ARIZONA PUBLIC SERVICE CO, 10-Q, 1999-11-15

ARIZONA PUBLIC SERVICE CO
10-Q, 1999-11-15
ELECTRIC & OTHER SERVICES COMBINED

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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.
<PAGE>
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
<PAGE>
-2-

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.
<PAGE>
-3-

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Nine Months
Ended September 30,
--------------------------
1999 1998
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
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
=========== ===========
</TABLE>

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

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)

<TABLE>
<CAPTION>
Twelve Months
Ended September 30,
--------------------------
1999 1998
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
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
=========== ===========
</TABLE>

See Notes to Condensed Financial Statements.
<PAGE>
-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.
<PAGE>
-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.
<PAGE>
-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.
<PAGE>
-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
<PAGE>
-9-

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
<PAGE>
-10-

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.
<PAGE>
-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
<PAGE>
-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;
<PAGE>
-13-

* 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.
<PAGE>
-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.
<PAGE>
-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)

<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
------------------------ ----------------------- -----------------------
1999 1998 1999 1998 1999 1998
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>

(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
<PAGE>
-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).
<PAGE>
-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).

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.
<PAGE>
-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
<PAGE>
-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.
<PAGE>
-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.
<PAGE>
-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.
<PAGE>
-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.
<PAGE>
-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:

<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(a) DATE EFFECTIVE
- ----------- ----------- ---------------------------- ----------- --------------
<S> <C> <C> <C> <C>
3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96
February 20, 1996 Report

3.3 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
</TABLE>

(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.
<PAGE>
-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)

BEFORE THE ARIZONA CORPORATION COMMISSION

DOCKET NO. E-01345A-98-0473 ET AL.
DECISION NO. _______________

CARL J. KUNASEK
CHAIRMAN
JIM IRVIN
COMMISSIONER
WILLIAM A. MUNDELL
COMMISSIONER

<TABLE>
<CAPTION>
<S> <C>
IN THE MATTER OF THE APPLICATION OF ARIZONA PUBLIC SERVICE DOCKET NO. E-01345A-98-0473
COMPANY FOR APPROVAL OF ITS PLAN FOR STRANDED COST RECOVERY.
- --------------------------------------------------------------

IN THE MATTER OF THE FILING OF ARIZONA PUBLIC SERVICE COMPANY DOCKET NO. E-01345A-97-0773
OF UNBUNDLED TARIFFS PURSUANT TO A.A.C. R14-2-1601 ET SEQ.

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

IN THE MATTER OF COMPETITION IN THE PROVISION OF ELECTRIC DOCKET NO. RE-00000C-94-0165
SERVICES THROUGHOUT THE STATE OF ARIZONA.
DECISION NO. 61973
- --------------------------------------------------------------
OPINION AND ORDER
</TABLE>

DATES OF HEARING: July 12, 1999 (pre-hearing conference), July 14, 15, 16,
19, 20, and 21, 1999

PLACE OF HEARING: Phoenix, Arizona

PRESIDING OFFICER: Jerry L. Rudibaugh

IN ATTENDANCE: Carl J. Kunasek, Chairman
Jim Irvin, Commissioner

APPEARANCES: Mr. Steven M. Wheeler, Mr. Thomas Mumaw and Mr. Jeffrey B.
Guldner, SNELL & WILMER, LLP, on behalf of Arizona Public
Service Company;

Mr. C. Webb Crockett and Mr. Jay Shapiro, FENNEMORE CRAIG,
on behalf of Cyprus Climax Metals, Co., ASARCO, Inc., and
Arizonans for Electric Choice & Competition;

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

Ms. Betty Pruitt on behalf of the Arizona Community Action
Association;

1 DECISION NO. 61973
<PAGE>
DOCKET NO. E-01345A-98-0473 ET AL.

Mr. Timothy Hogan on behalf of the Arizona Consumers
Council;

Mr. Robert S. Lynch on behalf of the Arizona Transmission
Dependent Utility Group;

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

Mr. Douglas C. Nelson, DOUGLAS C. NELSON, P.C., on behalf
of Commonwealth Energy Corporation;

Mr. Lawrence V. Robertson, Jr., MUNGER & CHADWICK, and Ms.
Leslie Lawner, Director Government Affairs on behalf of
Enron Corporation, and Mr. Robertson on behalf of PG&E
Energy Services;

Mr. Lex J. Smith, BROWN & BAIN, P.A., on behalf of
Illinova Energy Partners and Sempra Energy Trading;

Mr. Randall H. Werner, ROSHKA, HEYMAN & DeWULF, P.L.C., on
behalf of NEV Southwest;

Mr. Norman Furuta on behalf of the Department of the Navy;

Mr. Bradley S. Carroll on behalf of Tucson Electric Power
Company; and

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

BY THE COMMISSION:

On December 26, 1996, the Arizona Corporation Commission ("Commission") in
Decision No. 59943 enacted A.A.C. R14-2-1601 through R14-2-1616 ("Rules" or
"Electric Competition Rules").

On June 22, 1998, the Commission issued Decision No. 60977, the Stranded
Cost Order which required each Affected Utility to file a plan for stranded cost
recovery.

On August 10, 1998, the Commission issued Decision No. 61071 which made
modifications to the Rules on an emergency basis.

On August 21, 1998, Arizona Public Service Company ("APS") filed its
Stranded Costs plan.

On November 5, 1998, APS filed a Settlement Proposal that had been entered
into with the Commission's Utilities Division Staff ("Staff Settlement
Proposal"). Our November 24, 1998 Procedural Order set the matter for hearing.
On November 25, 1998, the Commission issued

2 DECISION NO. 61973
<PAGE>
DOCKET NO. E-01345A-98-0473 ET AL.

Decision No. 61259 which established an expedited procedural schedule for
evidentiary hearings on the Staff Settlement Proposal.

On November 30, 1998, the Arizona Attorney General's Office, in association
with numerous other parties, filed a Verified Petition for Special Action and
Writ of Mandamus with the Arizona Supreme Court ("Court") regarding the
Commission's November 25, 1998 Procedural Order, Decision No. 61259. The
Attorney General sought a Stay of the Commission's consideration of the Staff
Settlement Proposal with APS and Tucson Electric Power Company ("TEP").

On December 1, 1998, Vice Chief Justice Charles J. Jones granted a Motion
for Immediate Stay of the Procedural Order. On December 9, 1998, the Commission
Staff filed a notice with the Supreme Court that the Staff Settlement Proposal
had been withdrawn from Commission consideration.

On April 27, 1999, the Commission issued Decision No. 61677, which modified
Decision No. 60977. On May 17, 1999, APS filed with the Commission a Notice of
Filing, Application for Approval of Settlement Agreement ("Settlement" or
"Agreement") 1 and Request for Procedural Order.

Our May 25, 1999 Procedural Order set the matter for hearing commencing on
July 14, 1999.

This matter came before a duly authorized Hearing Officer of the Commission
at its offices in Phoenix, Arizona. APS, Cyprus Climax Metals, Co., ASARCO,
Inc., Arizonans for Electric Choice & Competition ("AECC"), Residential Utility
Consumer Office ("RUCO"), the Arizona Community Action Association ("ACAA"), the
Arizona Consumers Council, the Arizona Transmission Dependent Utility Group, the
Arizona Utility Investors Association, Enron Corporation, PG&E Energy Services,
Illinova Energy Partners, Sempra Energy Trading, NEV Southwest, the Department
of the Navy, Tucson Electric Power Company, Commonwealth Energy Corporation

- ----------
1 The Parties to the Proposed Settlement are as follows: the Residential
Utility Consumer Office, Arizona Public Service Company, Arizona Community
Action Association and the Arizonans for Electric Choice and Competition
which is a coalition of companies and associations in support of
competition that includes Cable Systems International, BHP Copper,
Motorola, Chemical Lime, Intel, Honeywell, Allied Signal, 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 Association, Arizona Restaurant Association, Arizona Retailers
Association, Boeing, Arizona School Board Association, National Federation
of Independent Business, Arizona Hospital Association, Lockheed Martin,
Abbot Labs and Raytheon.

3 DECISION NO. 61973
<PAGE>
DOCKET NO. E-01345A-98-0473 ET AL.

("Commonwealth") and Staff of the Commission appeared through counsel. Evidence
was presented concerning the Settlement Agreement, and after a full public
hearing, this matter was adjourned pending submission of a Recommended Opinion
and Order by the Presiding Officer to the Commission. In addition, a
post-hearing briefing schedule was established with simultaneous briefs filed on
August 5, 1999.

DISCUSSION

INTRODUCTION

The Settlement provides for rate reductions for residential and business
customers; sets the amount, method, and recovery period of stranded costs that
APS can collect in customer charges; establishes unbundled rates; and provides
that APS will separate its generating facilities, which will operate in the
competitive market, from its distribution system, which will continue to be
regulated.

According to APS, the Settlement was the product of months of hard
negotiations with various customer groups. APS opined that the Settlement
provides many clear benefits to customers, potential competitors, as well as to
APS. Some of those benefits as listed by APS are as follows:

* Allowing competition to commence in APS' service territory months before
otherwise possible and expanding the initial eligible load by 140 MW;

* Establishing both Standard Offer and Direct Access rates, and providing for
annual rate reductions with a cumulative total of as much as $475 million
by 2004;

* Ensuring stability and certainty for both bundled and unbundled rates;

* Resolving the issue of APS' stranded costs and regulatory asset recovery in
a fair and equitable manner;

* Providing for the divestiture of generation and competitive services by APS
in a cost-effective manner;

* Removing the specter of years of litigation and appeals involving APS and
Commission over competition-related issues;

* Continuing support for a regional ISO and the AISA;

* Continuing support for low income programs; and

* Requiring APS to file an interim code of conduct to address affiliate
relationships.

4 DECISION NO. 61973
<PAGE>
DOCKET NO. E-01345A-98-0473 ET AL.

The Settlement was entered into by RUCO and the ACAA reflecting Agreement
by residential customers of APS to the Settlement's terms and conditions. In
addition, the Settlement was executed by the AECC, a coalition of commercial and
industrial customers and trade associations. AECC opined that since residential
and non-residential customers have agreed to the Settlement, the "public
interest" has been served. AECC indicated the Settlement was not perfect but was
the result of "give and take" by each of the parties. Accordingly, AECC urged
the Commission to protect the "public interest" by approving the Settlement and
not allow Energy Service Providers ("ESPs") to delay the benefits that
competition has to offer.

LEGAL ISSUES:

The Arizona Consumers Council ("Consumers Council") opined that the
Agreement was not legal because: (1) there was no full rate proceeding2; (2)
Section 2.8 of the Agreement violates A.R.S. Section 40-246, regarding
Commission initiated rate reductions; and (3) the Agreement illegally binds
future Commissions. According to the Consumers Council, the Commission does not
have evidence to support a finding that the rates proposed in the Agreement are
just and reasonable; that the rate base proposed is proper; and asserted the
proposed adjustment clause can not be established outside a general rate case.

Staff argued that the Commission in Decision No. 59601, dated April 26,
1996, has previously determined just and reasonable rates for APS which must be
charged until changed in a rate proceeding. According to Staff, this case is not
about changing existing rates, but instead involves the introduction of a new
service - direct access. The direct access rates have been designed to replicate
the revenue flow from existing rates. Staff opined that the Commission has
routinely, and lawfully, approved rates for new services outside of a rate case.
Further, Staff asserted that the rates proposed in the Settlement are directly
related to a complete financial review. Staff indicated that the Consumers
Council has provided no contrary information and should not be allowed to
collaterally attack Decision No. 59601.

APS argued that no determination of fair value rate base ("FVRB"), fair
value rate of return

- ----------
2 Although the Consumers Council indicated they did not believe a full rate
proceeding was necessary, it is unclear as to the type of proceeding the
Consumers Council believed was necessary.

5 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

("FVROR"), or other financial analysis is legally necessary to justify current
APS rate levels, allow the introduction of a new service, or to evaluate a
series of voluntary rate decreases. In spite of that, APS did provide
information to support a FVRB of $5,195,675,000 and FVROR of 6.63 percent. No
other party presented evidence in support of a FVRB or FVROR. Staff supported
APS.

We concur with Staff and APS. The Consumers Council has provided no legal
authority that a full rate proceeding is necessary in order to adopt a rate
reduction or rates for new services. Further, pursuant to the Arizona
Constitution, the Commission has jurisdiction over ratemaking matters. We also
find that notice of the application and hearing was provided and that APS has
provided sufficient financial information to support a finding of FVRB and
FVROR. Lastly, this Commission can clearly bind future Commissions as a result
of its Decision. However, as later discussed, we agree there are limitations to
such legal authority.

SHOPPING CREDIT

One of the most contentious issues in the hearing was the level of the
"shopping credit." The "shopping credit" is the difference between the
customer's Standard Offer Rate and the Direct Access Rate available to customers
who take service from ESPs. The ESPs generally argued that the Settlement's
"shopping credits" were not sufficient to allow a new entrant to make a profit.
AECC opined that such an argument was nothing more than a request to increase
ESP's profits.

Staff opined that the "shopping credit" was too low and recommended it be
increased without impacting the stranded cost recovery amount of $350 million.
Under Staff's proposal, the increased "shopping credit" would be offset by
reducing the competitive transition charge ("CTCs"). Further, Staff recommended
that any stranded costs not collected could simply be deferred and collected
after 2004.

The AECC expert testified that the "shopping credit" under the Agreement
was superior to the "Shopping Credit" in the Staff Settlement Proposal as well
as the one offered to SRP's customers. APS argued that artificially high
shopping credits will likely increase ESP profits without lowering customer
rates and will encourage inefficient firms to enter the market. Based on the
analysis of the

6 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

40kW to 200 kW customer group3, APS showed an average margin on the "shopping
credit" of over 8 mils per kWh or a 23 percent markup over cost. APS asserted
that the test for a reasonable "shopping credit" "should not be whether ALL ESPs
can profit on all APS customers ALL of the time".

Based on the evidence presented, the "shopping credits" appear to be
reasonable to allow ESPs to compete in an efficient manner. Further, we do not
find customer rates should be increased simply to have higher "shopping
credits".

METERING AND BILLING CREDITS

The metering and billing credits resulting from the Agreement are based on
decremental costs. Several of the ESPs and Staff argued that these credits
should be based upon embedded costs and not decremental costs. APS responded
that such a result could cause them to lose revenues since its costs would only
go down by the decremental amounts. Staff testified that the Company would not
lose significant income if it used embedded costs since it would free up
resources to service new customers.

We concur. The proposed credits for metering, meter reading and billing4
will result in a direct access customer paying a portion of APS costs as well as
a portion of the ESP's costs. We believe this would stymie the competitive
market for these services. As a result, we find the approval of the Settlement
should be conditioned upon the use of Staff's proposed credits for metering,
meter reading, and billing.

PROPOSED ONE-YEAR ADVANCE NOTICE REQUIREMENT:

Section 2.3 provides that

"Customers greater than 3MW who chose a direct access supplier must
give APS one year's advance notice before being eligible to RETURN to
Standard Offer service." [emphasis added]

Several parties expressed concerns that the one-year notice requirement to
return to Standard Offer service would create a deterrent to load switching by
large industrial, institutional and commercial customers. PG&E proposed that any
increased cost could be charged directly to the

- ----------
3 Represents over 80 percent of the general service customers for competitive
access in phase one.

4 For example, the monthly credits for a direct access residential customers
are $1.30, $0.30, and $0.30 for metering, meter reading and billing,
respectively.

7 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

customer as a condition to its return.

We agree that APS needs to have some protection from customers leaving the
system when market prices are low and jumping back on Standard Offer rates when
market prices go up. The suggestion by PG&E that the customer be allowed to go
back to the Standard Offer if the customer pays for additional costs it has
caused is a reasonable resolution. Accordingly, we will order APS to submit
substitute language on this issue.

SECTION 2.8

Several of the parties expressed concern that Section 2.8 of the Agreement
allows APS to seek rate increases under specified conditions. Additionally, as
previously discussed, the Consumers Council opined that Section 2.8 violated
A.R.S. Section 40-246. Staff recommended the Commission condition approval of
the Agreement on Section 2.8 being amended to include language that the
Commission or Staff may commence rate change proceedings under conditions
paralleling those provided to the utility, including response to petitions
submitted under A.R.S. ss. 40-246.

We agree that Section 2.8 is too restrictive on the Commission's future
action. Accordingly, we will condition approval of the Agreement on inclusion of
the following language in Section 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.

SECTION 7.1

The Consumers Council opined that there was language in the Agreement which
would illegally bind future Commissions. While Staff disagreed with the legal
opinion of the Consumers Council, Staff was concerned with some of the binding
language in the Agreement and in particular with the following language in
Section 7.1:

7.1. To the extent any provision of this Agreement is inconsistent
with any existing or future Commission order, rule or regulation or is
inconsistent with the Electric

8 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

Competition Rules as now existing or as may be amended in the future, the
provisions of this Agreement shall control and the approval of the
Agreement by the Commission shall be deemed to constitute a
Commission-approved variation or exemption to any conflicting provision of
the Electric Competition Rules.

Staff recommended the Commission not approve Section 7.1.

We share Staff's concerns. We also recognize that the parties want to
preserve their benefits to their Agreement. We agree with the parties that to
the extent any provision of the Agreement is inconsistent with the Electric
Competition Rules as finalized by the Commission in September 1999, the
provisions of the Agreement shall control. 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. With that said, the Commission must be able to make
rule changes/other future modifications that become necessary over time. As a
result, we will direct the parties and Staff to file within 10 days, a revised
Section 7.1 consistent with the Commission's discussions herein and subsequently
approved by this Commission.

GENERATION AFFILIATE

Section 4.1 of the Agreement provides the following:

4.1 The Commission will approve the formation of an affiliate or
affiliates of APS to acquire at book value the competitive services 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).

Related to Section 4.1 is Section 2.6(3) which allows APS to defer costs of
forming the generation affiliate, to be collected beginning July 1, 2004.

According to NEV Southwest, APS indicated that it intends to establish a
generation affiliate under Pinnacle West, not under APS. Further, that APS
intends to procure generation for standard offer customers from the wholesale
generation market as provided for in the Electric Competition Rules.
Additionally, it was NEV Southwest's understanding that the affiliate generation
company could bid for the APS standard offer load under an affiliate FERC
tariff, but there would be no automatic privilege outside of the market bid. NEV
Southwest supports the aforementioned concepts and recommended they be
explicitly stated in the Agreement.

We concur with NEV Southwest. We shall order APS to include language as
requested by

9 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

NEV Southwest. Power for Standard Offer Service will be acquired in a manner
consistent with the Commission's Electric Competition Rules. We generally
support the request of APS to defer those costs related to formation of a new
generation affiliate pursuant to the Electric Competition Rules. We also
recognize the Company is making a business decision to transfer the generation
assets to an affiliate instead of an unrelated third party. As a result, we find
the Company's proposed mitigation of stranded costs(5) in the Settlement should
also apply to the costs of forming the new generation affiliate. Accordingly,
Section 2.6(3) should be modified to reflect that only 67 percent of those costs
to transfer generation assets to an affiliate shall be allowed to be deferred
for future collection.

Some parties were concerned that Sections 4.1 and 4.2 provide in effect
that the Commission will have approved in advance any proposed financing
arrangements associated with future transfers of "competitive services" assets
to an affiliate. As a result, there was a recommendation that the Commission
retain the right to review and approve or reject any proposed financing
arrangements. In addition, some parties expressed concern that APS has not
definitively described the assets it will retain and which it will transfer to
an affiliate.

We share the concerns that the non-competitive portion of APS not subsidize
the spun-off competitive assets through an unfair financial arrangement. We want
to make it clear that the Commission will closely scrutinize the capital
structure of APS at its 2004 rate case and make any necessary adjustments. The
Commission supports and authorizes the transfer by APS to an affiliate or
affiliates of all its generation and competitive electric service assets as set
forth in the Agreement no later than December 31, 2002. However, we will require
the Company to provide the Commission with a specific list of any assets to be
so transferred, along with their net book values at the time of transfer, at
least thirty days prior to the actual transfer. The Commission reserves the
right to verify whether such specific assets are for the provision of generation
and other competitive electric services or whether there are additional APS
assets that should be so transferred.

UNBUNDLED RATES

Several parties expressed concern that the Agreement's unbundled rates fail
to provide the

- ----------
5 Agreement to not recover $183 million out of a claimed $533 million.

10 DECISION NO. 61973
<PAGE>
DOCKET NO. E-01345A-98-0473 ET AL.

necessary information to determine whether a competitor's price is lower than
the Standard Offer rate. Further, some of the parties asserted that APS has not
performed a functional cost-of-service study and as a result the Settlement's
"shopping credit" is an artificial division of costs. In response, APS indicated
the Standard Offer rates can not be unbundled on a strict cost-of-service basis
unless the Standard Offer rates are redesigned to equal cost-of-service. APS
opined that such a process would result in significant rate increases for many
customers.

AECC asserted that a full rate case would result in additional months/years
of delay with continued drain of resources by all interested entities.

The ESPs asserted that the bill format proposed by APS is misleading and
too complex. In general, the ESPs desired a bill format that would allow
customers to easily compare Standard Offer and Direct Access charges in order to
make an informed decision. As a result, APS was directed to circulate an
Informational Unbundled Standard Offer Bill ("Bill") to the parties for
comments. Subsequent to the hearing, a Bill was circulated to the parties for
comments to determine what consensus could be reached on its format. In general,
there was little dispute with the format of the Bill. However, PG&E and
Commonwealth disagreed with the underlying cost allocation methodologies. Enron
was concerned that the Bill portrayed the Standard Offer to be more simplistic
than the Direct Access portion of the Bill. Enron proposed a bill format that
would clearly identify those services which are available from an ESP. Based on
comments from RUCO and Staff, APS made general revisions to the proposed Bill.

We find the APS Attachment AP-1R, second revised dated 8/16/99 provides
sufficient information in a concise manner to enable customers to make an
informed choice. (See Attachment No. 2 herein). However, we find the Enron
breakdown into a Part 1 versus Parts 2 and 3 will further help educate customers
as to choice. We will direct APS to further revise its Bill to have a Part 1 as
set forth by the Enron breakdown. We believe Parts 2 and 3 can be combined for
simplicity.

We concur with APS that it is not necessary to file a revised
cost-of-service study at this time. The proposed Standard Offer rates contained
in the Settlement are based on existing tariffs approved by this Commission.
Further, we concur with AECC that a full rate case with a revised
cost-of-service study would result in months/years of additional delay. Lastly,
the Standard Offer rates as

11 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

proposed in the Settlement are consistent with the Commission's requirement that
no customer shall receive a rate increase. The following was extracted from
Decision No. 61677:

"No customer or customer class shall receive a rate increase as a
result of stranded cost recovery by an Affected Utility under any of
these options."

CODE OF CONDUCT

There were concerns expressed that APS would be writing its own Code of
Conduct. Subsequently, APS did provide a copy of its proposed Code of Conduct to
the parties for comment. Several parties also expressed concern that any Code of
Conduct would not cover the actions of a single company during the two-year
delay for transferring generation assets.

Based on the above, we will direct APS to file with the Commission no later
than 30 days of the date of this Decision, its interim Code of Conduct. We will
direct APS to file its revised Code of Conduct within 30 days of the date of
this Decision. Such Code of Conduct should also include provisions to govern the
supply of generation during the two-year period of delay for the transfer of
generation assets so that APS doesn't give itself an undue advantage over the
ESPs. All parties shall have 60 days from the date of this Decision to provide
their comments to APS regarding the revised Code of Conduct. APS shall file its
final proposed Code of Conduct within 90 days of the date of this Decision.
Subsequently, within 10 days of filing the Code of Conduct, the Hearing Division
shall establish a procedural schedule to hear the matter.

SECTION 2.6(1)

Pursuant to the Agreement, the Commission shall approve an adjustment
clause or clauses which among other things would provide for a purchased power
adjustor ("PPA") for service after July 1, 2004 for Standard Offer obligations.
Part of the justification for the PPA was the fact that these costs would be
outside of the Company's control.

We concur that a PPA would result in less risk to the Company resulting in
lower costs for the Standard Offer customers. As a result, we will approve the
concept of the PPA as set forth in Section 2.6(1) with the understanding that
the Commission can eliminate the PPA once the Commission has provided reasonable
notice to the Company.

12 DECISION NO. 61973
<PAGE>
DOCKET NO. E-01345A-98-0473 ET AL.

REQUESTED WAIVERS

Section 4.3 of the Agreement would automatically act to exempt APS and its
affiliates from the application of a wide range of provisions under A.R.S. Title
40. In addition, under Section 4.5 of the Agreement, Commission approval without
modification will act to grant certain waivers to APS and its affiliates of a
variety of the provisions of the Commission's affiliate interest rules (A.A.C.
R14-2-801, ET SEQ.), and the rescission of all or portions of certain prior
Commission decisions.

Staff recommended that the Commission reserve its approval of the requested
statute waivers until such time as their applicability can be evaluated on an
industry-wide basis, rather than providing a blanket exemption for APS and its
affiliates. Additionally, Staff recommended that the Commission not waive the
applicability of A.A.C. R14-2-804(A), in order to preserve the regulatory
authority needed by the Commission to justify approving Exempt Wholesale
Generator ("EWG") status for APS' generation affiliate.

We concur with Staff. Accordingly, the requested statutory waivers shall
not be granted by this Decision. Those waivers will be considered in an
industry-wide proceeding to be scheduled at the Commission's earliest
convenience. The requested waivers of affiliate interest rules and rescission of
prior Commission decisions shall be granted, except that the provisions of
A.A.C. R14-2-804(A) shall not be waived.

ANALYSIS/SUMMARY

Consistent with our determination in Decision No. 60977, the following
primary objectives need to be taken into consideration in deciding the overall
stranded cost issue:

A. Provide the Affected Utilities a reasonable opportunity to collect 100
percent of their unmitigated stranded costs;

B. Provide incentives for the Affected Utilities to maximize their
mitigation effort;

C. Accelerate the collection of stranded costs into as short of a
transition period as possible consistent with other objectives;

D. Minimize the stranded cost impact on customers remaining on the
standard offer;

E. Don't confuse customers as to the bottom line; and

13 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

F. Have full generation competition as soon as possible.

The Commission also recognized in Decision No. 60977 that the aforementioned
objectives were in conflict. Part of that conflict is reflected in the following
language extracted from Decision No. 60977:

One of the main concerns expressed over and over by various
consumer groups was that the small consumers would end up with higher
costs during the transition phase and all the benefits would flow to
the larger users. At the time of the hearing, there had been minimal
participation in California by residential customers in the
competitive electric market place. It is not the Commission's intent
to have small consumers pay higher short-term costs in order to
provide lower costs for the larger consumers. Accordingly, we will
place limitations on stranded cost recovery that will minimize the
impact on the standard offer.

Decision No. 61677 modified Decision No. 60977 and allowed each Affected Utility
to chose from five options.

With the modifications contained herein, we find the overall Settlement
satisfies the objectives set forth in Decision Nos. 60977 and 61677. We believe
the Settlement will result in an orderly process that will have real rate
reductions6 during the transition period to a competitive generation market. The
Settlement allows EVERY APS CUSTOMER to have the immediate opportunity to
benefit from the change in market structure while maintaining reliability and
certainty of delivery. Further, the Settlement in conjunction with the Electric
Rules will provide every APS customer with a choice in a reasonable timeframe
and in an orderly manner. If anything, the Proposed Settlement favors customers
over competitors in the short run since APS has agreed to reductions in rates
totaling 7.5 percent(7). This Commission supports competition in the generation
market because of increased benefits to customers, including lower rates and
greater choice. While some of the potential competitors have argued that higher
"shopping credits" will result in greater choice, we find that a higher shopping
credit would also mean less of a rate reduction for APS customers. We find that
the Settlement strikes the proper balance between competing objectives by
allowing immediate

- ----------
6 There have been instances in other states where customers were told they
would receive rate decreases which were then offset by a stranded cost
add-on.

7 Pursuant to Decision No. 59601, dated April 24, 1996, 0.68 percent of that
decrease would have occurred on July 1, 1999.

14 DECISION NO. 61973
<PAGE>
DOCKET NO. E-01345A-98-0473 ET AL.

rate reductions while maintaining a relatively short transition period for
collection of stranded costs, followed shortly thereafter with a full rate case.
At that point in time the collection of stranded costs will be completed and
unbundled rates can be modified based upon an updated cost study.

* * * * * * * * * *

Having considered the entire record herein and being fully advised in the
premises, the Commission finds, concludes, and orders that:

FINDINGS OF FACT

1. APS is certificated to provide electric service as a public service
corporation in the State of Arizona.

2. Decision No. 59943 enacted R14-2-1601 through -1616, the Retail Electric
Competition Rules.

3. Following a hearing on generic issues related to stranded costs, the
Commission issued Decision No. 60977, dated June 22, 1998.

4. Decision No. 61071 adopted the Emergency Rules on a permanent basis.

5. On August 21, 1998, APS filed its Stranded Costs plan.

6. On November 5, 1998, APS filed the Staff Settlement Proposal.

7. Our November 24, 1998 Procedural Order set the matter for hearing.

8. Decision No. 61259 established an expedited procedural schedule for
evidentiary hearings on the Staff Settlement Proposal.

9. The Court issued a Stay of the Commission's consideration of the Staff
Settlement Proposal.

10. Staff withdrew the Staff Settlement Proposal from Commission
consideration.

11. On May 17, 1999, APS filed its Settlement requesting Commission
approval.

12. Our May 25, 1999 Procedural Order set the Settlement for hearing
commencing on July 14, 1999.

13. Decision No. 61311 (January 11, 1999) stayed the effectiveness of the
Emergency Rules and related Decisions, and ordered the Hearing Division to
conduct further proceedings in this Docket.

15 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

14. In Decision No. 61634 (April 23, 1999), the Commission adopted
modifications to R14-2-201 through-207, -210 and 212 and R14-2-1601 through
- -1617.

15. Pursuant to Decision No. 61677, dated April 27, 1999, the Commission
modified Decision No. 60977 whereby each Affected Utility could choose one of
the following options: (a) Net Revenues Lost Methodology; (b)
Divestiture/Auction Methodology; (c) Financial Integrity Methodology; (d)
Settlement Methodology; and (e) the Alternative Methodology.

16. APS and other Affected Utilities filed with the Arizona Superior Court
various appeals of Commission Orders adopting the Competition Rules and related
Stranded Cost Decisions (the "Outstanding Litigation").

17. Pursuant to Decision No. 61677, APS, RUCO, AECC, and ACAA entered into
the Settlement to resolve numerous issues, including stranded costs and
unbundled tariffs.

18. The difference between market based prices and the cost of regulated
power has been generally referred to as stranded costs.

19. Any stranded cost recovery methodology must balance the interests of
the Affected Utilities, ratepayers, and the move toward competition.

20. All current and future customers of the Affected Utilities should pay
their fair share of stranded costs.

21. Pursuant to the terms of the Settlement Agreement, APS has agreed to
the modification of its CC&N in order to implement competitive retail access in
its Service Territory.

22. The Settlement Agreement provides for competitive retail access in APS'
Service Territory, establishes rate reductions for all APS customers, sets a
mechanism for stranded cost recovery, resolves contentious litigation, and
therefore, is in the public interest and should be approved.

23. The information and formula for rate reductions contained in Exhibit
AP-3 Appended to APS Exhibit No. 2 provides current financial support for the
proposed rates.

24. RUCO, ACAA, and AECC collectively, represent residential and
non-residential customers.

25. According to AECC, the Agreement results in higher shopping credits
than in the Staff

16 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

Settlement Proposal as well as those offered by SRP.

26. The decremental approach for metering and billing will not provide
sufficient credits for competitors to compete.

27. Pursuant to the Settlement, customers will receive substantial rate
reductions without the necessity of a full rate case.

28. An APS rate case would take a minimum of one year to complete.

29. ESPs that have been certificated have shown more of an interest in
serving larger business customers than residential customers.

30. It is not in the public or customers' interests to forego guaranteed
Standard Offer rate reductions in order to have a higher shopping credit.

31. The Settlement will permit competition in a timely and efficient manner
and insure all customers benefit during the transition period.

32. Based on the evidence presented, the FVRB and FVROR of APS is
determined to be $5,195,675,000 and 6.63 percent, respectively.

33. The terms and conditions of the Settlement Agreement as modified herein
are just and reasonable and in the public interest.

CONCLUSIONS OF LAW

1. The Affected Utilities are public service corporations within the
meaning of the Arizona Constitution, Article XV, under A.R.S. ss.ss. 40-202,
- -203, -250, -321, -322, -331, -336, -361, -365, -367, and under the Arizona
Revised Statutes, Title 40, generally.

2. The Commission has jurisdiction over the Affected Utilities and of the
subject matter contained herein.

3. Notice of the proceeding has been given in the manner prescribed by law.

4. The Settlement Agreement as modified herein is just and reasonable and
in the public interest and should be approved.

5. APS should be authorized to implement its Stranded Cost Recovery Plan as
set forth in the Settlement Agreement.

6. APS' CC&N should be modified in order to permit competitive retail
access in APS'

17 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

CC&N service territory.

7. The requested statutory waivers should not be granted at this time. A
proceeding should be commenced to consider statutory waivers on an industry-wide
basis. The other waivers requested by APS in the Settlement should be granted as
modified herein, except that the provisions of A.A.C. R14-2-804(A) shall not be
waived.

ORDER

IT IS THEREFORE ORDERED that the Settlement Agreement as modified
herein is hereby approved and all Commission findings, approvals and
authorizations requested therein are hereby granted.

IT IS FURTHER ORDERED that Arizona Public Service Company's CC&N is
hereby modified to permit competitive retail access consistent with this
Decision and the Competition Rules.

IT IS FURTHER ORDERED that within 30 days of the date of this Decision,
Arizona Public Service Company shall file a proposed Code of Conduct for
Commission approval.

IT IS FURTHER ORDERED that Arizona Public Service Company shall file a
revised Settlement Agreement consistent with the modifications herein.

18 DECISION NO. 61973
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DOCKET NO. E-01345A-98-0473 ET AL.

IT IS FURTHER ORDERED that within ten days of the date the proposed Code of
Conduct is filed, the Hearing Division shall issue a Procedural Order setting a
procedural schedule for consideration of the Code of Conduct.

IT IS FURTHER ORDERED that this Decision shall become effective
immediately. BY ORDER OF THE ARIZONA CORPORATION COMMISSION.

Carl J. Kunasek William A. Mundell
- --------------------------------------------------------------------------------
CHAIRMAN COMMISSIONER COMMISSIONER

IN WITNESS WHEREOF, I, BRIAN C. McNEIL,
Executive Secretary of the Arizona
Corporation Commission, have hereunto
set my hand and caused the official seal
of the Commission to be affixed at the
Capitol, in the City of Phoenix, this
6th day of October, 1999.

Brian C. McNeil
-------------------------------
BRIAN C. McNEIL
EXECUTIVE SECRETARY

DISSENT _________________
JLR:dap

19 DECISION NO. 61973
<PAGE>
DOCKET NO. E-01345A-98-0473 ET AL.

SERVICE LIST FOR: ARIZONA PUBLIC SERVICE COMPANY

DOCKET NOS.: E-01345A-98-0473, E-01345A-97-0773 and
RE-00000C-94-0165

Service List for RE-00000C-94-0165

Paul A. Bullis, Chief Counsel
LEGAL DIVISION
1200 W. Washington Street
Phoenix, Arizona 85007

Utilities Division Director
ARIZONA CORPORATION COMMISSION
1200 W. Washington Street
Phoenix, Arizona 85007

20 DECISION NO. 61973
<PAGE>
ATTACHMENT 1
SETTLEMENT AGREEMENT

May 14, 1999

This settlement agreement ("Agreement") is entered into as of May 14,
1999, by Arizona Public Service Company ("APS" or the "Company") and the various
signatories to this Agreement (collectively, the "Parties") for the purpose of
establishing terms and conditions for the introduction of competition in
generation and other competitive services that are just, reasonable and in the
public interest.

INTRODUCTION

In Decision No. 59943, dated December 26, 1996, the Arizona Corporation
Commission ("ACC" or the "Commission") established a "framework" for
introduction of competitive electric services throughout the territories of
public service corporations in Arizona in the rules adopted in A.A.C. R14-2-1601
ET SEQ. (collectively, "Electric Competition Rules" as they may be amended from
time to time). The Electric Competition Rules established by that order
contemplated future changes to such rules and the possibility of waivers or
amendments for particular companies under appropriate circumstances. Since their
initial issuance, the Electric Competition Rules have been amended several times
and are currently stayed pursuant to Decision No. 61311, dated January 5, 1999.
During this time, APS, Commission Staff and other interested parties have
participated in a number of proceedings, workshops, public comment sessions and
individual negotiations in order to further refine and develop a restructured
utility industry in Arizona that will provide meaningful customer choice in a
manner that is just, reasonable and in the public interest.

This Agreement establishes the agreed upon transition for APS to a
restructured entity and will provide customers with competitive choices for
generation and certain other retail services. The Parties believe this Agreement
will produce benefits for all customers through implementing customer choice and
providing rate reductions so that the APS service territory may benefit from
economic growth. The Parties also believe this Agreement will fairly treat APS
and its shareholders by providing a reasonable opportunity to recover prudently
incurred investments and costs, including stranded costs and regulatory assets.

Specifically, the Parties believe the Agreement is in the public interest
for the following reasons. FIRST, customers will receive substantial rate
reductions. SECOND, competition will be promoted through the introduction of
retail access faster than would have been possible without this Agreement and by
the functional separation of APS' power production and delivery functions.
THIRD, economic development and the environment will
<PAGE>
benefit through guaranteed rate reductions and the continuation of renewable and
energy efficiency programs. FOURTH, universal service coverage will be
maintained through APS' low income assistance programs and establishment of
"provider of last resort" obligations on APS for customers who do not wish to
participate in retail access. FIFTH, APS will be able to recover its regulatory
assets and stranded costs as provided for in this Agreement without the
necessity of a general rate proceeding. Sixth, substantial litigation and
associated costs will be avoided by amicably resolving a number of important and
contentious issues that have already been raised in the courts and before the
Commission. Absent approval by the Commission of the settlement reflected by
this Agreement, APS would seek full stranded cost recovery and pursue other rate
and competitive restructuring provisions different than provided for herein. The
other Parties would challenge at least portions of APS' requested relief,
including the recovery of all stranded costs. The resulting regulatory hearings
and related court appeals would delay the start of competition and drain the
resources of all Parties.

NOW, THEREFORE, APS and the Parties agree to the following provisions
which they believe to be just, reasonable and in the public interest:

TERMS OF AGREEMENT

ARTICLE I
IMPLEMENTATION OF RETAIL ACCESS

1.1 The APS distribution system shall be open for retail access on July 1,
1999; provided, however, that such retail access to electric generation and
other competitive electric services suppliers will be phased in for customers in
APS' service territory in accordance with the proposed Electric Competition
Rules, as and when such rules become effective, with an additional 140 MW being
made available to eligible non-residential customers. The Parties shall urge the
Commission to approve Electric Competition Rules, at least on an emergency
basis, so that meaningful retail access can begin by July 1, 1999. Unless
subject to judicial or regulatory restraint, APS shall open its distribution
system to retail access for all customers on January 1, 2001.

1.2 APS will make retail access available to residential customers
pursuant to its December 21, 1998, filing with the Commission.

1.3 The Parties acknowledge that APS' ability to offer retail access is
contingent upon numerous conditions and circumstances, a number of which are not
within the direct control of the Parties. Accordingly, the Parties agree that it
may become necessary to modify the terms of retail access to account for such
factors, and they further agree to address such matters in good faith and to
cooperate in an effort to propose joint resolutions of any such matters.

2
<PAGE>
1.4. APS agrees to the amendment and modification of its Certificate(s) of
Convenience and Necessity to permit retail access consistent with the terms of
this Agreement. The Commission order adopting this Agreement shall constitute
the necessary Commission Order amending and modifying APS' CC&Ns to permit
retail access consistent with the terms of this Agreement.

ARTICLE II
RATE MATTERS

2.1. The Company's unbundled rates and charges attached hereto as Exhibit
A will be effective as of July 1, 1999. The Company's presently authorized rates
and charges shall be deemed its standard offer ("Standard Offer") rates for
purposes of this Agreement and the Electric Competition Rules. Bills for
Standard Offer service shall indicate individual unbundled service components to
the extent required by the Electric Competition Rules.

2.2. Future reductions of standard offer tariff rates of 1.5% for
customers having loads of less than 3 MW shall be effective as of July 1, 1999,
July 1, 2000, July 1, 2001, July 1, 2002, and July 1, 2003, upon the filing and
Commission acceptance of revised tariff sheets reflecting such decreases. For
customers having loads greater than 3 MW served on Rate Schedules E-34 and E-35,
Standard Offer tariff rates will be reduced: 1.5%, effective July 1, 1999; 1.5%
effective July 1, 2000; 1.25% effective July 1, 2001; and .75% effective July 1,
2002. The 1.5% Standard Offer rate reduction to be effective July 1, 1999,
includes the rate reduction otherwise required by Decision No. 59601. Such
decreases shall become effective by the filing with and acceptance by the
Commission of revised tariff sheets reflecting each decrease.

2.3. Customers greater than 3 MW who choose a direct access supplier must
give APS one year's advance notice before being eligible to return to Standard
Offer service.

2.4. Unbundled rates shall be reduced in the amounts and at the dates set
forth in Exhibit A attached hereto upon the filing and Commission acceptance of
revised tariff sheets reflecting such decreases.

2.5. This Agreement shall not preclude APS from requesting, or the
Commission from approving, changes to specific rate schedules or terms and
conditions of service, or the approval of new rates or terms and conditions of
service, that do not significantly affect the overall earnings of the Company or
materially modify the tariffs or increase the rates approved in this Agreement.
Nothing contained in this Agreement shall preclude APS from filing changes to
its tariffs or terms and conditions of service which are not inconsistent with
its obligations under this Agreement.

2.6. Notwithstanding the rate reduction provisions stated above, the
Commission shall, prior to December 31, 2002, approve an adjustment clause or
clauses which

3
<PAGE>
will provide full and timely recovery beginning July 1, 2004, of the reasonable
and prudent costs of the following:

(1) APS' "provider of last resort" and Standard Offer obligations for
service after July 1, 2004, which costs shall be recovered only from
Standard Offer and "provider of last resort" customers;

(2) Standard Offer service to customers who have left Standard Offer
service or a special contract rate for a competitive generation
supplier but who desire to return to Standard Offer service, which
costs shall be recovered only from Standard Offer and "provider of
last resort" customers;

(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; and

(4) Commission-approved system benefit programs or levels not included in
Standard Offer rates as of June 30, 1999, which costs shall be
recovered from all customers receiving services from APS.

By June 1, 2002, APS shall file an application for an adjustment clause or
clauses, together with a proposed plan of administration, and supporting
testimony. The Commission shall thereafter issue a procedural order setting such
adjustment clause application for hearing and including reasonable provisions
for participation by other parties. The Commission order approving the
adjustment clauses shall also establish reasonable procedures pursuant to which
the Commission, Commission Staff and interested parties may review the costs to
be recovered. By June 30, 2003, APS will file its request for the specific
adjustment clause factors which shall, after hearing and Commission approval,
become effective July 1, 2004. APS shall be allowed to defer costs covered by
this Section 2.6 when incurred for later full recovery pursuant to such
adjustment clause or clauses, including a reasonable return.

2.7. By June 30, 2003, APS shall file a general rate case with prefiled
testimony and supporting schedules and exhibits; provided, however, that any
rate changes resulting therefrom shall not become effective prior to July 1,
2004.

2.8. APS shall not be prevented from seeking 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 the inability to finance on
reasonable terms, or (b) material changes in APS' cost of service for Commission
regulated services resulting from federal, tribal,

4
<PAGE>
state or local laws, regulatory requirements, judicial decision, 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.

ARTICLE III
REGULATORY ASSETS AND STRANDED COSTS

3.1. APS currently recovers regulatory assets through July 1, 2004,
pursuant to Commission Decision No. 59601 in accordance with the provisions of
this Agreement.

3.2. APS has demonstrated that its allowable stranded costs after
mitigation (which result from the impact of retail access), exclusive of
regulatory assets, are at least $533 million net present value.

3.3. The Parties agree that APS should not be allowed to recover $183
million net present value of the amounts included above. APS shall have a
reasonable opportunity to recover $350 million net present value through a
competitive transition charge ("CTC") set forth in Exhibit A attached hereto.
Such CTC shall remain in effect until December 31, 2004, at which time it will
terminate. If by that date APS has recovered more or less than $350 million net
present value, as calculated in accordance with Exhibit B attached hereto, then
the nominal dollars associated with any excess recovery/under recovery shall be
credited/debited against the costs subject to recovery under the adjustment
clause set forth in Section 2.6(3).

3.4. The regulatory assets to be recovered under this Agreement, after
giving effect to the adjustments set forth in Section 3.3, shall be amortized in
accordance with Schedule C of Exhibit A attached hereto.

3.5. Neither the Parties nor the Commission shall take any action that
would diminish the recovery of APS' stranded costs or regulatory assets provided
for herein. The Company's willingness to enter into this Agreement is based upon
the Commission's irrevocable promise to permit recovery of the Company's
regulatory assets and stranded costs as provided herein. Such promise by the
Commission shall survive the expiration of the Agreement and shall be
specifically enforceable against this and any future Commission.

ARTICLE IV
CORPORATE STRUCTURE

4.1. The Commission will approve the formation of an
affiliate or affiliates of APS to acquire at book value the competitive services
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

5
<PAGE>
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).

4.2. Approval of this Agreement by the Commission shall be deemed to
constitute all requisite Commission approvals for (1) the creation by APS or its
parent of new corporate affiliates to provide competitive services including,
but not limited to, generation sales and power marketing, and the transfer
thereto of APS' generation assets and competitive services, and (2) the full and
timely recovery through the adjustment clause referred to in Section 2.6 above
for all of the reasonable and prudent costs so incurred in separating
competitive generation assets and competitive services as required by proposed
A.A.C. R14-2-1615, exclusive of the costs of transferring the APS power
marketing function to an affiliate. The assets and services to be transferred
shall include the items set forth on Exhibit C attached hereto. Such transfers
may require various regulatory and third party approvals, consents or waivers
from entities not subject to APS' control, including the FERC and the NRC. No
Party to this Agreement (including the Commission) will oppose, or support
opposition to, APS requests to obtain such approvals, consents or waivers.

4.3. Pursuant to A.R.S. ss. 40-202(L), the Commission's
approval of this Agreement shall exempt any competitive service provided by APS
or its affiliates from the application of various provisions of A.R.S. Title 40,
including A.R.S. ss.ss. 40-203, 40-204(A), 40-204(B), 40-248, 40-250, 40-251,
40-285, 40-301, 40-302, 40-303, 40-321, 40-322, 40-331, 40-332, 40-334, 40-365,
40-366, 40-367 and 40-401.

4.4. APS' subsidiaries and affiliates (including APS' parent) may take
advantage of competitive business opportunities in both energy and non-energy
related businesses by establishing such unregulated affiliates as they deem
appropriate, which will be free to operate in such places as they may determine.
The APS affiliate or affiliates acquiring APS' generating assets may be a
participant in the energy supply market within and outside of Arizona. Approval
of this Agreement by the Commission shall be deemed to include the following
specific determinations required under Sections 32(c) and (k)(2) of the Public
Utility Holding Company Act of 1935:

APS or an affiliate is authorized to establish a subsidiary company,
which will seek exempt wholesale generator ("EWG") status from the
Federal Energy Regulatory Commission, for the purposes of acquiring and
owning Generation Assets.

The Commission has determined that allowing the Generation Assets to
become "eligible facilities," within the meaning of Section 32 of the
Public Utility Holding Company Act ("PUHCA"), and owned by an APS EWG
affiliate (1) will benefit consumers, (2) is in the public interest,
and (3) does not violate Arizona law.

6
<PAGE>
The Commission has sufficient regulatory authority, resources and
access to the books and records of APS and any relevant associate,
affiliate, or subsidiary company to exercise its duties under Section
32(k) of PUHCA.

APS will purchase any electric energy from its EWG affiliate at market
based rates. This Commission has determined that (1) the proposed
transaction will benefit consumers and does not violate Arizona law;
(2) the proposed transaction will not provide APS' EWG affiliate an
unfair competitive advantage by virtue of its affiliation with APS; (3)
the proposed transaction is in the public interest.

The APS affiliate or affiliates acquiring APS' generating assets will be subject
to regulation by the Commission, to the extent otherwise permitted by law, to no
greater manner or extent than that manner and extent of Commission regulation
imposed upon other owners or operators of generating facilities.

4.5. The Commission's approval of this Agreement will constitute certain
waivers to APS and its affiliates (including its parent) of the Commission's
existing affiliate interest rules (A.A.C. R14-2-801, ET SEQ.), and the
rescission of all or portions of certain prior Commission decisions, all as set
forth on Exhibit D attached hereto.

4.6. The Parties reserve their rights under Sections 205 and 206 of the
Federal Power Act with respect to the rates of any APS affiliate formed under
the provisions of this Article IV.

ARTICLE V
WITHDRAWAL OF LITIGATION

5.1. Upon receipt of a final order of the Commission approving this
Agreement that is no longer subject to judicial review, APS and the Parties
shall withdraw with prejudice all of their various court appeals of the
Commission's competition orders.

ARTICLE VI
APPROVAL BY THE COMMISSION

6.1. This Agreement shall not become effective until the issuance of a
final Commission order approving this Agreement without modification on or
before August 1, 1999. In the event that the Commission fails to approve this
Agreement without modification according to its terms on or before August 1,
1999, any Party to this Agreement may withdraw from this Agreement and shall
thereafter not be bound by its provisions; provided, however, that if APS
withdraws from this Agreement, the Agreement shall be null and void and of no
further force and effect. In any event, the rate reduction provisions of this
Agreement shall not take effect until this Agreement is approved. Parties so
withdrawing shall be free to pursue

7
<PAGE>
their respective positions without prejudice. Approval of this Agreement by the
Commission shall make the Commission a Party to this Agreement and fully bound
by its provisions.

6.2. The Parties agree that they shall make all reasonable and good faith
efforts necessary to (1) obtain final approval of this Agreement by the
Commission, and (2) ensure full implementation and enforcement of all the terms
and conditions set forth in this Agreement. Neither the Parties nor the
Commission shall take or propose any action which would be inconsistent with the
provisions of this Agreement. All Parties shall actively defend this Agreement
in the event of any challenge to its validity or implementation.

ARTICLE VII
MISCELLANEOUS MATTERS

7.1. To the extent any provision of this Agreement is inconsistent with
any existing or future Commission order, rule or regulation or is inconsistent
with the Electric Competition Rules as now existing or as may be amended in the
future, the provisions of this Agreement shall control and the approval of this
Agreement by the Commission shall be deemed to constitute a Commission-approved
variation or exemption to any conflicting provision of the Electric Competition
Rules.

7.2. The provisions of this Agreement shall be implemented and enforceable
notwithstanding the pendency of a legal challenge to the Commission's approval
of this Agreement, unless such implementation and enforcement is stayed or
enjoined by a court having jurisdiction over the matter. If any portion of the
Commission order approving this Agreement or any provision of this Agreement is
declared by a court to be invalid or unlawful in any respect, then (1) APS shall
have no further obligations or liability under this Agreement, including, but
not limited to, any obligation to implement any future rate reductions under
Article II not then in effect, and (2) the modifications to APS' certificates of
convenience and necessity referred to in Section 1.4 shall be automatically
revoked, in which event APS shall use its best efforts to continue to provide
noncompetitive services (as defined in the proposed Electric Competition Rules)
at then current rates with respect to customer contracts then in effect for
competitive generation (for the remainder of their term) to the extent not
prohibited by law and subject to applicable regulatory requirements.

7.3. The terms and provisions of this Agreement apply solely to and are
binding only in the context of the purposes and results of this Agreement and
none of the positions taken herein by any Party may be referred to, cited or
relied upon by any other Party in any fashion as precedent or otherwise in any
other proceeding before this Commission or any other regulatory agency or before
any court of law for any purpose except in furtherance of the purposes and
results of this Agreement.

7.4. This Agreement represents an attempt to compromise and settle
disputed claims regarding the prospective just and reasonable rate levels, and
the terms and conditions

8
<PAGE>
of competitive retail access, for APS in a manner consistent with the public
interest and applicable legal requirements. Nothing contained in this Agreement
is an admission by APS that its current rate levels or rate design are unjust or
unreasonable.

7.5. As part of this Agreement, APS commits that it will continue the
APS Community Action Partnership (which includes weatherization, facility repair
and replacement, bill assistance, health and safety programs and energy
education) in an annual amount of at least $500,000 through July 1, 2004.
Additionally, the Company will, subject to Commission approval, continue low
income rates E-3 and E-4 under their current terms and conditions.

7.6. APS shall actively support the Arizona Independent Scheduling
Administrator ("AISA") and the formation of the Desert Star Independent System
Operator. APS agrees to modify its OATT to be consistent with any FERC approved
AISA protocols. The Parties reserve their rights with respect to any AISA
protocols, including the right to challenge or seek modifications to, or waivers
from, such protocols. APS shall file changes to its existing OATT consistent
with this section within ten (10) days of Commission approval of this Agreement
pursuant to Section 6.1.

7.7. Within thirty (30) days of Commission approval of this Agreement
pursuant to Section 6.1, APS shall serve on the Parties an Interim Code of
Conduct to address inter-affiliate relationships involving APS as a utility
distribution company. APS shall voluntarily comply with this Interim Code of
Conduct until the Commission approves a code of conduct for APS in accordance
with the Electric Competition Rules that is concurrently effective with codes of
conduct for all other Affected Utilities (as defined in the Electric Competition
Rules). APS shall meet and confer with the Parties prior to serving its Interim
Code of Conduct.

7.8. In the event of any disagreement over the interpretation of this
Agreement or the implementation of any of the provisions of this Agreement, the
Parties shall promptly convene a conference and in good faith shall attempt to
resolve such disagreement.

7.9. The obligations under this Agreement that apply for a specific term
set forth herein shall expire automatically in accordance with the term
specified and shall require no further action for their expiration.

7.10. The Parties agree and recommend that the Commission schedule
public meetings and hearings for consideration of this Agreement. The filing of
this Agreement with the Commission shall be deemed to be the filing of a formal
request for the expeditious issuance of a procedural schedule that establishes
such formal hearings and public meetings as may be necessary for the Commission
to approve this Agreement in accordance with

9
<PAGE>
Section 6.1 and that afford interested parties adequate opportunity to comment
and be heard on the terms of this Agreement consistent with applicable legal
requirements.

DATED at Phoenix, Arizona, as of this 14th day of May, 1999.

RESIDENTIAL UTILITY ARIZONA PUBLIC SERVICE COMPANY
CONSUMER OFFICE

By Greg Patterson By Jack E. Davis
------------------------------- -------------------------------

Title Director Title President, Energy
---------------------------- -------------------------------
Delivery & Sales
-------------------------------

ARIZONA COMMUNITY ACTION (Party)
ASSOCIATION ------------------------------------

By Janet Regner By
------------------------------- -------------------------------

Title Executive Director Title
---------------------------- ------------------------------

ARIZONANS FOR ELECTRIC CHOICE AND (Party)
COMPETITION,* a coalition of companies ------------------------------------
and associations in support of
competition that includes Cable Systems
International, BHP Copper, Motorola, By
Chemical Lime, Intel, Honeywell, -------------------------------
Allied Signal, Cyprus Climax Metals,
Asarco, Phelps Dodge, Homebuilders Title
of Central Arizona, Arizona Mining ------------------------------
Industry Gets Our Support, Arizona
Food Marketing Alliance, Arizona
Association of Industries, Arizona
Multi-housing Association, Arizona Rock
Products Association, Arizona Restaurant (Party)
Association, and Arizona Retailers ----------------------------------
Association.

By Peter A. Woog By
------------------------------- -------------------------------

Title Chairman Title
---------------------------- ----------------------------

* Enron is not a signatory to this Agreement.

* Also included: Boeing, AZ School Board Association, National Federation of
Independent Business (NFIB), AZ Hospital Association, Lockheed Martin, Abbot
Labs, Raytheon
10
<PAGE>
(Party) (Party)
- --------------------------------- ---------------------------------

By By
------------------------------- -------------------------------

Title Title
---------------------------- ----------------------------

(Party) (Party)
- --------------------------------- ---------------------------------