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, 1999

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

For the transition period from __________ to __________

Commission file number 1-4473

ARIZONA PUBLIC SERVICE COMPANY
------------------------------------------------------
(Exact name of registrant as specified in its charter)

Arizona 86-0011170
------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.

Yes [X] No [ ]

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

Number of shares of common stock, $2.50 par value,
outstanding as of November 15, 1999: 71,264,947

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(A) AND
(B) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE
FORMAT.

Glossary

ACC - Arizona Corporation Commission

ACC Staff - Staff of the Arizona Corporation Commission

Company - Arizona Public Service Company

DOE - United States Department of Energy

EITF - Emerging Issues Task Force

EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the
Pricing of Electricity -- Issues Related to the 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"

EPA - Environmental Protection Agency

FASB - Financial Accounting Standards Board

FERC - Federal Energy Regulatory Commission

Four Corners - Four Corners Power Plant

ITC - Investment tax credit

June 10-Q - Arizona Public Service Company Quarterly Report on Form 10-Q for the
fiscal quarter ended June 30, 1999

NGS - Navajo Generating Station

1998 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 1998

Palo Verde - Palo Verde Nuclear Generating Station

Pinnacle West - Pinnacle West Capital Corporation

Power Coordination Agreement - 1955 agreement between the Company and Salt River
Project that provides for certain electric system and power sales

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

Territorial Agreement - 1955 agreement between the Company and Salt River
Project that has provided exclusive retail service territories in Arizona for
each party

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)

Three Months
Ended September 30,
----------------------
1999 1998
--------- ---------
(Thousands of Dollars)

ELECTRIC OPERATING REVENUES .......................... $ 867,504 $ 740,734
--------- ---------
FUEL EXPENSES:
Fuel for electric generation ....................... 68,137 74,112
Purchased power .................................... 328,270 178,587
--------- ---------
Total ........................................... 396,407 252,699
--------- ---------
OPERATING REVENUES LESS FUEL EXPENSES ................ 471,097 488,035
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses . 108,264 110,259
Depreciation and amortization ...................... 94,184 94,284
Income taxes ....................................... 92,286 98,411
Other taxes ........................................ 25,449 30,002
--------- ---------
Total ........................................... 320,183 332,956
--------- ---------
OPERATING INCOME ..................................... 150,914 155,079
--------- ---------
OTHER INCOME (DEDUCTIONS):
Other - net ........................................ 620 (2,120)
Income taxes ....................................... 13,283 14,271
--------- ---------
Total ........................................... 13,903 12,151
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS .................... 164,817 167,230
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ......................... 31,409 33,906
Interest on short-term borrowings .................. 2,775 2,359
Debt discount, premium and expense ................. 1,847 1,878
Capitalized interest ............................... (722) (4,106)
--------- ---------
Total ........................................... 35,309 34,037
--------- ---------
INCOME BEFORE EXTRAORDINARY CHARGE ................... 129,508 133,193

EXTRAORDINARY CHARGE - NET OF INCOME TAXES OF $94,115 139,885 --
--------- ---------
NET INCOME (LOSS) .................................... (10,377) 133,193

PREFERRED STOCK DIVIDEND REQUIREMENTS ................ -- 2,347
--------- ---------
EARNINGS (LOSS) FOR COMMON STOCK ..................... $ (10,377) $ 130,846
========= =========

See Notes to Condensed Financial Statements.

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)

Nine Months
Ended September 30,
--------------------------
1999 1998
----------- -----------
(Thousands of Dollars)

ELECTRIC OPERATING REVENUES ......................... $ 1,792,921 $ 1,562,872
----------- -----------
FUEL EXPENSES:
Fuel for electric generation ...................... 178,536 174,874
Purchased power ................................... 449,655 247,327
----------- -----------
Total .......................................... 628,191 422,201
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES ............... 1,164,730 1,140,671
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses 310,072 309,388
Depreciation and amortization ..................... 286,856 279,097
Income taxes ...................................... 166,945 162,808
Other taxes ....................................... 84,484 89,459
----------- -----------
Total .......................................... 848,357 840,752
----------- -----------
OPERATING INCOME .................................... 316,373 299,919
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net ....................................... (3,799) (7,035)
Income taxes ...................................... 24,765 26,214
----------- -----------
Total .......................................... 20,966 19,179
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ................... 337,339 319,098
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................ 98,833 103,249
Interest on short-term borrowings ................. 6,779 5,419
Debt discount, premium and expense ................ 5,604 5,745
Capitalized interest .............................. (6,721) (12,627)
----------- -----------
Total .......................................... 104,495 101,786
----------- -----------
INCOME BEFORE EXTRAORDINARY CHARGE .................. 232,844 217,312

EXTRAORDINARY CHARGE - NET OF INCOME TAXES OF $94,115 139,885 --
----------- -----------
NET INCOME .......................................... 92,959 217,312

PREFERRED STOCK DIVIDEND REQUIREMENTS ............... 1,016 7,660
----------- -----------
EARNINGS FOR COMMON STOCK ........................... $ 91,943 $ 209,652
=========== ===========

See Notes to Condensed Financial Statements

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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)

Twelve Months
Ended September 30,
--------------------------
1999 1998
----------- -----------
(Thousands of Dollars)

ELECTRIC OPERATING REVENUES ......................... $ 2,236,447 $ 1,970,832
----------- -----------
FUEL EXPENSES:
Fuel for electric generation ...................... 235,629 221,089
Purchased power ................................... 507,862 294,430
----------- -----------
Total .......................................... 743,491 515,519
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES ............... 1,492,956 1,455,313
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses 414,725 421,542
Depreciation and amortization ..................... 384,333 370,741
Income taxes ...................................... 196,344 183,479
Other taxes ....................................... 110,289 119,844
----------- -----------
Total .......................................... 1,105,691 1,095,606
----------- -----------
OPERATING INCOME .................................... 387,265 359,707
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net ....................................... (9,067) (14,188)
Income taxes ...................................... 31,302 32,685
----------- -----------
Total .......................................... 22,235 18,497
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ................... 409,500 378,204
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ........................ 132,798 138,790
Interest on short-term borrowings ................. 8,841 7,237
Debt discount, premium and expense ................ 7,439 7,653
Capitalized interest .............................. (10,357) (16,444)
----------- -----------
Total .......................................... 138,721 137,236
----------- -----------
INCOME BEFORE EXTRAORDINARY CHARGE .................. 270,779 240,968

EXTRAORDINARY CHARGE - NET OF INCOME TAXES OF $94,115 139,885 --
----------- -----------
NET INCOME .......................................... 130,894 240,968

PREFERRED STOCK DIVIDEND REQUIREMENTS ............... 3,059 10,658
----------- -----------
EARNINGS FOR COMMON STOCK ........................... $ 127,835 $ 230,310
=========== ===========

See Notes to Condensed Financial Statements.

-5-

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS

ASSETS

September 30, December 31,
1999 1998
(Unaudited)
----------- -----------
(Thousands of Dollars)
UTILITY PLANT:
Electric plant in service and held for future use $ 7,475,666 $ 7,265,604
Less accumulated depreciation and amortization ... 3,005,785 2,814,762
----------- -----------
Total ......................................... 4,469,881 4,450,842
Construction work in progress .................... 204,000 228,643
Nuclear fuel, net of amortization ................ 53,560 51,078
----------- -----------
Utility plant - net ........................... 4,727,441 4,730,563
----------- -----------
INVESTMENTS AND OTHER ASSETS ..................... 212,517 183,549
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents ........................ 4,867 5,558
Accounts receivable:
Service customers ............................. 312,927 205,999
Other ......................................... 18,316 23,213
Allowance for doubtful accounts ............... (1,441) (1,725)
Accrued utility revenues ......................... 101,283 67,740
Materials and supplies, at average cost .......... 69,897 69,074
Fossil fuel, at average cost ..................... 17,913 13,978
Deferred income taxes ............................ 3,999 3,999
Other ............................................ 28,869 26,695
----------- -----------
Total current assets .......................... 556,630 414,531
----------- -----------
DEFERRED DEBITS:
Regulatory assets ................................ 648,377 980,084
Unamortized debt issue costs ..................... 14,883 14,916
Other ............................................ 93,902 69,656
----------- -----------
Total deferred debits ......................... 757,162 1,064,656
----------- -----------
TOTAL ......................................... $ 6,253,750 $ 6,393,299
=========== ===========

See Notes to Condensed Financial Statements.

-6-

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS

LIABILITIES

September 30, December 31,
1999 1998
(Unaudited)
---------- ----------
(Thousands of Dollars)
CAPITALIZATION:
Common stock ....................................... $ 178,162 $ 178,162
Additional paid-in capital ......................... 1,196,804 1,195,625
Retained earnings .................................. 565,230 601,968
---------- ----------
Common stock equity ............................. 1,940,196 1,975,755
Non-redeemable preferred stock ..................... -- 85,840
Redeemable preferred stock ......................... -- 9,401
Long-term debt less current maturities ............. 1,812,262 1,876,540
---------- ----------
Total capitalization ............................ 3,752,458 3,947,536
---------- ----------
CURRENT LIABILITIES:
Commercial paper ................................... 223,500 178,830
Current maturities of long-term debt ............... 114,542 164,378
Accounts payable ................................... 228,386 145,139
Accrued taxes ...................................... 185,974 59,827
Accrued interest ................................... 22,380 31,218
Customer deposits .................................. 23,728 26,815
Other .............................................. 27,266 16,755
---------- ----------
Total current liabilities ....................... 825,776 622,962
---------- ----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes .............................. 1,180,246 1,312,007
Deferred investment tax credit ..................... 8,962 32,465
Unamortized gain - sale of utility plant ........... 74,355 77,787
Customer advances for construction ................. 38,080 31,451
Other .............................................. 373,873 369,091
---------- ----------
Total deferred credits and other ................ 1,675,516 1,822,801
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 6, 8 and 9)

TOTAL ........................................... $6,253,750 $6,393,299
========== ==========

See Notes to Condensed Financial Statements.

-7-

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months
Ended September 30,
----------------------
1999 1998
--------- ---------
(Thousands of Dollars)
Cash Flows from Operating Activities:
Net income ......................................... $ 92,959 $ 217,312
Items not requiring cash:
Depreciation and amortization .................... 286,856 279,097
Nuclear fuel amortization ........................ 24,306 24,991
Deferred income taxes - net ...................... (30,977) (47,749)
Deferred investment tax credit - net ............. (23,503) (23,369)
Extraordinary charge, net of income taxes ........ 139,885 --
Changes in certain current assets and liabilities:
Accounts receivable - net ........................ (102,315) (118,843)
Accrued utility revenues ......................... (33,543) (27,594)
Materials, supplies and fossil fuel .............. (4,758) (8,944)
Other current assets ............................. (2,174) (3,103)
Accounts payable ................................. 78,937 61,611
Accrued taxes .................................... 126,147 122,709
Accrued interest ................................. (8,838) (5,171)
Other current liabilities ........................ 7,897 16,799
Other - net ........................................ (18,750) (20,778)
--------- ---------
Net cash flow provided by operating activities ....... 532,129 466,968
--------- ---------
Cash Flows from Investing Activities:
Capital expenditures ............................... (228,540) (221,904)
Capitalized interest ............................... (6,721) (12,627)
Other .............................................. 592 (5,872)
--------- ---------
Net cash flow used for investing activities .... (234,669) (240,403)
--------- ---------
Cash Flows from Financing Activities:
Long-term debt ..................................... 142,952 109,375
Short-term borrowings - net ........................ 44,670 (15,400)
Dividends paid on common stock ..................... (127,500) (127,500)
Dividends paid on preferred stock .................. (1,393) (8,070)
Repayment of preferred stock ....................... (96,499) (37,585)
Repayment and reacquisition of long-term debt ...... (260,381) (142,250)
--------- ---------
Net cash flow used for financing activities .... (298,151) (221,430)
--------- ---------
Net increase (decrease) in cash and cash equivalents . (691) 5,135
Cash and cash equivalents at beginning of period ..... 5,558 12,552
--------- ---------
Cash and cash equivalents at end of period ........... $ 4,867 $ 17,687
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ........ $ 107,677 $ 100,929
Income taxes ..................................... $ 102,299 $ 115,585

See Notes to Condensed Financial Statements.

-8-

ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED FINANCIAL STATEMENTS

1. Our condensed 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 exception of the extraordinary item. We suggest that these
condensed financial statements and notes to condensed financial statements be
read along with the financial statements and notes to financial statements
included in our 1998 10-K. We have reclassified certain prior year amounts for
comparison purposes with 1999.

2. Weather conditions can have a significant impact on our results for interim
periods. For this and other reasons, results for interim periods do not
necessarily represent results to be expected for the year.

3. We are a wholly-owned subsidiary of Pinnacle West.

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, 1999.

5. Regulatory Accounting

For our regulated operations, we prepare our financial statements in accordance
with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based,
rate-regulated enterprise to reflect the impact of regulatory decisions in its
financial statements.

During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting
Standards Board (FASB) issued EITF 97-4. EITF 97-4 requires that SFAS No. 71 be
discontinued no later than when legislation is passed or a rate order is issued
that contains sufficient detail to determine its effect on the portion of the
business being deregulated.

In September 1999, our Settlement Agreement with the ACC was approved (see Note
6 for a discussion of the agreement), and, as a result, we have discontinued the
application of SFAS No. 71 for our generation operations. This meant that
regulatory assets, unless reestablished as recoverable through ongoing regulated
cash flows, were eliminated and the generation assets were tested for
impairment. We determined that the generation assets were not impaired. A
regulatory disallowance, which removed $234 million pretax ($183 million net
present value) from ongoing regulatory cash flows, was recorded as a net
reduction of regulatory assets. This reduction ($140 million after income taxes)
was reported as an extraordinary charge on the income

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statement. The regulatory assets to be recovered under this Settlement Agreement
will be amortized as follows:

(Millions)

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

The condensed balance sheets include the amounts listed below for generation
assets included in utility plant not subject to SFAS No. 71:

(Thousands of Dollars)

September 30, December 31,
1999 1998
----------- -----------
Electric plant in service and held for future use $ 3,730,840 $ 3,680,482
Accumulated depreciation and amortization (1,793,288) (1,681,099)
Construction work in progress 85,638 107,324
Nuclear fuel, net of amortization 53,560 51,078

6. Regulatory Matters -- Electric Industry Restructuring

STATE

SETTLEMENT AGREEMENT As of May 14, 1999, we entered into a comprehensive
Settlement Agreement with various other 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.

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

* We will reduce rates for standard offer service for customers with loads
less than 3 megawatts in a series of annual rate reductions of 1.5%
beginning July 1, 1999 through July 1, 2003, for a total of 7.5%. The first
reduction of approximately $24 million ($14 million after income taxes)
includes the July 1, 1999 retail price decrease of approximately $10.8
million annually ($6.5 million after income taxes) related to the 1996
regulatory agreement. See "1996 Regulatory Agreement" below. For customers
having loads 3 megawatts or greater, standard offer rates will be reduced
in annual increments that total 5% through 2002.

* Unbundled rates being charged by us for competitive direct access service
(for example, distribution services) became effective upon approval of the
Settlement

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Agreement, retroactive to July 1, 1999, and also will be subject to annual
reductions, that vary by rate class, through 2003.

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

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

* Our distribution system opened for retail access, effective September 24,
1999. Customers will be eligible for retail access in accordance with the
phase-in adopted by the ACC under the electric competition rules (see
"Retail Electric Competition Rules" below), with an additional 140
megawatts being made available to eligible non-residential customers.
Unless subject to judicial or regulatory restraint, we will open our
distribution system to retail access for all customers on January 1, 2001.

* We are currently recovering substantially all of our regulatory assets
through July 1, 2004, pursuant to the 1996 regulatory agreement. In
addition, the Settlement Agreement states that we have demonstrated that
our allowable stranded costs, after mitigation and exclusive of regulatory
assets, are at least $533 million net present value. We will not be allowed
to recover $183 million net present value of the above amounts. The
Settlement Agreement provides that we will have the opportunity to recover
$350 million net present value through a competitive transition charge
(CTC) that will remain in effect through December 31, 2004, at which time
it will terminate. Any over/under-recovery will be credited/debited against
the costs subject to recovery under the adjustment clause described above.

* We will form a separate corporate affiliate or affiliates and transfer to
that affiliate(s) our generating assets and competitive services at book
value as of the date of transfer, which transfer shall take place by
December 31, 2002. We will be allowed to defer and later collect
sixty-seven percent of our costs to accomplish the required transfer of
generation assets to an affiliate.

-11-

* When the Settlement Agreement approved by the ACC is no longer subject to
judicial review, we will move to dismiss all of our litigation pending
against the ACC as of the date we entered into the Settlement Agreement.

On October 25, 1999, two parties filed motions for reconsideration of the
Settlement Agreement with the ACC. The ACC took no action within the twenty day
limit, so the motions are deemed denied. We continue to operate under the terms
of the Settlement Agreement.

In its motion for reconsideration, one of the parties has questioned the
degree to which the ACC may, under the Arizona Constitution, deregulate any
portion of the electric utility industry and allow rates to be determined by
market forces. The issue of competitively set rates has been decided by lower
Arizona courts in favor of the ACC in four separate lawsuits, two of which
relate to telecommunications companies. Appeals of the lower courts' decisions
are pending.

As discussed in Note 5 above, we have discontinued the application of
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation," for our generation operations.

RETAIL ELECTRIC COMPETITION RULES On September 21, 1999, the ACC voted to
approve the rules that provide a framework for the introduction of retail
electric competition in Arizona (the "Rules"). If any of the Rules conflict with
the Settlement Agreement, the terms of the Settlement Agreement govern. On
October 19, 1999, several parties, including us, filed motions for
reconsideration of the Rules with the ACC. The ACC took no action within the
twenty day limit, so the motions are deemed denied.

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

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

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

* Subject to the 20% requirement, all utility customers with single premise
loads of one megawatt or greater will be eligible for competitive electric
services on the Final Decision Date, which for the Company's customers was
the approval of the

-12-

Settlement Agreement. Customers may aggregate loads to meet this one
megawatt requirement.

* When effective, residential customers will be phased in at 1 1/4% per
quarter calculated beginning on January 1, 1999, subject to the 20%
requirement above.

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

* Affected utilities must file ACC tariffs with separate pricing for electric
services provided for 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, the Company
received a waiver to allow transfer of its competitive generation assets
and services to affiliates no later than December 31, 2002.

1996 REGULATORY AGREEMENT In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and us. Based on the price reduction formula of
the agreement, the ACC approved retail price decreases of approximately $17.6
million ($10.5 million after income taxes), or 1.2%, effective July 1, 1997;
approximately $17 million ($10 million after income taxes), or 1.1%, effective
July 1, 1998; and approximately $10.8 million ($6.5 million after income taxes),
or 0.7%, effective as of July 1, 1999. The July 1, 1999 rate decrease was
included in the first rate reduction under the Settlement Agreement discussed
above. The regulatory agreement also requires Pinnacle West to infuse $200
million of common equity into us in annual payments of $50 million in 1996
through 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;

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

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

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

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

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

Several electric utility industry restructuring bills have been introduced
during the 106th Congress. Several of these bills are written to allow consumers
to choose their electricity suppliers beginning in 2000 and beyond. These bills,
other bills that are expected to be introduced, and ongoing discussions at the
federal level suggest a wide range of opinion that will need to be narrowed
before any substantial restructuring of the electric utility industry can occur.

7. Agreement with Salt River Project

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

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

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

-14-

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

Certain provisions of the Agreement (including those relating to the amendments
of the Territorial Agreement and the Power Coordination Agreement) became
effective upon the introduction of competition. See Note 6.

8. 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, we
could be assessed retrospective premium adjustments. The maximum assessment per
reactor under the program for each nuclear incident is approximately $88
million, subject to an annual limit of $10 million per incident. Based upon our
29.1% interest in the three Palo Verde units, our maximum potential assessment
per incident is approximately $77 million, with an annual payment limitation of
approximately $9 million.

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

9. Accounting Matters

In June 1998 the Financial Accounting Standards Board (FASB) issued SFAS
No. 133 "Accounting for Derivative Instruments and Hedging Activities." SFAS No.
133 requires that entities recognize all derivatives as either assets or
liabilities on the balance sheet and measure those instruments at fair value.
The standard also provides specific guidance for accounting for derivatives
designated as hedging instruments. The statement was to have been effective for
us in 2000; however, the FASB has moved the effective date to 2001. We are
currently evaluating what impact this standard will have on our financial
statements.

-15-

ARIZONA PUBLIC SERVICE COMPANY

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, including:

* the changes in our earnings for the periods presented
* the factors impacting our business, including competition and electric
industry restructuring
* the effects of regulatory agreements on our results
* our capital needs and resources and
* Year 2000 technology issues.

We suggest this section be read along with the 1998 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 Financial
Statements. These Notes add further details to the discussion.

OPERATING RESULTS

The following table summarizes our revenues and earnings for the
three-month, nine-month and twelve-month periods ended September 30, 1999 and
1998:

Periods ended September 30
(Unaudited)
(Thousands of Dollars)

Three Months Nine Months Twelve Months
------------------------ ----------------------- -----------------------
1999 1998 1999 1998 1999 1998
---------- ---------- ---------- ---------- ---------- ----------

Operating Revenues $ 867,504 $ 740,734 $1,792,921 $1,562,872 $2,236,447 $1,970,832

Earnings (Loss) for
Common Stock (1) $ (10,377) $ 130,846 $ 91,943 $ 209,652 $ 127,835 $ 230,310

(1) 1999 periods include an extraordinary charge of $139,885, net of income
taxes of $94,115.

OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 COMPARED
WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1998

Earnings decreased $141 million in the three-month comparison primarily
because of the effects of a $140 million after-tax extraordinary charge for a
regulatory disallowance (see Notes 5 and 6). Earnings excluding the
extraordinary charge were

-16-

$1 million lower because of the effects of milder weather, a retail price
reduction and lower contributions from power marketing and trading activities.
These reductions in earnings were substantially offset by an increase in
customers and lower property taxes. See Note 6 for information on the price
reduction.

Operating revenues increased $127 million because of:

* increased power marketing and trading revenues ($131 million)
* increases in the number of customers and the average amount of
electricity used by customers ($24 million) and
* miscellaneous factors ($2 million).

As mentioned above, these positive factors were partially offset by weather
impacts ($22 million) and the effect of a reduction in retail prices ($8
million).

Power marketing and trading activities are predominantly short-term
opportunity wholesale sales. The increase in power marketing revenues resulted
primarily from increased activity in western U.S. bulk power markets and was
accompanied by an increase in purchased power expenses. Although these
activities contribute positively to earnings in both periods, the contribution
in 1999 was lower than in 1998.

Fuel and purchased power expenses increased $144 million primarily because
of increased wholesale sales volume and higher purchased power prices.

Other taxes decreased $5 million primarily because of an adjustment to
reflect lower property tax rates for 1999.

OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 COMPARED
WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1998

Earnings decreased $118 million in the nine-month comparison primarily
because of the effects of a $140 million after-tax extraordinary charge for a
regulatory disallowance (see Notes 5 and 6). Earnings excluding the
extraordinary charge were $22 million higher because of an increase in
customers, lower property taxes and lower financing costs. These increases in
earnings were partially offset by the effects of milder weather, retail price
reductions, higher depreciation and lower contributions from power marketing and
trading activities. See Note 6 for information on the price reductions.

Operating revenues increased $230 million because of:

* increased power marketing and trading revenues ($188 million) and
* increases in the number of customers and the average amount of
electricity used by customers ($69 million).

-17-

As mentioned above, these positive factors were partially offset by weather
impacts ($10 million) and the effect of reductions in retail prices ($17
million).

Fuel and purchased power expenses increased $206 million primarily because
of increased wholesale and retail sales volume and higher purchased power
prices.

Other taxes decreased $5 million primarily because of lower property tax
rates.

Financing costs decreased by $4 million primarily because of lower amounts
of outstanding preferred stock.

Depreciation and amortization expense increased $8 million because we had
more plant in service.

OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 COMPARED
WITH TWELVE-MONTH PERIOD SEPTEMBER 30, 1998

Earnings decreased $102 million in the twelve-month comparison primarily
because of the effects of a $140 million after-tax extraordinary charge for a
regulatory disallowance (see Notes 5 and 6). Earnings excluding the
extraordinary charge were $38 million higher because of an increase in
customers, lower property taxes, lower operations and maintenance expenses and
lower financing costs. These increases in earnings were partially offset by the
effects of milder weather, retail price reductions and higher depreciation. See
Note 6 for information on the price reductions.

Operating revenues increased $266 million because of:

* increased power marketing and trading revenues ($216 million)
* increases in the number of customers and the average amount of
electricity used by customers ($85 million) and
* miscellaneous factors ($8 million).

As mentioned above, these positive factors were partially offset by weather
impacts ($23 million) and the effect of reductions in retail prices ($20
million).

-18-

to earnings in both periods, the contribution in the current period was the same
as in the previous period.

Fuel and purchased power expenses increased $228 million primarily because
of increased wholesale and retail sales volume and higher purchased power
prices.

Other taxes decreased $10 million primarily because of lower property tax
rates for 1999 and an adjustment in the fourth quarter of 1998 to reflect lower
property tax rates for 1998.

Operations and maintenance expenses were lower $7 million primarily due to
lower employee benefit costs.

Financing costs decreased by $6 million primarily because of lower amounts
of outstanding preferred stock.

Depreciation and amortization expense increased $14 million because we had
more plant in service.

OTHER INCOME

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

LIQUIDITY AND CAPITAL RESOURCES

For the nine months ended September 30, 1999, we incurred approximately
$229 million in capital expenditures, which is approximately 70% of the most
recently estimated 1999 capital expenditures. Our projected capital expenditures
for the next three years are: 1999, $328 million; 2000, $353 million; and 2001,
$343 million. These amounts include about $30 - $35 million each year for
nuclear fuel expenditures.

Our long-term debt and preferred stock redemption requirements, optional
repayments and payment obligations on a capitalized lease for the next three
years are: 1999, $406 million; 2000, $115 million; and 2001, $252 million.
During the nine months ended September 30, 1999, we redeemed approximately $260
million of our long-term debt and all $96 million (including premiums) of our
preferred stock with cash from operations and long-term and short-term debt. In
February 1999 we issued $125 million of unsecured long-term debt, and in
November 1999, we issued $250 million of unsecured long-term debt. As a result
of the 1996 regulatory agreement (see Note 6), Pinnacle West invested $50
million in the Company in 1996, 1997 and 1998 and will make the final investment
of $50 million in 1999.

-19-

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

YEAR 2000 READINESS DISCLOSURE

OVERVIEW As the year 2000 approaches, many companies face problems because many
computer systems and equipment will not properly recognize calendar dates
beginning with the year 2000. We are addressing the Year 2000 issue as described
below. We initiated a comprehensive company-wide Year 2000 program during 1997
to review and resolve all Year 2000 issues in mission critical systems (systems
and equipment that are key to the power production, delivery, health, and safety
functions) in a timely manner to ensure the reliability of electric service to
our customers. This included a company-wide awareness program of the Year 2000
issue. We also have had an internal audit/quality team review the individual
Year 2000 projects and their Year 2000 readiness.

The following chart shows Year 2000 readiness of our mission critical systems as
of September 30, 1999:

INVENTORY ASSESSMENT REMEDIATION & TESTING
--------- ---------- ---------------------
100% 100% 100%

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

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

We have made, and will continue to make, certain modifications to computer
hardware, software, and application systems, including IT and non-IT systems, in
an effort to

-20-

ensure they are capable of handling changing business needs, including dates in
the year 2000 and thereafter. In addition, we will continue to analyze other IT
and non-IT systems, including embedded technology and real-time process control
systems, for potential modifications.

We have inventoried, assessed, remediated and tested all mission critical IT and
non-IT systems and equipment as of June 30, 1999. Remediation and testing is
also completed for the continuous emissions monitoring systems (CEMS). See "Year
2000 Readiness Disclosure" in Part I, Item 2 of the June 10-Q. We notified the
North American Electric Reliability Council (NERC) on June 30, 1999, that our
mission critical systems are ready for date changes associated with the Year
2000, in accordance with NERC's recommended criteria. We also notified the
Nuclear Regulatory Commission (NRC) that Palo Verde is "Y2K Ready," which means
that Palo Verde has followed a prescribed program to identify and resolve Year
2000 issues so that the plant can operate reliably while meeting commitments.

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

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

We have also been working with NERC through the Western Systems Coordinating
Council (WSCC) to develop operational plans for stable grid operation that will
be used by other utilities and us in the western United States. Our operational
plans are complete. However, we cannot currently predict the effect on us if the
systems of these other companies are not Year 2000 ready.

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

-21-

We have developed our own contingency plans to handle Year 2000 issues,
including the most reasonably likely worst case scenario, discussed above. These
plans were completed June 30, 1999.

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. See Note 7 for a discussion of a proposed amendment to a
Power Coordination Agreement with Salt River Project that we estimate would
reduce our pretax costs for purchased power by approximately $17 million during
the first full year that the amendment is effective and by lesser annual amounts
during the next seven years.

RATE MATTERS

See Note 6 for a discussion of a price reduction effective as of July 1,
1999, and for a discussion of a Settlement Agreement that will, among other
things, result in 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 our traditional
regulated markets; regional economic conditions, which could affect customer
growth; the cost of debt and equity capital; weather variations affecting
customer usage; technological developments in the electric industry; the
successful completion of a large-scale construction project; and Year 2000
issues.

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

-22-

ITEM 3. MARKET RISKS

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

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

We are exposed to the impact of market fluctuations in the price and
distribution costs of electricity, natural gas, coal, and emissions
allowances/credits and therefore employ established procedures to manage our
risks associated with these market fluctuations by utilizing various commodity
derivatives, including exchange traded futures and options and over-the-counter
forwards, options, and swaps. As part of our overall risk management program, we
enter into these derivative transactions for trading and to hedge certain
natural gas in storage as well as purchases and sales of electricity, fuels, and
emissions allowances/credits.

We measure the price risk in our commodity derivative portfolio on a daily basis
utilizing market sensitivity based modeling to understand expected and potential
single day favorable or unfavorable impacts to income before tax. The model
results are monitored daily to ensure compliance against thresholds on a
commodity and portfolio basis. As of September 30, 1999, a hypothetical adverse
price movement of 10% in the market price of our commodity derivative portfolio
would decrease the fair market value of these contracts by approximately $7
million. This analysis does not include the favorable impact this same
hypothetical price move would have on the underlying position being hedged with
the commodity derivative portfolio.

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

-23-

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 the Company's construction and financing programs.

COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING

See Note 6 of Notes to Condensed 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

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

CLEAN AIR ACT. As previously reported, we filed a petition for review
alleging EPA improperly classified Four Corners Unit 4 with respect to nitrogen
oxides emissions limitations. See "Environmental Matters - Clean Air Act" in
Part I, Item 1 of the 1998 10-K. In October 1999, EPA issued a direct final
rule, which classified Four Corners Unit 4 as we had proposed. Depending on the
comments filed by other parties, if any, the rules may become final as soon as
December 1999. We do not currently expect this rule to have a material impact on
our financial position or results of operations.

-24-

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

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

10.2 Retail Electric Competition Rules

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:

EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(a) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------

3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96
February 20, 1996 Report

3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93
restated as of May 25, 1988 Registration Nos.
33-33910 and 33-55248 by
means of September 24,
1993 Form 8-K Report

(b) Reports on Form 8-K

During the quarter ended September 30, 1999, and the period from October 1
through November 15, 1999, we filed the following reports on Form 8-K:

Report dated August 26, 1999 regarding the ACC Hearing Officer
recommendations on our proposed Settlement Agreement and the proposed retail
electric competition rules.

Report dated September 21, 1999 regarding ACC approval of our Settlement
Agreement and the retail electric competition rules.

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

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

-25-

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.

ARIZONA PUBLIC SERVICE COMPANY
(Registrant)

Dated: November 15, 1999 By: Michael V. Palmeri
------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Financial Officer and
Officer Duly Authorized to sign this
Report)