy Regulatory Commission to the
Scheduling Coordinator who provides transmission service to the Customer's ESP.
The Customer's ESP must submit a Direct Access Service Request pursuant to the
terms and conditions in Schedule #10.

ON-SITE GENERATION TERMS AND CONDITIONS

     Customers served under this rate schedule who have on-site generation
connected to the Company's electrical delivery grid shall enter into an
Agreement for Interconnection with the Company which shall establish all
pertinent details related to interconnection and other required service
standards. The Customer does not have the option to sell power and energy to the
Company under this tariff.

CONTRACT PERIOD

          For service locations in:

          a)   Isolated Areas: Ten (10) years, or longer, at Company's option,
               with standard seven (7) year termination period.

          b)   Other Areas: Three (3) years, or longer, at Company's option.


TERMS AND CONDITIONS

     This rate schedule is subject to Company's Terms and Conditions for
Standard Offer and Direct Access Service (Schedule #1) and the Company's
Schedule #10. These schedules have provisions that may affect customer's monthly
bill.
<PAGE>
                                                                       Exhibit A
                                                                         DA-GS11
                             ELECTRIC DELIVERY RATES


ARIZONA PUBLIC SERVICE COMPANY                    A.C.C. No. 5395
Phoenix, Arizona                                  Tariff or Schedule No. DA-GS11
Filed by:  Alan Propper                           Original Tariff
Title: Director, Pricing and Regulation           Effective: October 1, 1999

                                  DIRECT ACCESS
                                 RALSTON PURINA

AVAILABILITY

     This rate schedule is available in all certificated retail delivery service
territory served by Company at all points where facilities of adequate capacity
and the required phase and suitable voltage are adjacent to the premises served.

APPLICATION

     This rate schedule is applicable only to Ralston Purina (Site #863970289)
when it receives electric energy on a direct access basis from any certificated
Electric Service Provider (ESP) as defined in A.A.C. R14-2-1603. Service must be
supplied as specified by individual customer contract and the Company's Schedule
#4 (Totalized Metering of Multiple Service Entrance Sections At a Single Premise
for Standard Offer and Direct Access Service).

     This rate schedule is not applicable to resale service.

     This rate schedule shall become effective as defined in Company's Terms and
Conditions for Direct Access (Schedule #10).

TYPE OF SERVICE

     Service shall be three phase, 60 Hertz, at 12.5 kV.

METERING REQUIREMENTS

     Customer shall comply with the terms and conditions for hourly metering
specified in Schedule #10.

MONTHLY BILL

     The monthly bill shall be the greater of the amount computed under A. or B.
below, including the applicable Adjustments.

     A. RATE

                                 Basic                             Competitive
                               Delivery                  System    Transition
                                Service   Distribution  Benefits     Charge
                                -------   ------------  --------     ------
                  $/month      $2,430.00

                  per kW                   $2.58                      $1.86

                  per kWh                  $0.00732     $0.00115


          DETERMINATION OF KW

          The kW used for billing purposes shall be the greater of:

          1.   The kW used for billing purposes shall be the average kW supplied
               during the 15-minute period (or other period as specified by
               individual customer's contract) of maximum use during the month,
               as determined from readings of the delivery meter.

          2.   The minimum kW specified in the agreement for service or
               individual customer contract.

     B. MINIMUM

          $2,430.00 per month plus $1.74 per kW per month.

          ADJUSTMENTS

          1.   When Metering, Meter Reading or Consolidated Billing are provided
               by the Customer's ESP, the monthly bill will be credited as
               follows:

                      Meter             $154.15 per month
                      Meter Reading     $  1.69 per month
                      Billing           $  1.33 per month

          2.   The monthly bill is also subject to the applicable proportionate
               part of any taxes, or governmental impositions which are or may
               in the future be assessed on the basis of gross revenues of the
               Company and/or the price or revenue from the electric service
               sold and/or the volume of energy delivered or purchased for sale
               and/or sold hereunder.

                           (CONTINUED ON REVERSE SIDE)
<PAGE>
                                                                 DA-GS11
                                                                 A.C.C. No. XXXX
                                                                 Page 2 of 2

SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS

     Customer is responsible for acquiring its own generation and any other
required competitively supplied services from an ESP. T he Company will provide
and bill its transmission and ancillary services on rates approved by the
Federal Energy Regulatory Commission to the Scheduling Coordinator who provides
transmission service to the Customer's ESP. The Customer's ESP must submit a
Direct Access Service Request pursuant to the terms and conditions in Schedule
#10.

ON-SITE GENERATION TERMS AND CONDITIONS

     If Customer has on-site generation connected to the Company's electrical
delivery grid, it shall enter into an Agreement for Interconnection with the
Company which shall establish all pertinent details related to interconnection
and other required service standards. The Customer does not have the option to
sell power and energy to the Company under this tariff.

TERMS AND CONDITIONS

     This rate schedule is subject to Company's Terms and Conditions for
Standard Offer and Direct Access Service (Schedule #1) and the Company's
Schedule #10. These schedules have provisions that may affect customer's monthly
bill.
<PAGE>
                                                                       Exhibit A
                                                                       DA-GS12

                             ELECTRIC DELIVERY RATES


ARIZONA PUBLIC SERVICE COMPANY                    A.C.C. No. 5396
Phoenix, Arizona                                  Tariff or Schedule No. DA-GS12
Filed by:  Alan Propper                           Original Tariff
Title: Director, Pricing and Regulation           Effective: October 1, 1999

                                  DIRECT ACCESS
                                   BHP COPPER

AVAILABILITY

     This rate schedule is available in all certificated retail delivery service
territory served by Company at all points where facilities of adequate capacity
and the required phase and suitable voltage are adjacent to the premises served.

APPLICATION

     This rate schedule is applicable only to BHP Copper (Site #774932285) when
it receives electric energy on a direct access basis from any certificated
Electric Service Provider (ESP) as defined in A.A.C. R14-2-1603. Service must be
supplied as specified by individual customer contract and the Company's Schedule
#4 (Totalized Metering of Multiple Service Entrance Sections At a Single Premise
for Standard Offer and Direct Access Service).

     This rate schedule is not applicable to resale service.

     This rate schedule shall become effective as defined in Company's Terms and
Conditions for Direct Access (Schedule #10).

TYPE OF SERVICE

     Service shall be three phase, 60 Hertz, at 12.5 kV or higher.

METERING REQUIREMENTS

     Customer shall comply with the terms and conditions for hourly metering
specified in Schedule #10.

MONTHLY BILL

     The monthly bill shall be the greater of the amount computed under A. or B.
below, including the applicable Adjustments.

     A. RATE

                                            Distribution
                     Basic    Distribution       at                  Competitive
                   Delivery   at Primary    Transmission    System    Transition
                    Service     Voltage       Voltage      Benefits     Charge
                    -------     -------       -------      --------     ------
        $/month    $2,430.00

        per kW                 $2.35          $1.22                      $1.54

        per kWh                $0.00665       $0.00346     $0.00115


          PRIMARY AND TRANSMISSION LEVEL SERVICE:

               Pursuant to A.A.C. R14-2-1612.K.11, the Company shall retain
               ownership of Current Transformers (CT's) and Potential
               Transformers (PT's) for those customers taking service at voltage
               levels of more than 25 kV. For customers whose metering services
               are provided by an ESP, a monthly facilities charge will be
               billed, in addition to all other applicable charges shown above,
               as determined in the service contract based upon the Company's
               cost of CT and PT ownership, maintenance and operation.

          DETERMINATION OF KW

          The kW used for billing purposes shall be the greater of:

          1.   The kW used for billing purposes shall be the average kW supplied
               during the 30-minute period (or other period as specified by
               individual customer's contract) of maximum use during the month,
               as determined from readings of the delivery meter.

          2.   The minimum kW specified in the agreement for service or
               individual customer contract.

     B. MINIMUM

          $2,430.00 per month plus $1.74 per kW per month.

                           (CONTINUED ON REVERSE SIDE)
<PAGE>
                                                                 DA-GS12
                                                                 A.C.C. No. XXXX
                                                                 Page 2 of 2

     ADJUSTMENTS

          1.   When Metering, Meter Reading or Consolidated Billing are provided
               by the Customer's ESP, the monthly bill will be credited as
               follows:

                      Meter             $154.15 per month
                      Meter Reading     $  1.69 per month
                      Billing           $  1.33 per month

          2.   The monthly bill is also subject to the applicable proportionate
               part of any taxes, or governmental impositions which are or may
               in the future be assessed on the basis of gross revenues of the
               Company and/or the price or revenue from the electric service
               sold and/or the volume of energy delivered or purchased for sale
               and/or sold hereunder.

SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS

     Customer is responsible for acquiring its own generation and any other
required competitively supplied services from an ESP. T he Company will provide
and bill its transmission and ancillary services on rates approved by the
Federal Energy Regulatory Commission to the Scheduling Coordinator who provides
transmission service to the Customer's ESP. The Customer's ESP must submit a
Direct Access Service Request pursuant to the terms and conditions in Schedule
#10.

ON-SITE GENERATION TERMS AND CONDITIONS

     If Customer has on-site generation connected to the Company's electrical
delivery grid, it shall enter into an Agreement for Interconnection with the
Company which shall establish all pertinent details related to interconnection
and other required service standards. The Customer does not have the option to
sell power and energy to the Company under this tariff.

TERMS AND CONDITIONS

     This rate schedule is subject to Company's Terms and Conditions for
Standard Offer and Direct Access Service (Schedule #1) and the Company's
Schedule #10. These schedules have provisions that may affect customer's monthly
bill.
<PAGE>
                                                                       Exhibit A
                                                                         DA-GS13
                             ELECTRIC DELIVERY RATES

ARIZONA PUBLIC SERVICE COMPANY                    A.C.C. No. 5397
Phoenix, Arizona                                  Tariff or Schedule No. DA-GS13
Filed by:  Alan Propper                           Original Tariff
Title: Director, Pricing and Regulation           Effective: October 1, 1999

                                  DIRECT ACCESS
                                  CYPRUS BAGDAD

AVAILABILITY

     This rate schedule is available in all certificated retail delivery service
territory served by Company at all points where facilities of adequate capacity
and the required phase and suitable voltage are adjacent to the premises served.

APPLICATION

     This rate schedule is applicable only to Cyprus Bagdad (Site #120932284)
when it receives electric energy on a direct access basis from any certificated
Electric Service Provider (ESP) as defined in A.A.C. R14-2-1603. Service must be
supplied as specified by individual customer contract and the Company's Schedule
#4 (Totalized Metering of Multiple Service Entrance Sections At a Single Premise
for Standard Offer and Direct Access Service).

     This rate schedule is not applicable to resale service.

     This rate schedule shall become effective as defined in Company's Terms and
Conditions for Direct Access (Schedule #10).

TYPE OF SERVICE

     Service shall be three phase, 60 Hertz, at 115 kV or higher.

METERING REQUIREMENTS

     Customer shall comply with the terms and conditions for hourly metering
specified in Schedule #10.

MONTHLY BILL

     The monthly bill shall be the greater of the amount computed under A. or B.
below, including the applicable Adjustments.

     A. RATE

                                 Basic                             Competitive
                               Delivery                  System    Transition
                                Service   Distribution  Benefits     Charge
                                -------   ------------  --------     ------
                  $/month      $2,430.00

                  per kW                   $1.05                      $1.34

                  per kWh                  $0.00298     $0.00115


          PRIMARY AND TRANSMISSION LEVEL SERVICE:

               Pursuant to A.A.C. R14-2-1612.K.11, the Company shall retain
               ownership of Current Transformers (CT's) and Potential
               Transformers (PT's) for those customers taking service at voltage
               levels of more than 25 kV. For customers whose metering services
               are provided by an ESP, a monthly facilities charge will be
               billed, in addition to all other applicable charges shown above,
               as determined in the service contract based upon the Company's
               cost of CT and PT ownership, maintenance and operation.

          DETERMINATION OF KW

          The kW used for billing purposes shall be the greater of:

          1.   The kW used for billing purposes shall be the average kW supplied
               during the 30-minute period (or other period as specified by
               individual customer's contract) of maximum use during the month,
               as determined from readings of the delivery meter.

          2.   The minimum kW specified in the agreement for service or
               individual customer contract.

     B. MINIMUM

          $2,430.00 per month plus $1.74 per kW per month, until June 30, 2004
          when this minimum will no longer be applicable.

                           (CONTINUED ON REVERSE SIDE)
<PAGE>
                                                                 DA-GS13
                                                                 A.C.C. No. XXXX
                                                                 Page 2 of 2

          ADJUSTMENTS

          1.   When Metering, Meter Reading or Consolidated Billing are provided
               by the Customer's ESP, the monthly bill will be credited as
               follows:

                      Meter             $154.15 per month
                      Meter Reading     $  1.69 per month
                      Billing           $  1.33 per month

          2.   The monthly bill is also subject to the applicable proportionate
               part of any taxes, or governmental impositions which are or may
               in the future be assessed on the basis of gross revenues of the
               Company and/or the price or revenue from the electric service
               sold and/or the volume of energy delivered or purchased for sale
               and/or sold hereunder.

SERVICES ACQUIRED FROM CERTIFICATED ELECTRIC SERVICE PROVIDERS

     Customer is responsible for acquiring its own generation and any other
required competitively supplied services from an ESP. T he Company will provide
and bill its transmission and ancillary services on rates approved by the
Federal Energy Regulatory Commission to the Scheduling Coordinator who provides
transmission service to the Customer's ESP. The Customer's ESP must submit a
Direct Access Service Request pursuant to the terms and conditions in Schedule
#10.

ON-SITE GENERATION TERMS AND CONDITIONS

     If Customer has on-site generation connected to the Company's electrical
delivery grid, it shall enter into an Agreement for Interconnection with the
Company which shall establish all pertinent details related to interconnection
and other required service standards. The Customer does not have the option to
sell power and energy to the Company under this tariff.

TERMS AND CONDITIONS

     This rate schedule is subject to Company's Terms and Conditions for
Standard Offer and Direct Access Service (Schedule #1) and the Company's
Schedule #10. These schedules have provisions that may affect customer's monthly
bill.
<PAGE>
                                                                       Exhibit A
                                                                         5/13/99
                                                                      Schedule A

                         ARIZONA PUBLIC SERVICE COMPANY

                         Competitive Transition Charges
                          By Direct Access Rate Classes


<TABLE>
<CAPTION>
                                               Competition Transition Charges Effective January 1 of
Line                                          ---------------------------------------------------------
 #           Direct Access Rate Class          1999      2000      2001      2002      2003      2004
----         ------------------------         -------   -------   -------   -------   -------   -------
<S>    <C>                                    <C>       <C>       <C>       <C>       <C>       <C>
 1     Residential, DA-R1 (per kWh)           $0.0093   $0.0084   $0.0063   $0.0056   $0.0050   $0.0036
 2     Under 3 mW, DA-GS1, (per kW/mo.)       $  2.43   $  2.20   $  1.66   $  1.46   $  1.30   $  0.94
 3     3 mW and Above, DA-GS10 (per kW/mo.)   $  2.82   $  2.55   $  1.89   $  1.72   $  1.51   $  1.09
 4     BHP Copper (per kW/mo.)                $  1.54   $  1.53   $  1.06   $  0.95   $  0.83   $  0.61
 5     Cyprus Copper (per kW/mo.)             $  1.34   $  1.46   $  1.05   $  0.94   $  0.82   $  0.61
 6     Ralston Purina (per kW/mo.)            $  1.86   $  1.98   $  1.50   $  1.34   $  1.18   $  0.87

 7     Average Retail (per kWh)               $0.0067   $0.0061   $0.0054   $0.0048   $0.0043   $0.0031
</TABLE>

Charges are based upon recovery of $350 million NPV derived from APS' Compliance
Filing of 8/21/98 as adjusted to synchronize Direct Access and Standard Offer
revenue decreases.
<PAGE>
                         ARIZONA PUBLIC SERVICE COMPANY
                              Distribution Charges
                         By Direct Access Rate Classes

<TABLE>
<CAPTION>
                                                                       Distribution Charges Effective January 1 of
Line                                                       --------------------------------------------------------------------
 #                     Direct Access Rate Class              1999        2000        2001        2002        2003       2004(a)
----                   ------------------------            --------    --------    --------    --------    --------    --------
<S>  <C>                                                   <C>         <C>         <C>         <C>         <C>         <C>
     RESIDENTIAL, DA-R1
 1          Summer per kWh                                 $0.04158    $0.04041    $0.03934    $0.03837    $0.03748    $0.03689
 2          Winter per kWh                                 $0.03518    $0.03419    $0.03329    $0.03247    $0.03172    $0.03122

     DA-GS1 (UNDER 3 MW)
        Summer Rates
 3           per kW for all kW over 5                      $  0.721    $  0.691    $  0.663    $  0.638    $  0.615    $  0.600
 4           per kWh for the first 2,500 kWh               $0.04255    $0.04075    $0.03912    $0.03763    $0.03627    $0.03537
 5           per kWh for the next 100 kWh per kW over 5    $0.04255    $0.04075    $0.03912    $0.03763    $0.03627    $0.03537
 6           per kWh for the next 42,000 kWh               $0.02901    $0.02779    $0.02667    $0.02565    $0.02473    $0.02411
 7           per kWh for all additional kWh                $0.01811    $0.01735    $0.01665    $0.01602    $0.01544    $0.01506
        Winter Rates
 8           per kW for all kW over 5                      $  0.652    $  0.624    $  0.599     $ 0.576    $  0.555    $  0.541
 9           per kWh for the first 2,500 kWh               $0.03827    $0.03666    $0.03519    $0.03385    $0.03263    $0.03182
 10          per kWh for the next 100 kWh per kW over 5    $0.03827    $0.03666    $0.03519    $0.03385    $0.03263    $0.03182
 11          per kWh for the next 42,000 kWh               $0.02600    $0.02490    $0.02390    $0.02299    $0.02216    $0.02161
 12          per kWh for all additional kWh                $0.01614    $0.01546    $0.01484    $0.01427    $0.01376    $0.01342
        Voltage Discounts
 13         Primary Voltage                                    11.6%       12.1%       12.6%       13.1%       13.6%       13.9%
 14         Transmission Voltage                               52.6%       54.9%       57.2%       59.5%       61.7%       63.3%

     DA-GS10 (3 MW AND ABOVE)
 15         per kW                                         $   3.53    $   3.33    $   3.15    $   2.98    $   2.83    $   2.73
 16         per kWh                                        $0.00999    $0.00943    $0.00892    $0.00845    $0.00802    $0.00774
        Voltage Discounts
 17         Primary Voltage Discount                            4.8%        5.1%        5.3%        5.6%        5.9%        6.2%
 18         Transmission Voltage Discount                      36.7%       38.9%       41.1%       43.4%       45.8%       47.4%

     DA-GS11 (RALSTON PURINA)
 19         per kW                                         $   2.58    $   2.71    $   2.57    $   2.44    $   2.32    $   2.25
 20         per kWh                                        $0.00732    $0.00767    $0.00727    $0.00691    $0.00657    $0.00635

     DA-GS12 (BHP COPPER)
 21     Primary Voltage Delivery - per kW                  $   2.35    $   2.30    $   2.16    $   2.07    $   1.99    $   1.93
 22                                per kWh                 $0.00665    $0.00651    $0.00611    $0.00585    $0.00561    $0.00546
 23     Transmission Voltage Delivery - per kW             $   1.22    $   1.17    $   1.03    $   0.94    $   0.85    $   0.80
 24                                     per kWh            $0.00346    $0.00332    $0.00292    $0.00266    $0.00242    $0.00227

     DA-GS13 (CYPRUS BAGDAD)
 25         per kW                                         $   1.05    $   1.21    $   1.03    $   0.94    $   0.85    $   0.80
 26         per kWh                                        $0.00297    $0.00343    $0.00292    $0.00266    $0.00242    $0.00227
</TABLE>

(a)  Transmission voltage customers will not pay Distribution Charges after June
     30, 2004
<PAGE>
                                                                       Exhibit A
                                                                         5/14/99
                                                                      Schedule C


                         ARIZONA PUBLIC SERVICE COMPANY

                     Regulatory Asset Amortization Schedule
                              (Millions of Dollars)


                                                         1/1 - 6/30
1999        2000        2001       2002        2003       2004(1)       Total(2)
----        ----        ----       ----        ----       -------       --------
164         158         145        115          86          18            686


(1)  Amortization ends 6/30/2004
(2)  Includes the disallowance from Section 3.3
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-27
<SEQUENCE>3
<FILENAME>fds.xfd
<DESCRIPTION>FINANCIAL DATA SCHEDULE
<TEXT>

<TABLE> <S> <C>

<ARTICLE>    UT

<S>                                                      <C>
<PERIOD-TYPE>                                          9-MOS
<PERIOD-START>                                   Jan-01-2000
<FISCAL-YEAR-END>                                Dec-31-2000
<PERIOD-END>                                     Sep-30-2000
<BOOK-VALUE>                                        PER-BOOK
<TOTAL-NET-UTILITY-PLANT>                          4,947,162
<OTHER-PROPERTY-AND-INVEST>                          615,543
<TOTAL-CURRENT-ASSETS>                             1,038,526
<TOTAL-DEFERRED-CHARGES>                             573,549
<OTHER-ASSETS>                                             0
<TOTAL-ASSETS>                                     7,174,780
<COMMON>                                           1,536,493
<CAPITAL-SURPLUS-PAID-IN>                                  0
<RETAINED-EARNINGS>                                  839,339
<TOTAL-COMMON-STOCKHOLDERS-EQ>                     2,375,832
<PREFERRED-MANDATORY>                                      0
<PREFERRED>                                                0
<LONG-TERM-DEBT-NET>                               2,354,911
<SHORT-TERM-NOTES>                                         0
<LONG-TERM-NOTES-PAYABLE>                                  0
<COMMERCIAL-PAPER-OBLIGATIONS>                         1,984
<LONG-TERM-DEBT-CURRENT-PORT>                          4,887
<PREFERRED-STOCK-CURRENT>                                  0
<CAPITAL-LEASE-OBLIGATIONS>                                0
<LEASES-CURRENT>                                           0
<OTHER-ITEMS-CAPITAL-AND-LIAB>                     2,437,166
<TOT-CAPITALIZATION-AND-LIAB>                      7,174,780
<GROSS-OPERATING-REVENUE>                          2,852,021
<INCOME-TAX-EXPENSE>                                 194,069
<OTHER-OPERATING-EXPENSES>                           803,378
<TOTAL-OPERATING-EXPENSES>                         2,298,596
<OPERATING-INCOME-LOSS>                              553,425
<OTHER-INCOME-NET>                                    13,785
<INCOME-BEFORE-INTEREST-EXPEN>                             0
<TOTAL-INTEREST-EXPENSE>                             113,121
<NET-INCOME>                                         260,020
<PREFERRED-STOCK-DIVIDENDS>                                0
<EARNINGS-AVAILABLE-FOR-COMM>                        260,020
<COMMON-STOCK-DIVIDENDS>                              88,963
<TOTAL-INTEREST-ON-BONDS>                             68,491
<CASH-FLOW-OPERATIONS>                               552,979
<EPS-BASIC>                                             3.07
<EPS-DILUTED>                                           3.06


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