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 June 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _____________ to _____________
Commission file number 1-4473
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 August 16, 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 Applications 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
ITC - Investment tax credit
March 10-Q - Arizona Public Service Company Quarterly Report on Form 10-Q for
the fiscal quarter ended March 31, 1999
1998 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 1998
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
Power Coordination Agreement - 1955 agreement between the Company and Salt River
Project that provides for certain electric system and power sales
SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"
SFAS No. 133 - Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities"
Salt River Project - Salt River Project Agricultural Improvement and Power
District
Territorial Agreement - 1955 agreement between the Company and Salt River
Project that has provided exclusive retail service territories in Arizona for
each party
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PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Three Months
Ended June 30,
----------------------
1999 1998
--------- ---------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES .......................... $ 511,434 $ 441,715
--------- ---------
FUEL EXPENSES:
Fuel for electric generation ....................... 58,283 50,434
Purchased power .................................... 74,260 45,151
--------- ---------
Total ............................................ 132,543 95,585
--------- ---------
OPERATING REVENUES LESS FUEL EXPENSES ................ 378,891 346,130
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel
expenses ......................................... 104,404 102,713
Depreciation and amortization ...................... 96,533 92,666
Income taxes ....................................... 49,856 39,933
Other taxes ........................................ 29,595 29,519
--------- ---------
Total ............................................ 280,388 264,831
--------- ---------
OPERATING INCOME ..................................... 98,503 81,299
--------- ---------
OTHER INCOME (DEDUCTIONS):
Other - net ........................................ (1,485) (2,519)
Income taxes ....................................... 7,227 7,488
--------- ---------
Total ............................................ 5,742 4,969
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS .................... 104,245 86,268
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ......................... 33,868 34,160
Interest on short-term borrowings .................. 1,936 2,376
Debt discount, premium and expense ................. 1,912 1,918
Capitalized interest ............................... (3,013) (4,370)
--------- ---------
Total ............................................ 34,703 34,084
--------- ---------
NET INCOME ........................................... 69,542 52,184
PREFERRED STOCK DIVIDEND REQUIREMENTS ................ -- 2,435
--------- ---------
EARNINGS FOR COMMON STOCK ............................ $ 69,542 $ 49,749
========= =========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Six Months
Ended June 30,
----------------------
1999 1998
--------- ---------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES .......................... $ 925,417 $ 822,138
--------- ---------
FUEL EXPENSES:
Fuel for electric generation ....................... 110,399 100,762
Purchased power .................................... 121,385 68,740
--------- ---------
Total ............................................ 231,784 169,502
--------- ---------
OPERATING REVENUES LESS FUEL EXPENSES ................ 693,633 652,636
--------- ---------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel
expenses ......................................... 201,808 199,129
Depreciation and amortization ...................... 192,672 184,813
Income taxes ....................................... 74,659 64,397
Other taxes ........................................ 59,035 59,457
--------- ---------
Total ............................................ 528,174 507,796
--------- ---------
OPERATING INCOME ..................................... 165,459 144,840
--------- ---------
OTHER INCOME (DEDUCTIONS):
Other - net ........................................ (4,419) (4,915)
Income taxes ....................................... 11,482 11,943
--------- ---------
Total ............................................ 7,063 7,028
--------- ---------
INCOME BEFORE INTEREST DEDUCTIONS .................... 172,522 151,868
--------- ---------
INTEREST DEDUCTIONS:
Interest on long-term debt ......................... 67,424 69,343
Interest on short-term borrowings .................. 4,004 3,060
Debt discount, premium and expense ................. 3,757 3,867
Capitalized interest ............................... (5,999) (8,521)
--------- ---------
Total ............................................ 69,186 67,749
--------- ---------
NET INCOME ........................................... 103,336 84,119
PREFERRED STOCK DIVIDEND REQUIREMENTS ................ 1,016 5,313
--------- ---------
EARNINGS FOR COMMON STOCK ............................ $ 102,320 $ 78,806
========= =========
See Notes to Condensed Financial Statements
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
Twelve Months
Ended June 30,
-------------------------
1999 1998
----------- -----------
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES ........................ $ 2,109,677 $ 1,862,919
----------- -----------
FUEL EXPENSES:
Fuel for electric generation ..................... 241,604 195,355
Purchased power .................................. 358,179 225,995
----------- -----------
Total .......................................... 599,783 421,350
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES .............. 1,509,894 1,441,569
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel
expenses......................................... 416,720 421,385
Depreciation and amortization .................... 384,433 367,331
Income taxes ..................................... 202,469 177,263
Other taxes ...................................... 114,842 120,070
----------- -----------
Total .......................................... 1,118,464 1,086,049
----------- -----------
OPERATING INCOME ................................... 391,430 355,520
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net ...................................... (11,807) (11,623)
Income taxes ..................................... 32,290 32,466
----------- -----------
Total .......................................... 20,483 20,843
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS .................. 411,913 376,363
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ....................... 135,295 140,583
Interest on short-term borrowings ................ 8,425 7,041
Debt discount, premium and expense ............... 7,470 7,600
Capitalized interest ............................. (13,741) (16,335)
----------- -----------
Total .......................................... 137,449 138,889
----------- -----------
NET INCOME ......................................... 274,464 237,474
PREFERRED STOCK DIVIDEND REQUIREMENTS .............. 5,406 11,295
----------- -----------
EARNINGS FOR COMMON STOCK .......................... $ 269,058 $ 226,179
=========== ===========
See Notes to Condensed Financial Statements.
<PAGE>
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
June 30, December 31,
1999 1998
(Unaudited)
----------- -----------
(Thousands of Dollars)
UTILITY PLANT:
Electric plant in service and held for
future use....................................... $ 7,370,852 $ 7,265,604
Less accumulated depreciation and amortization ... 2,941,878 2,814,762
----------- -----------
Total .......................................... 4,428,974 4,450,842
Construction work in progress .................... 247,910 228,643
Nuclear fuel, net of amortization ................ 50,446 51,078
----------- -----------
Utility plant - net ............................ 4,727,330 4,730,563
----------- -----------
INVESTMENTS AND OTHER ASSETS ..................... 204,986 183,549
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents ........................ 11,686 5,558
Accounts receivable:
Service customers .............................. 154,871 205,999
Other .......................................... 41,650 23,213
Allowance for doubtful accounts ................ (1,410) (1,725)
Accrued utility revenues ......................... 98,046 67,740
Materials and supplies, at average cost .......... 70,919 69,074
Fossil fuel, at average cost ..................... 17,786 13,978
Deferred income taxes ............................ 3,999 3,999
Other ............................................ 30,647 26,695
----------- -----------
Total current assets ........................... 428,194 414,531
----------- -----------
DEFERRED DEBITS:
Regulatory asset for income taxes ................ 373,417 400,795
Rate synchronization cost deferral ............... 276,055 303,660
Unamortized costs of reacquired debt ............. 49,253 53,744
Unamortized debt issue costs ..................... 15,376 14,916
Other ............................................ 293,744 291,541
----------- -----------
Total deferred debits .......................... 1,007,845 1,064,656
----------- -----------
TOTAL .......................................... $ 6,368,355 $ 6,393,299
=========== ===========
See Notes to Condensed Financial Statements.
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES
June 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 ................................... 575,607 601,968
---------- ----------
Common stock equity ............................... 1,950,573 1,975,755
Non-redeemable preferred stock ...................... -- 85,840
Redeemable preferred stock .......................... -- 9,401
Long-term debt less current maturities .............. 1,955,137 1,876,540
---------- ----------
Total capitalization .............................. 3,905,710 3,947,536
---------- ----------
CURRENT LIABILITIES:
Commercial paper .................................... 223,950 178,830
Current maturities of long-term debt ................ 14,542 164,378
Accounts payable .................................... 124,643 145,139
Accrued taxes ....................................... 149,149 59,827
Accrued interest .................................... 32,209 31,218
Common stock dividends payable ...................... 85,000 --
Customer deposits ................................... 24,124 26,815
Other ............................................... 16,557 16,755
---------- ----------
Total current liabilities ......................... 670,174 622,962
---------- ----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ............................... 1,287,784 1,312,007
Deferred investment tax credit ...................... 22,736 32,465
Unamortized gain - sale of utility plant ............ 75,499 77,787
Customer advances for construction .................. 36,191 31,451
Other ............................................... 370,261 369,091
---------- ----------
Total deferred credits and other .................. 1,792,471 1,822,801
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 5, 6, 9, and 10)
TOTAL ............................................. $6,368,355 $6,393,299
========== ==========
See Notes to Condensed Financial Statements.
<PAGE>
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months
Ended June 30,
----------------------
1999 1998
--------- ---------
(Thousands of Dollars)
Cash Flows from Operating Activities:
NET INCOME ......................................... $ 103,336 $ 84,119
Items not requiring cash:
Depreciation and amortization .................... 192,672 184,813
Nuclear fuel amortization ........................ 15,673 16,580
Deferred income taxes - net ...................... (21,445) (18,428)
Deferred investment tax credit - net ............. (9,729) (9,951)
Changes in current assets and liabilities:
Accounts receivable - net ........................ 32,376 9,947
Accrued utility revenues ......................... (30,306) (8,363)
Materials, supplies and fossil fuel .............. (5,653) (8,912)
Other current assets ............................. (3,952) (5,295)
Accounts payable ................................. (17,952) (10,279)
Accrued taxes .................................... 89,322 (7,435)
Accrued interest ................................. 991 83
Other current liabilities ........................ (2,416) 2,922
Other - net ........................................ (9,728) 10,267
--------- ---------
Net cash flow provided by operating activities ....... 333,189 240,068
--------- ---------
Cash Flows from Investing Activities:
Capital expenditures ............................... (153,730) (144,580)
Capitalized interest ............................... (5,999) (8,521)
Other .............................................. 1,172 (3,347)
--------- ---------
Net cash flow used for investing activities .... (158,557) (156,448)
--------- ---------
Cash Flows from Financing Activities:
Long-term debt ..................................... 142,952 99,375
Short-term borrowings - net ........................ 45,120 82,735
Dividends paid on common stock ..................... (42,500) (85,000)
Dividends paid on preferred stock .................. (1,393) (5,631)
Repayment of preferred stock ....................... (96,499) (31,209)
Repayment and reacquisition of long-term debt ...... (216,184) (142,250)
--------- ---------
Net cash flow used for financing activities .... (168,504) (81,980)
--------- ---------
Net increase in cash and cash equivalents ............ 6,128 1,640
Cash and cash equivalents at beginning of period ..... 5,558 12,552
--------- ---------
Cash and cash equivalents at end of period ........... $ 11,686 $ 14,192
========= =========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ........ $ 64,233 $ 63,960
Income taxes ..................................... $ 7,849 $ 86,397
See Notes to Condensed Financial Statements.
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-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. 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 six months ended June 30, 1999.
5. Regulatory Accounting
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. Our
existing regulatory orders and the current regulatory environment support our
accounting practices related to regulatory assets, which amounted to about $850
million at June 30, 1999. Under the 1996 regulatory agreement (see Note 7), the
ACC accelerated the amortization of substantially all of our regulatory assets
to an eight-year period that will end June 30, 2004.
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, which could result in write-downs or write-offs of
physical and/or regulatory assets. Additionally, the EITF determined that
regulatory assets should not be written off if they are to be recovered from a
portion of the entity which continues to apply SFAS No. 71.
Although rules have been proposed for the transition of generation services to
competition, there are many unresolved issues. We continue to apply SFAS No. 71
to our generation operations. If rate recovery of regulatory assets is no longer
probable, whether due to competition or regulatory action, we would be required
to write off the remaining balance as an extraordinary charge to expense. See
Note 6 for a discussion
<PAGE>
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of a proposed settlement agreement which, if approved, would result in the
discontinuation of SFAS No. 71 for generation operations.
6. Regulatory Matters -- Electric Industry Restructuring
STATE
PROPOSED 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. Hearings before the ACC on the Settlement Agreement
ended in July 1999, and a final ACC order, which is a condition to the
agreement's effectiveness, has not yet been issued. By the terms of the
Settlement Agreement, unless ACC approval has been obtained on or before August
1, 1999, each party has the right to unilaterally withdraw from the Settlement
Agreement. To date, no party has elected to withdraw.
The following are the major provisions of the Settlement Agreement:
* 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 includes the July 1, 1999 retail price decrease related to the
1996 regulatory agreement. See Note 7. 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) will become effective as of July 1,
1999, and 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.
* 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 will be open for retail access upon approval of the
Settlement Agreement. Customers will be eligible for retail access in
accordance with the phase-in program expected to be ultimately adopted by
the ACC under the electric competition rules when such rules become
effective, 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.
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* We are currently recovering substantially all of our regulatory assets
through July 1, 2004, pursuant to the 1996 regulatory agreement. See Note
7. 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
thereto our generating assets and competitive services by December 31,
2002.
* Upon final approval of the Settlement Agreement by the ACC in an order no
longer subject to judicial review, we will move to dismiss all of our
litigation pending against the ACC as of the date of the Settlement
Agreement.
Upon final ACC order, we will discontinue the application of Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation," for our generation operations. This means that regulatory
assets, unless reestablished as recoverable through ongoing regulated cash
flows, are to be eliminated and the generation assets must be tested for
impairment. The regulatory disallowance, which removes $234 million pre-tax
($183 million net present value) from ongoing regulatory cash flows, will be
recorded as a net reduction of regulatory assets. This reduction will be
reported as an extraordinary charge on the income statement. The regulatory
assets to be recovered under this Settlement Agreement would be amortized as
follows:
(Millions)
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
- ---- ---- ---- ---- ---- ---------- -----
$164 $158 $145 $115 $86 $18 $686
PROPOSED RETAIL ELECTRIC COMPETITION RULES In December 1996, the ACC
adopted rules that provide a framework for the introduction of retail electric
competition in Arizona. The ACC adopted certain modifications to these rules on
August 10, 1998, and on December 11, 1998, the ACC adopted the amended rules,
without any modifications that would have a significant impact on us, on a
permanent basis. We believe that certain provisions of the 1996 ACC rules and
the amended rules are deficient and we have filed lawsuits to protect our legal
rights regarding the 1996 rules and the amended rules. These lawsuits are
pending but two related cases filed by other utilities have been partially
decided in a manner adverse to those utilities' positions.
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On January 11, 1999, the ACC issued an order which stayed the amended rules,
granted reconsideration of the decision to make the rules permanent, and
directed the hearing division of the ACC to establish a procedural order for
further action on these rules. The order also granted waivers from compliance
with the rules for us, and all affected utilities.
On February 5, 1999, the ACC Hearing Division issued recommendations for changes
to the amended rules. The recommended changes to the amended rules were further
modified by a Procedural Order of the ACC Hearing Division dated March 12, 1999.
On April 14, 1999, the ACC voted to notice, for further rulemaking, the Hearing
Division's recommended changes, with certain exceptions (the "Proposed Rules").
The Proposed Rules approved by the ACC for further rulemaking include the
following major provisions:
* They would apply to virtually all Arizona electric utilities regulated by
the ACC, including us.
* The Proposed 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.
* 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. Customers with single premise loads of
40 kilowatts or greater 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 noncompetitive services.
* The ACC shall allow a reasonable opportunity for recovery of unmitigated
stranded costs (see "Stranded Costs" below).
* Absent an ACC waiver, prior to January 1, 2001, each affected utility must
transfer all competitive generation assets and services either to an
unaffiliated party or to a separate corporate affiliate.
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The Proposed Rules will not become final and effective until approved by the ACC
following formal rulemaking proceedings under Arizona law. In compliance with
statutory procedural requirements, ACC oral proceedings on the matter were held
in June 1999, and a final order has not yet been issued.
We cannot currently predict when or if the Proposed Rules will become effective,
when or if the stay of the amended rules will be lifted, or when retail electric
competition will be introduced in Arizona. See "Proposed Settlement Agreement"
above for discussion of our proposals regarding the introduction of retail
electric competition in Arizona.
STRANDED COSTS On June 22, 1998, the ACC issued an Order on stranded cost
determination and recovery. We believe that certain provisions of the stranded
cost order are deficient and in August 1998, we filed two lawsuits to protect
our legal rights relating to the order.
On February 5, 1999, the ACC Hearing Division issued recommended changes to the
June 1998 stranded cost order. These recommended changes were further amended by
an ACC Procedural Order dated March 12, 1999. On April 14, 1999, the ACC voted
to adopt the Hearing Division's changes to the June 1998 stranded cost order.
The amended stranded cost order became effective on April 27, 1999, and allows
us and each affected utility to choose from any one of five options for the
recovery of stranded costs:
* Net Revenues Lost Methodology is the difference between generation revenues
under traditional regulation and generation revenues under competition.
This option provides for declining recovery percentages for stranded costs
over a five-year recovery period. Regulatory assets are to be fully
recovered under their presently authorized amortization schedule. In
accordance with a 1996 regulatory agreement, the ACC accelerated the
amortization of substantially all of our regulatory assets to an eight-year
period that ends June 30, 2004.
* Divestiture/Auction Methodology allows a utility to divest all or
substantially all of its generating assets, including regulatory assets
associated with generation, in order to collect 100 percent of the
difference between net sales price and book value of generating assets
divested over a ten-year period, with no return on the unamortized balance.
* Financial Integrity Methodology allows a utility "sufficient revenues to
meet minimum financial ratios" for a period of ten years.
* Settlement Methodology allows a settlement to be agreed upon by the ACC and
a utility.
* Any combination of the above, if shown to be in the best interests of all
affected parties.
See "Proposed Settlement Agreement" above for a discussion of the methodology we
proposed.
<PAGE>
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LEGISLATIVE INITIATIVES An Arizona joint legislative committee studied
electric utility industry restructuring issues in 1996 and 1997. In conjunction
with that study, the Arizona legislative counsel prepared memoranda in late 1997
related to the legal authority of the ACC to deregulate the Arizona electric
utility industry. The memoranda raise a question as to 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. This latter
issue has been subsequently decided by lower courts in favor of the ACC in four
separate lawsuits, two of which are unrelated.
In May 1998, a law was enacted to facilitate implementation of retail electric
competition in Arizona. The law includes the following major provisions:
* Arizona's largest government-operated electric utility (Salt River Project)
and, at their option, smaller municipal electric systems must (i) make at
least 20% of their 1995 retail peak demand available to electric service
providers by December 31, 1998 and for all retail customers by December 31,
2000; (ii) decrease rates by at least 10% over a ten-year period beginning
as early as January 1, 1991; (iii) implement procedures and public
processes comparable to those already applicable to public service
corporations for establishing the terms, conditions, and pricing of
electric services as well as certain other decisions affecting retail
electric competition;
* describes the factors which form the basis of consideration by Salt River
Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive basis
during the first two years of competition only for customers having demands
in excess of one 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 legislative session on certain competitive issues.
GENERAL Until the manner of implementation of competition, including
addressing stranded costs, is determined, 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. See "Proposed
Settlement Agreement" above.
<PAGE>
-14-
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. 1996 Regulatory Agreement
In April 1996, the ACC approved a regulatory agreement between the ACC Staff and
us. The major provisions of this agreement are:
* An annual rate reduction of approximately $48.5 million ($29 million after
income taxes), or 3.4% on average for all customers except certain contract
customers, effective July 1, 1996.
* Recovery of substantially all of our present regulatory assets through
accelerated amortization over an eight-year period that will end June 30,
2004, increasing annual amortization by approximately $120 million ($72
million after income taxes).
* A formula for sharing future cost savings between customers and
shareholders (price reduction formula), referencing a return on equity (as
defined) of 11.25%.
* A moratorium on filing for permanent rate changes prior to July 2, 1999,
except under the price reduction formula and under certain other limited
circumstances.
* Infusion of $200 million of common equity by Pinnacle West, in annual
payments of $50 million starting in 1996.
Based on the price reduction formula, the ACC approved retail price decreases of
approximately $17.6 million ($10.5 million after income taxes), or 1.2%,
effective July 1, 1997, and approximately $17 million ($10 million after income
taxes), or 1.1%, effective July 1, 1998. In May 1999, we filed with the ACC for
another retail price decrease of approximately $10.8 million annually ($6.5
million after income taxes), which would become effective as of July 1, 1999.
The amount and timing of the price decrease are subject to ACC approval. This
will be the last price decrease under the 1996 regulatory agreement and will be
included in the first rate reduction under the proposed Settlement Agreement
discussed in Note 6. See "Proposed Settlement Agreement" above for a discussion
of the price decrease.
<PAGE>
-15-
8. 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 the Arizona
electric industry. 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 would amend 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.
* 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) are affected
by the timing of the introduction of competition. See Note 6. On February 18,
1999, the ACC approved the Agreement.
9. 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.
<PAGE>
-16-
10. 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>
-17-
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, six-month and twelve-month periods ended June 30, 1999 and 1998:
Periods ended June 30
(Unaudited)
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
------------------- ------------------- -----------------------
1999 1998 1999 1998 1999 1998
-------- -------- -------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $511,434 $441,715 $925,417 $822,138 $2,109,677 $1,862,919
Earnings for Common Stock $ 69,542 $ 49,749 $102,320 $ 78,806 $ 269,058 $ 226,179
</TABLE>
OPERATING RESULTS - THREE-MONTH PERIOD ENDED JUNE 30, 1999 COMPARED WITH
THREE-MONTH PERIOD ENDED JUNE 30, 1998
Earnings increased $19.8 million in the three-month comparison primarily
because of the effects of warmer weather, an increase in customers and increased
contributions from power marketing and trading activities, partially offset by a
retail price reduction, and higher depreciation and amortization expense. See
Note 7 for information on the price reduction.
<PAGE>
-18-
Operating revenues increased $70 million because of:
* increased power marketing and trading revenues ($36 million)
* the effects of warmer weather ($21 million) and
* increases in the number of customers ($17 million).
As mentioned above, these positive factors were partially offset by the
effect of a reduction in retail prices ($4 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 bulk power markets. The increase in
power marketing and trading revenues was accompanied by increases in purchased
power expenses.
Fuel expenses increased $37 million primarily because of increased
wholesale and retail sales volume and higher purchased power prices.
Depreciation and amortization expense increased $4 million because we had
more plant in service.
OPERATING RESULTS - SIX-MONTH PERIOD ENDED JUNE 30, 1999 COMPARED WITH
SIX-MONTH PERIOD ENDED JUNE 30, 1998
Earnings increased $23.5 million in the six-month comparison primarily
because of an increase in customers, increased contributions from power
marketing and trading activities and the effects of warmer weather, partially
offset by a retail price reduction, and higher depreciation and amortization
expense. See Note 7 for information on the price reduction.
Operating revenues increased $103 million because of:
* increased power marketing and trading revenues ($70 million)
* increases in the number of customers ($29 million)
* the effects of warmer weather ($10 million) and
* miscellaneous factors ($2 million).
As mentioned above, these positive factors were partially offset by 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
from increased activity in western bulk power markets. The increase in power
marketing and trading revenues was accompanied by increases in purchased power
expenses.
Fuel expenses increased $62 million primarily because of increased
wholesale and retail sales volume and higher purchased power prices.
<PAGE>
-19-
Depreciation and amortization expense increased $8 million because we had
more plant in service.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED JUNE 30, 1999 COMPARED WITH
TWELVE-MONTH PERIOD ENDED JUNE 30, 1998
Earnings increased $42.9 million in the twelve-month comparison primarily
because of an increase in customers, increased contributions from power
marketing and trading activities, the effects of warmer weather and lower
financing costs. In the comparison, these positive factors more than offset the
effects of two fuel-related settlements recorded in the third quarter of 1997, a
retail price reduction that became effective July 1, 1998, and higher
depreciation and amortization expense. See Note 7 for additional information
about the price reduction.
Operating revenues increased $247 million primarily because of:
* increased power marketing and trading revenues ($164 million)
* increases in the number of customers and the average amount of
electricity used by customers ($79 million)
* the effects of warmer weather ($15 million) and
* miscellaneous factors ($7 million).
As mentioned above, these positive factors were partially offset by the
effect of a reduction in retail prices ($18 million).
Power marketing and trading activities are predominantly short-term
opportunity wholesale sales. The increase in power marketing revenues resulted
from increased activity in Western bulk power markets, higher prices, and
increased sales to large customers in California. The increase in power
marketing and trading revenues was accompanied by increases in purchased power
expenses.
Fuel expense increased $178 million primarily because of increased
wholesale and retail sales volumes, the effects of two fuel-related settlements
in the third quarter of 1997, and higher purchased power prices. The settlements
increased pretax earnings in the twelve months ended June 30, 1998 by
approximately $21 million. The income statement reflects these settlements as
reductions in fuel expense and as other income.
Depreciation and amortization expense increased $17 million because we had
more plant in service.
Financing costs decreased by $10 million primarily because of lower amounts
of outstanding debt and preferred stock and lower interest rates.
<PAGE>
-20-
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 will be reflected in income
tax expense.
LIQUIDITY AND CAPITAL RESOURCES
For the six months ended June 30, 1999, we incurred approximately $154
million in capital expenditures, which is approximately 47% 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 and payment
obligations on a capitalized lease for the next three years are: 1999, $387
million; 2000, $115 million; and 2001, $2 million. During the six months ended
June 30, 1999, we redeemed approximately $216 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. As a result of the 1996 regulatory
agreement (see Note 7), Pinnacle West invested $50 million in the Company in
1996, 1997 and 1998 and will make the final investment of $50 million in 1999.
Although provisions in our first mortgage bond indenture, articles of
incorporation, and ACC financing orders establish maximum amounts of additional
first mortgage bonds 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 an internal audit/quality review team that is periodically
reviewing the individual Year 2000 projects and their Year 2000 readiness.
<PAGE>
-21-
The following chart shows Year 2000 readiness of our mission critical systems as
of June 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 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. 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.
As previously reported, we expected remediation and testing to be completed by
June 30, 1999, for all mission critical systems, except for (i) Palo Verde Unit
1 systems and (ii) the continuous emissions monitoring systems (CEMS) for four
of our fossil plants. See "Year 2000 Readiness Disclosure" in Part I, Item 2 of
the March 10-Q. However,
<PAGE>
-22-
as of June 30, 1999, remediation and testing was completed for all mission
critical systems, including Palo Verde Unit 1, but excluding CEMS, which have
been removed from the mission critical systems list because the failure of the
system would not lead to an unplanned shutdown of generation. This is based on
NERC's June 14, 1999 clarifying pronouncement on exception reporting. We
currently expect the CEMS for the four fossil plants to be Y2K Ready no later
than the fourth quarter 1999.
We currently estimate that we will spend about $5 million relating to Year 2000
issues, about $4.5 million 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 expect to fund this cost with available cash balances and cash provided by
operations.
We are communicating 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.
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 proposed Settlement Agreement related to the implementation of
retail electric competition. See Note 8 for a discussion of a proposed amendment
to a Power Coordination Agreement with Salt River Project that we estimate would
reduce our
<PAGE>
-23-
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 7 for a discussion of a proposed price reduction that would become
effective as of July 1, 1999. See Note 6 for a discussion of a proposed
Settlement Agreement that would, among other things, result in rate 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.
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 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.
<PAGE>
-24-
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 June 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 $8 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>
-25-
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In June 1999, the Navajo Nation served Salt River Project with a lawsuit
naming Salt River Project, several Peabody Coal Company entities ("Peabody"),
Southern California Edison Company and other defendants, and citing various
claims in connection with the renegotiations of the coal royalty and lease
agreements under which Peabody mines coal for the Navajo and Mohave Generating
Stations. The Navajo Nation v. Peabody Holding Company, Inc., et al., United
States District Court for the District of Columbia, CA-99-0469-EGS. We are a 14%
owner of Navajo Generating Station, which Salt River Project operates. The suit
alleges, among other things, that the defendants obtained a favorable coal
royalty rate by improperly influencing the outcome of a federal administrative
process under which the royalty rate was to be adjusted. The suit seeks $600
million in damages, treble damages, punitive damages of not less than $1
billion, and the ejection of defendants "from all possessory interests and
Navajo Tribal lands" arising out of the [primary coal lease]. Salt River Project
has advised us that it denies all charges and will vigorously defend itself.
Because the litigation is in preliminary stages, we cannot currently predict the
outcome of this matter.
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 proposed settlement
agreement with the ACC.
ENVIRONMENTAL MATTERS
As previously reported, in July 1997, EPA promulgated final national
ambient air quality standards for ozone and coarse and fine particulate matter.
See "Environmental Matters - EPA Environmental Regulation - Clean Air Act" in
Part I, Item 1 of the 1998 10-K. These standards were challenged and the court
determined that EPA's promulgation of the standards violated the constitutional
prohibition on delegation of legislative power. The court remanded the ozone
standard, vacated the coarse particulate matter standard, and invited the
parties to brief the court on vacating or remanding the fine particulate matter
standard. We cannot currently predict EPA's response to this decision.
<PAGE>
-26-
ITEM 6. Exhibits and Reports on Form 8-K
(a) Exhibits
Exhibit No. Description
- ----------- -----------
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
10.1(b) Key Executive Employment 10.1 to Pinnacle West's 1-8962 8-16-99
and Severance Agreement June 1999 Form 10-Q
between Pinnacle West and
certain executive officers
of Pinnacle West and its
subsidiaries
</TABLE>
(b) Reports on Form 8-K
During the quarter ended June 30, 1999, and the period from July 1 through
August 16, 1999, the Company filed the following reports on Form 8-K:
Report dated May 14, 1999 regarding our settlement agreement with various
other parties, including representatives of major consumer groups, related to
the implementation of retail electric competition.
- ----------
(a) Reports filed under File No. 1-4473 were filed in the office of the
Securities and Exchange Commission located in Washington, D.C.
(b) Additional agreements, substantially identical in all material respects to
this Exhibit have been entered into with additional officers of the Pinnacle
West and its subsidiaries. Although such additional documents may differ in
other respects (such as dollar amounts and dates of execution), there are no
material details in which such agreements differ from this Exhibit.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Company has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
Dated: August 16, 1999 By: George A. Schreiber, Jr.
------------------------------------
George A. Schreiber, Jr.
Chief Financial Officer
(Principal Financial Officer
and Officer Duly Authorized
to sign this Report)
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<FISCAL-YEAR-END> DEC-31-1999
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