FORM 10-Q
Securities and Exchange Commission
Washington, D.C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended September 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 1-4473
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 N. 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 14, 2000: 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
APS Energy Services - APS Energy Services Company, Inc., a subsidiary of
Pinnacle West
Company - Arizona Public Service Company
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 - United States Environmental Protection Agency
FASB - Financial Accounting Standards Board
FERC - United States Federal Energy Regulatory Commission
Four Corners - Four Corners Power Plant
ITC - Investment tax credit
June 10-Q - Quarterly Report on Form 10-Q for the fiscal quarter ended June 30,
2000
MW - Megawatts
NGS - Navajo Generating Station
1999 10-K - Arizona Public Service Company Annual Report on Form 10-K for the
fiscal year ended December 31, 1999
Palo Verde - Palo Verde Nuclear Generating Station
Pinnacle West - Pinnacle West Capital Corporation
Pinnacle West Energy - Pinnacle West Energy Corporation, a Pinnacle West
subsidiary
SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation"
SFAS No. 133 - Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities"
Salt River Project - Salt River Project Agricultural Improvement and Power
District
Settlement Agreement - APS' Settlement Agreement approved by the ACC in 1999
<PAGE>
-2-
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Three Months
Ended September 30,
--------------------------
2000 1999
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
ELECTRIC OPERATING REVENUES .............................. $ 1,565,622 $ 867,504
----------- -----------
FUEL EXPENSES:
Fuel for electric generation ........................... 100,036 68,137
Purchased power ........................................ 977,103 332,617
----------- -----------
Total ............................................... 1,077,139 400,754
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES .................... 488,483 466,750
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses ..... 110,827 107,188
Depreciation and amortization .......................... 97,383 94,184
Income taxes ........................................... 93,998 92,286
Other taxes ............................................ 25,629 22,178
----------- -----------
Total ............................................... 327,837 315,836
----------- -----------
OPERATING INCOME ......................................... 160,646 150,914
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net ............................................ (3,544) 620
Income taxes ........................................... 1,424 13,283
----------- -----------
Total ............................................... (2,120) 13,903
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ........................ 158,526 164,817
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ............................. 33,681 31,409
Interest on short-term borrowings ...................... 1,634 2,775
Debt discount, premium and expense ..................... 1,656 1,847
Capitalized interest ................................... (2,676) (722)
----------- -----------
Total ............................................... 34,295 35,309
----------- -----------
INCOME BEFORE EXTRAORDINARY CHARGE ....................... 124,231 129,508
Extraordinary charge - net of income taxes of $94,115 .. -- 139,885
----------- -----------
EARNINGS (LOSS) FOR COMMON STOCK ......................... $ 124,231 $ (10,377)
=========== ===========
</TABLE>
See Notes to Condensed Financial Statements.
<PAGE>
-3-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Nine Months
Ended September 30,
--------------------------
2000 1999
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
ELECTRIC OPERATING REVENUES .............................. $ 2,730,997 $ 1,792,921
----------- -----------
FUEL EXPENSES:
Fuel for electric generation ........................... 232,655 178,536
Purchased power ........................................ 1,259,151 457,319
----------- -----------
Total ............................................... 1,491,806 635,855
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES .................... 1,239,191 1,157,066
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses ..... 323,938 313,884
Depreciation and amortization .......................... 289,856 286,856
Income taxes ........................................... 189,706 166,945
Other taxes ............................................ 76,606 73,008
----------- -----------
Total ............................................... 880,106 840,693
----------- -----------
OPERATING INCOME ......................................... 359,085 316,373
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net ............................................ (3,856) (3,799)
Income taxes ........................................... 1,550 24,765
----------- -----------
Total ............................................... (2,306) 20,966
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ........................ 356,779 337,339
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ............................. 99,626 98,833
Interest on short-term borrowings ...................... 6,754 6,779
Debt discount, premium and expense ..................... 5,124 5,604
Capitalized interest ................................... (7,582) (6,721)
----------- -----------
Total ............................................... 103,922 104,495
----------- -----------
INCOME BEFORE EXTRAORDINARY CHARGE ....................... 252,857 232,844
Extraordinary charge - net of income taxes of $94,115 .. -- 139,885
----------- -----------
NET INCOME ............................................... 252,857 92,959
PREFERRED STOCK DIVIDEND REQUIREMENTS .................... -- 1,016
----------- -----------
EARNINGS FOR COMMON STOCK ................................ $ 252,857 $ 91,943
=========== ===========
</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,
--------------------------
2000 1999
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
ELECTRIC OPERATING REVENUES .............................. $ 3,230,874 $ 2,236,447
----------- -----------
FUEL EXPENSES:
Fuel for electric generation ........................... 297,968 235,629
Purchased power ........................................ 1,353,477 516,996
----------- -----------
Total ............................................... 1,651,445 752,625
----------- -----------
OPERATING REVENUES LESS FUEL EXPENSES .................... 1,579,429 1,483,822
----------- -----------
OTHER OPERATING EXPENSES:
Operations and maintenance excluding fuel expenses ..... 447,783 419,910
Depreciation and amortization .......................... 385,057 384,333
Income taxes ........................................... 214,776 196,344
Other taxes ............................................ 100,177 95,970
----------- -----------
Total ............................................... 1,147,793 1,096,557
----------- -----------
OPERATING INCOME ......................................... 431,636 387,265
----------- -----------
OTHER INCOME (DEDUCTIONS):
Other - net ............................................ (11,594) (9,067)
Income taxes ........................................... 9,312 31,302
----------- -----------
Total ............................................... (2,282) 22,235
----------- -----------
INCOME BEFORE INTEREST DEDUCTIONS ........................ 429,354 409,500
----------- -----------
INTEREST DEDUCTIONS:
Interest on long-term debt ............................. 133,469 132,798
Interest on short-term borrowings ...................... 8,247 8,841
Debt discount, premium and expense ..................... 6,843 7,439
Capitalized interest ................................... (7,540) (10,357)
----------- -----------
Total ............................................... 141,019 138,721
----------- -----------
INCOME BEFORE EXTRAORDINARY CHARGE ....................... 288,335 270,779
Extraordinary charge - net of income taxes of $94,115 .. -- 139,885
----------- -----------
NET INCOME ............................................... 288,335 130,894
PREFERRED STOCK DIVIDEND REQUIREMENTS .................... -- 3,059
----------- -----------
EARNINGS FOR COMMON STOCK ................................ $ 288,335 $ 127,835
=========== ===========
</TABLE>
See Notes to Condensed Financial Statements
<PAGE>
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ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
ASSETS
(Unaudited)
September 30, December 31,
2000 1999
----------- -----------
(Thousands of Dollars)
UTILITY PLANT:
Electric plant in service and held for future use $ 7,726,945 $ 7,545,575
Less accumulated depreciation and amortization ... 3,193,589 3,026,041
----------- -----------
Total ......................................... 4,533,356 4,519,534
Construction work in progress .................... 215,639 184,764
Nuclear fuel, net of amortization ................ 51,274 49,114
----------- -----------
Utility plant - net ........................... 4,800,269 4,753,412
----------- -----------
INVESTMENTS AND OTHER ASSETS ..................... 192,725 208,457
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents ........................ 63,365 7,477
Accounts receivable:
Service customers ............................. 606,040 201,704
Other ......................................... 78,036 35,684
Allowance for doubtful accounts ............... (2,168) (1,538)
Accrued utility revenues ......................... 111,315 72,919
Materials and supplies, at average cost .......... 73,506 69,977
Fossil fuel, at average cost ..................... 14,553 21,869
Deferred income taxes ............................ 8,163 8,163
Other ............................................ 39,324 30,885
----------- -----------
Total current assets .......................... 992,134 447,140
----------- -----------
DEFERRED DEBITS:
Regulatory assets ................................ 502,595 613,729
Unamortized debt issue costs ..................... 13,143 15,172
Other ............................................ 47,544 79,714
----------- -----------
Total deferred debits ......................... 563,282 708,615
----------- -----------
TOTAL ......................................... $ 6,548,410 $ 6,117,624
=========== ===========
See Notes to Condensed Financial Statements.
<PAGE>
-6-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES
(Unaudited)
September 30, December 31,
2000 1999
---------- ----------
(Thousands of Dollars)
CAPITALIZATION:
Common stock ...................................... $ 178,162 $ 178,162
Additional paid-in capital ........................ 1,246,804 1,246,804
Retained earnings ................................. 683,565 558,208
---------- ----------
Common stock equity ............................ 2,108,531 1,983,174
Long-term debt less current maturities ............ 2,056,282 1,997,400
---------- ----------
Total capitalization ........................... 4,164,813 3,980,574
---------- ----------
CURRENT LIABILITIES:
Commercial paper .................................. 2,000 38,300
Current maturities of long-term debt .............. 4,887 114,711
Accounts payable .................................. 472,090 170,662
Accrued taxes ..................................... 208,857 62,858
Accrued interest .................................. 23,600 32,299
Customer deposits ................................. 23,892 24,682
Other ............................................. 69,322 26,248
---------- ----------
Total current liabilities ...................... 804,648 469,760
---------- ----------
DEFERRED CREDITS AND OTHER:
Deferred income taxes ............................. 1,104,516 1,178,085
Unamortized gain - sale of utility plant .......... 69,780 73,212
Customer advances for construction ................ 41,128 38,150
Other ............................................. 363,525 377,843
---------- ----------
Total deferred credits and other ............... 1,578,949 1,667,290
---------- ----------
COMMITMENTS AND CONTINGENCIES (Notes 6, 7, and 9)
TOTAL .......................................... $6,548,410 $6,117,624
========== ==========
See Notes to Condensed Financial Statements.
<PAGE>
-7-
ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Nine Months
Ended September 30,
--------------------------
2000 1999
----------- -----------
(Thousands of Dollars)
<S> <C> <C>
Cash Flows from Operating Activities:
NET INCOME ......................................... $ 252,857 $ 92,959
Items not requiring cash:
Depreciation and amortization .................... 289,856 286,856
Nuclear fuel amortization ........................ 23,139 24,306
Deferred income taxes - net ...................... (47,627) (30,977)
Deferred investment tax credit - net ............. -- (23,503)
Extraordinary charge, net of income taxes - net .. -- 139,885
Changes in certain current assets and liabilities:
Accounts receivable - net ........................ (446,058) (102,315)
Accrued utility revenues ......................... (38,396) (33,543)
Materials, supplies and fossil fuel .............. 3,787 (4,758)
Other current assets ............................. (8,439) (2,174)
Accounts payable ................................. 298,198 78,937
Accrued taxes .................................... 145,999 126,147
Accrued interest ................................. (8,699) (8,838)
Other current liabilities ........................ 42,284 7,897
Other - net ........................................ 32,302 (18,750)
----------- -----------
Net cash flow provided by operating activities .. 539,203 532,129
----------- -----------
Cash Flows from Investing Activities:
Capital expenditures ............................... (278,282) (228,540)
Capitalized interest ............................... (7,582) (6,721)
Other .............................................. 18,349 592
----------- -----------
Net cash flow used for investing activities .... (267,515) (234,669)
----------- -----------
Cash Flows from Financing Activities:
Long-term debt ..................................... 300,000 142,952
Short-term borrowings - net ........................ (36,300) 44,670
Dividends paid on common stock ..................... (127,500) (127,500)
Dividends paid on preferred stock .................. -- (1,393)
Repayment of preferred stock ....................... -- (96,499)
Repayment and reacquisition of long-term debt ...... (352,000) (260,381)
----------- -----------
Net cash flow used for financing activities .... (215,800) (298,151)
----------- -----------
Net increase (decrease) in cash and cash equivalents.. 55,888 (691)
Cash and cash equivalents at beginning of period ..... 7,477 5,558
----------- -----------
Cash and cash equivalents at end of period ........... $ 63,365 $ 4,867
=========== ===========
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest) ........ $ 96,723 $ 107,677
Income taxes ..................................... $ 133,817 $ 102,299
</TABLE>
See Notes to Condensed Financial Statements.
<PAGE>
-8-
ARIZONA PUBLIC SERVICE COMPANY
NOTES TO CONDENSED FINANCIAL STATEMENTS
1. Our unaudited 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 the exception of the extraordinary charge . 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 1999 10-K. We have reclassified certain
prior year amounts to conform to the current year presentation.
2. Weather conditions and wholesale power marketing and trading activities can
have significant impacts on our results for interim periods. For these 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, 2000.
5. Regulatory Accounting
For regulated operations, we prepare our financial statements in accordance with
SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS
No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of
regulatory decisions in its financial statements.
During 1997, the Emerging Issues Task Force (EITF) of the FASB issued EITF 97-4.
EITF 97-4 requires that SFAS No. 71 be discontinued no later than when
legislation is passed or a rate order is issued that contains sufficient detail
to determine its effect on the portion of the business being deregulated, which
could result in write-downs or write-offs of physical and/or regulatory assets.
Additionally, the EITF determined that regulatory assets should not be written
off if they are to be recovered from a portion of the entity which continues to
apply SFAS No. 71.
The Settlement Agreement was approved by the ACC in September 1999 (see Note 6
for a discussion of the agreement). Consequently, we have discontinued the
application of SFAS No. 71 for our generation operations. This application means
that the generation assets were tested for impairment and the portion of
regulatory assets deemed to be unrecoverable through ongoing regulated cash
flows was eliminated. We determined that the generation assets were not
impaired. A regulatory disallowance removed $234 million pretax ($183 million
net present value) from ongoing regulatory cash flows and was recorded as a net
reduction of regulatory assets. This reduction ($140 million after income taxes)
was reported as an extraordinary charge on the income statement during the third
quarter of 1999. Prior to the Settlement Agreement, under the 1996 regulatory
agreement (see Note 6), the ACC accelerated the amortization of substantially
all of our regulatory assets to an eight-year period ending June 30, 2004.
<PAGE>
-9-
The regulatory assets to be recovered under the 1999 Settlement Agreement are
now being amortized as follows (millions of dollars):
1/1 - 6/30
1999 2000 2001 2002 2003 2004 Total
---- ---- ---- ---- ---- ---- -----
$164 $158 $145 $115 $ 86 $ 18 $686
The majority of our regulatory assets relate to deferred income taxes and rate
synchronization cost deferrals.
The condensed balance sheets include the amounts listed below for generation
assets not subject to SFAS No. 71 (thousands of dollars):
September 30, December 31,
2000 1999
----------- -----------
Electric plant in service & held for future use $ 3,819,709 $ 3,770,234
Accumulated depreciation and amortization (1,725,706) (1,641,855)
Construction work in progress 82,447 67,306
Nuclear fuel, net of amortization 51,274 49,114
6. Regulatory Matters -- Electric Industry Restructuring
STATE
SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive
Settlement Agreement with various parties, including representatives of major
consumer groups, related to the implementation of retail electric competition.
On September 23, 1999, the ACC voted to approve the Settlement Agreement, with
some modifications. On December 13, 1999, two parties filed lawsuits challenging
the ACC's approval of the Settlement Agreement. One of the parties questioned
the authority of the ACC to approve the Settlement Agreement and both parties
challenged several specific provisions of the Settlement Agreement. A decision
on the appeals to the Settlement Agreement is not expected until later this year
or next year.
<PAGE>
-10-
The following are the major provisions of the Settlement Agreement, as approved:
* We have reduced, and will reduce, rates for standard offer service for
customers with loads less than three MW in a series of annual retail
electric price reductions of 1.5% beginning July 1, 1999 through July
1, 2003, for a total of 7.5%. The first reduction of approximately $24
million ($14 million after income taxes) included the July 1, 1999
retail price decrease of approximately $11 million ($7 million after
income taxes) related to the 1996 regulatory agreement. See "1996
Regulatory Agreement" below. Based on the price reduction authorized
in the Settlement Agreement, there was a retail price decrease of
approximately $28 million ($17 million after taxes), or 1.5%,
effective July 1, 2000. For customers having loads three MW or
greater, standard offer rates will be reduced in varying annual
increments that total 5% through 2002.
* Unbundled rates being charged by us for competitive direct access
service (for example, distribution services) became effective upon
approval of the Settlement Agreement, retroactive to July 1, 1999, and
also will be subject to annual reductions beginning January 1, 2000,
that vary by rate class, through January 1, 2004.
* There will be a moratorium on retail price changes for standard offer
and unbundled competitive direct access services until July 1, 2004,
except for the price reductions described above and certain other
limited circumstances. Neither the ACC nor 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 MW 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.
* Prior to the Settlement Agreement, we were 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
<PAGE>
-11-
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 such affiliate(s) our generating assets and competitive services at
book value as of the date of transfer, which transfer shall take place
no later than December 31, 2002. See Management's Discussion and
Analysis of Financial Condition and Results of Operations below for a
discussion of the planned timing of the transfer. We will be allowed
to defer and later collect, beginning July 1, 2004, sixty-seven
percent of our costs to accomplish the required transfer of generation
assets to an affiliate.
* When the Settlement Agreement approved by the ACC is no longer subject
to judicial review, we will move to dismiss all of our litigation
pending against the ACC as of the date we entered into the Settlement
Agreement. To protect our rights, we have several lawsuits pending on
ACC orders relating to stranded cost recovery and the adoption and
amendment of the ACC's electric competition rules, which would be
voluntarily dismissed at the appropriate time under this provision.
As discussed in Note 5 above, we have discontinued the application of SFAS No.
71 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 (Rules). If any of the Rules conflict with the
Settlement Agreement, the terms of the Settlement Agreement govern. On December
8, 1999, we filed a lawsuit to protect our legal rights regarding the Rules.
This lawsuit is pending, along with several other lawsuits on ACC orders
relating to stranded cost recovery, the adoption or amendment of the Rules and
the certification of competitive electric service providers.
On July 12, 2000, a Maricopa County Superior Court judge issued a preliminary
ruling and denied most of the substantive challenges to the Rules that had been
made by certain electric cooperatives. However, he concluded that some of the
Rules were invalid because of procedural deficiencies or were invalid in their
application. Specifically, the judge concluded that several non-ratemaking Rules
were required to be presented to the Arizona Attorney General for certification
prior to becoming effective. Additionally, the judge determined that the Arizona
Constitution requires the ACC to make findings regarding the fair value of
property in Arizona in establishing rates for competitive electric service
providers (ESPs), which rendered the rate setting provisions of the Rules
invalid in the application.
On November 2, 2000, the same Superior Court judge amended his July 12
preliminary ruling. This amended ruling indicated the Court's intent to accept
the substantive provisions of a form of final judgment submitted by the electric
cooperatives that finds the Rules in their entirety to be unconstitutional and
unlawful due to failure to establish fair value rate base and because certain of
the Rules were not submitted to the Arizona Attorney General for certification.
The cooperatives' proposed form of final judgment also invalidates all the ACC
orders authorizing competitive electric service providers in Arizona. We do not
believe either of the rulings affects the Settlement Agreement with the ACC. The
Settlement Agreement was not at issue in the consolidated cases before the
judge. Further, the ACC made findings related to the fair value of APS' property
in the order approving the APS Settlement Agreement.
<PAGE>
-12-
Although the ACC has not yet indicated what steps it intends to take after a
final judgment is issued, the ACC could appeal the ruling to the Court of
Appeals or could elect to take action to correct the deficiencies identified in
the judge's ruling. The cooperatives or ESPs may also appeal the ruling. If the
order is appealed by the ACC or any of the ESPs, including APS Energy Services,
we believe that it will be automatically stayed pending further judicial review.
The Rules approved by the ACC include the following major provisions:
* They apply to virtually all Arizona electric utilities regulated by
the ACC, including 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, we will
provide retail access to customers representing the minimum 20%
required by the ACC and an additional 140 MW of non-residential load
in 1999, and to all customers as of January 1, 2001, or such other
dates as approved by the ACC.
* Subject to the 20% requirement, all utility customers with single
premise loads of one MW or greater will be eligible for competitive
electric services on the Final Decision Date, which for our customers
was the approval of the Settlement Agreement. Customers may also
aggregate smaller loads to meet this one MW requirement.
* Residential customers were phased in at 1.25% per quarter calculated
beginning on January 1, 1999, subject to the 20% requirement above.
* Electric service providers that get Certificates of Convenience and
Necessity (CC&Ns) from the ACC can supply only competitive services,
including electric generation, but not electric transmission and
distribution.
* Affected utilities must file ACC tariffs that unbundle rates for
non-competitive services.
* The ACC shall allow a reasonable opportunity for recovery of
unmitigated stranded costs.
* Absent an ACC waiver, prior to January 1, 2001, each affected utility
(except certain electric cooperatives) must transfer all competitive
generation assets and services either to an unaffiliated party or to a
separate corporate affiliate. Under the Settlement Agreement, we
received a waiver to allow transfer of our generation and other
competitive assets and services to affiliates no later than December
31, 2002. See Management's Discussion and Analysis of Financial
Condition and Results of Operations below for a discussion of the
planned timing of the transfer.
<PAGE>
-13-
1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory
agreement between the ACC Staff and us. Based on the price reduction formula
authorized in the agreement, the ACC approved retail price decreases
(approximate) as follows (millions of dollars):
Annual Electric Percentage
Revenue Decrease Decrease Effective Date
---------------- -------- --------------
$49 3.4% July 1, 1996
$18 1.2% July 1, 1997
$17 1.1% July 1, 1998
$11 0.7% July 1, 1999 (a)
(a) Included in the first rate reduction under the Settlement Agreement
(see above).
The regulatory agreement also required the parent company to infuse $200 million
of common equity into us in annual payments of $50 million from 1996 through
1999. All of these equity infusions were made by December 31, 1999.
LEGISLATION. In May 1998, a law was enacted to facilitate implementation of
retail electric competition in Arizona. The law includes the following major
provisions:
* Arizona's largest government-operated electric utility (Salt River
Project) and, at their option, smaller municipal electric systems must
(i) make at least 20% of their 1995 retail peak demand available to
electric service providers by December 31, 1998 and for all retail
customers by December 31, 2000; (ii) decrease rates by at least 10%
over a ten-year period beginning as early as January 1, 1991; (iii)
implement procedures and public processes comparable to those already
applicable to public service corporations for establishing the terms,
conditions, and pricing of electric services as well as certain other
decisions affecting retail electric competition;
* describes the factors which form the basis of consideration by Salt
River Project in determining stranded costs; and
* metering and meter reading services must be provided on a competitive
basis during the first two years of competition only for customers
having demands in excess of one MW (and that are eligible for
competitive generation services), and thereafter for all customers
receiving competitive electric generation.
GENERAL
We cannot accurately predict the impact of full retail competition on our
financial position, cash flows, or results of operations. As competition in the
electric industry continues to evolve, we will continue to evaluate strategies
and alternatives that will position the Company and our subsidiaries to compete
in the new regulatory environment.
<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 current congressional session. Several of these bills are written to
allow consumers to choose their electricity suppliers beginning in 2000 and
beyond. These bills, other bills that are expected to be introduced, and ongoing
discussions at the federal level suggest a wide range of opinion that will need
to be narrowed before any comprehensive restructuring of the electric utility
industry can occur.
7. Nuclear Insurance
The Palo Verde participants have insurance for public liability payments
resulting from nuclear energy hazards to the full limit of liability under
federal law. This potential liability is covered by primary liability insurance
provided by commercial insurance carriers in the amount of $200 million and the
balance by an industry-wide retrospective assessment program. If losses at any
nuclear power plant covered by the programs exceed the accumulated funds, 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>
-15-
8. Business Segments
We have two principal business segments (determined by products, services and
regulatory environment) which consist of the transmission and distribution of
electricity and wholesale power marketing and trading activities (delivery
business segment) and the generation of electricity (generation business
segment). Eliminations primarily relate to intersegment sales of electricity.
Segment information for the three, nine and twelve months ended September 30,
2000 and 1999 is as follows (millions of dollars):
<TABLE>
<CAPTION>
3 Months Ended 9 Months Ended 12 Months Ended
September 30, September 30, September 30,
----------------- ------------------- -------------------
2000 1999 2000 1999 2000 1999
------- ----- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues:
Delivery $ 1,566 $ 867 $ 2,731 $ 1,793 $ 3,231 $ 2,236
Generation 322 266 750 662 942 852
Eliminations (322) (266) (750) (662) (942) (852)
------- ----- ------- ------- ------- -------
Total $ 1,566 $ 867 $ 2,731 $ 1,793 $ 3,231 $ 2,236
======= ===== ======= ======= ======= =======
Income from Continuing
Operations:
Delivery $ 57 $ 61 $ 137 $ 115 $ 169 $ 142
Generation 67 69 116 117 119 126
------- ----- ------- ------- ------- -------
Total $ 124 $ 130 $ 253 $ 232 $ 288 $ 268
======= ===== ======= ======= ======= =======
</TABLE>
As of September 30, As of December 31,
2000 1999
------ ------
Assets:
Delivery $4,238 $3,796
Generation 2,310 2,322
------ ------
Total $6,548 $6,118
====== ======
<PAGE>
-16-
9. Accounting Matters
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". In June 2000, the FASB issued SFAS No. 138,
which amends certain provisions of SFAS133 to clarify certain areas causing
difficulties in implementation. The amendment includes expanding the normal
purchase and sale exemption for supply contracts. We will adopt SFAS133 and the
corresponding amendments under SFAS138 on January 1, 2001. We are currently
determining the impact of SFAS133 on our consolidated results of operations and
financial position; however, certain implementation issues are currently being
resolved by the FASB's Derivatives Implementation Group that will significantly
affect its impact. This statement should have no impact on cash flows.
<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
* the effects of regulatory decisions on our results and outlook
* our capital needs and resources and
* our management of market risks.
We are Arizona's largest electric utility, providing retail and wholesale
electric service to the entire state with the exception of Tucson and about
one-half of the Phoenix area. We also generate, sell, and deliver electricity to
wholesale customers in the western United States.
As discussed in Note 6, the Settlement Agreement and the Rules require us to
transfer our generating assets and competitive services to one or more corporate
affiliates. We plan to complete the move of our wholesale power marketing and
trading activities to the parent company by the end of 2000. We plan to move
certain of our non-nuclear generating facilities and related assets, as well as
certain employees of our generation business unit, to Pinnacle West Energy on
January 1, 2001, or as soon thereafter as requisite approvals are obtained. See
Note 6 for information regarding lawsuits challenging the Settlement Agreement
and the Rules.
We suggest this section be read along with the 1999 10-K. Throughout this
Management's Discussion and Analysis of Financial Condition and Results of
Operations, we refer to specific "Notes" in the Notes to Condensed Financial
Statements in this report. 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, 2000 and the comparable
prior-year periods:
<PAGE>
-18-
Periods ended September 30
(Unaudited)
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
----------------------- ------------------------ ------------------------
2000 1999 2000 1999 2000 1999
---------- --------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $1,565,622 $ 867,504 $2,730,997 $1,792,921 $3,230,874 $2,236,447
Earnings (Loss) for
Common Stock (1) $ 124,231 $ (10,377) $ 252,857 $ 91,943 $ 288,335 $ 127,835
</TABLE>
(1) Each of the 1999 periods include an extraordinary charge of $139,885 net of
income taxes of $94,115.
OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED
WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1999
Earnings for the three months ended September 30, 2000 were $124 million
compared with a loss of $10 million for the same period in the prior year. The
increase primarily relates to an extraordinary charge recorded in the third
quarter of 1999, partially offset by lower income excluding the extraordinary
charge in the third quarter of 2000.
The extraordinary charge related to a regulatory disallowance that resulted from
our comprehensive Settlement Agreement that was approved by the ACC in September
1999. See Notes 5 and 6 for additional information about the regulatory
disallowance and the Settlement Agreement.
Earnings excluding the extraordinary charge decreased $5 million over the
comparable prior-year period primarily because of the completion of the
amortization of ITCs in 1999, an electricity price reduction, and miscellaneous
factors. Partially offsetting these factors was an increase in the contribution
of wholesale power marketing and trading activities. See Note 6 for information
on the price reduction. See "Income Taxes" below for a discussion of the ITC
amortization.
Electric operating revenues increased $ 698 million because of:
* increased power marketing, trading, and wholesale revenues ($664
million)
* increases in the number of customers and the average amount of
electricity used by customers ($33 million) and
* warmer weather impacts ($9 million).
As mentioned above, these positive factors were partially offset by the effect
of a reduction in retail electricity prices ($8 million).
The increase in power marketing, trading, and wholesale revenues resulted from
higher prices and increased activity in the western U.S. wholesale power
markets. The revenues were accompanied by an increase in purchased power and
fuel expenses of $602 million.
<PAGE>
-19-
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased prices.
Utility operations and maintenance expenses increased primarily because of
higher costs related to customer growth.
Property tax expense increased because of higher tax rates.
Depreciation and amortization expense increased primarily because of higher
plant balances.
OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED
WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1999
Earnings for the nine months ended September 30, 2000 were $253 million compared
with $92 million for the same period in the prior year. The increase primarily
relates to an extraordinary charge recorded in the third quarter of 1999 and
higher earnings excluding the extraordinary charge in the nine month period
ended September 30, 2000.
The extraordinary charge related to a regulatory disallowance that resulted from
our comprehensive Settlement Agreement that was approved by the ACC in September
1999. See Notes 5 and 6 for additional information about the regulatory
disallowance and the Settlement Agreement.
Earnings excluding the extraordinary charge increased $21 million over the
comparable prior-year period primarily because of an increase in the
contribution of wholesale power marketing and trading activities. This positive
factor more than offsets decreases due to the completion of the amortization of
ITCs in 1999, electricity price reductions, higher utility operations and
maintenance expense, and miscellaneous factors. See Note 6 for information on
the price reductions. See "Income Taxes" below for a discussion of the ITC
amortization.
Electric operating revenues increased $938 million because of:
* increased power marketing, trading, and wholesale revenues ($840
million)
* increases in the number of customers and the average amount of
electricity used by customers ($87 million)
* warmer weather impacts ($28 million) and
* miscellaneous factors ($1 million).
These positive factors were partially offset by the effect of a reduction in
retail electricity prices ($18 million).
The increase in power marketing, trading, and wholesale revenues resulted from
higher prices and increased activity in the western U.S. wholesale power
markets. The revenues were accompanied by an increase in purchased power and
fuel expenses of $734 million.
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased prices.
<PAGE>
-20-
Utility operations and maintenance expenses increased primarily because of
higher costs primarily related to customer growth.
OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED
WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1999
Earnings for the twelve months ended September 30, 2000 were $288 million
compared with $128 million for the same period in the prior year. The increase
primarily relates to an extraordinary charge recorded in the third quarter of
1999 and higher earnings excluding the extraordinary charge in the twelve month
period ended September 30, 2000.
The extraordinary charge related to a regulatory disallowance that resulted from
our comprehensive Settlement Agreement that was approved by the ACC in September
1999. See Notes 5 and 6 for additional information about the regulatory
disallowance and the Settlement Agreement.
Earnings excluding the extraordinary charge increased $21 million over the
comparable prior year period primarily because of an increase in the
contribution of wholesale power marketing and trading activities, and an
increase in the number of customers and in the average amount of electricity
used by customers. These positive factors more than offset decreases due to the
completion of the amortization of ITCs in 1999, reductions in retail electricity
prices, higher utility operations and maintenance expenses, and miscellaneous
factors. See Note 6 for information on the price reduction. See "Income Taxes"
below for a discussion of the ITC amortization.
Electric operating revenues increased $994 million because of:
* increased power marketing, trading, and wholesale revenues ($880
million)
* increases in the number of customers and the average amount of
electricity used by customers ($107 million) and
* warmer weather impacts ($35).
These positive factors were partially offset by the effect of a reduction in
retail electricity prices ($28 million).
The increase in power marketing, trading, and wholesale revenues resulted
primarily from increased activity in western U.S. wholesale power markets and
higher prices. The revenues were accompanied by increases in purchased power and
fuel expenses of $769 million.
Fuel and purchased power expenses were also higher because of higher retail
sales volumes and increased prices.
Utility operations and maintenance expenses increased primarily because of
customer growth, power marketing costs, and technology related costs.
<PAGE>
-21-
INCOME TAXES
As part of a 1994 rate settlement with the ACC, we accelerated amortization of
substantially all deferred ITCs over a five-year period that ended on December
31, 1999. The ITC amortization decreased annual income tax expense by
approximately $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, 2000, we incurred approximately $275
million in capital expenditures, which is approximately 59% of the most recently
estimated 2000 capital expenditures. Our projected capital expenditures for the
next three years are $464 million in 2000; $356 million in 2001; and $364 in
2002. These amounts include about $30-$35 million each year for nuclear fuel
expenditures.
Our long-term debt redemption requirements, optional repayments on long-term
debt, and payment obligations on a capitalized lease are: $354 million in 2000;
$252 million in 2001; and $125 million in 2002. During the nine months ended
September 30, 2000, we redeemed all of our long-term debt requirements for 2000
with cash from operations and short-term borrowings. On August 7, 2000, we
issued $300 million of our 7 5/8% Notes Due 2005.
We expect to purchase Units 1, 2 and 3 of the West Phoenix Power Plant in
December 2000. These units are currently reflected as a capitalized lease.
Although provisions in 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.
FINANCIAL OUTLOOK
This section describes the major factors affecting our financial outlook. See
"Liquidity and Capital Resources" for expected capital expenditures and
financing requirements. See "Operating Results" for a summary of our earnings
for the three-month, nine-month, and twelve-month periods ended September 30,
2000 and 1999.
The electric industry is restructuring to a competitive, customer-driven
environment from a regulated monopoly structure. See Note 6 for a discussion of
industry restructuring developments and their potential impacts on our financial
outlook. In addition to other issues, the Settlement Agreement sets forth
electricity prices for its regulated electricity services and the timing for
customer eligibility to select competitive energy providers.
Electric operating revenues are derived from sales of electricity in regulated
retail markets in Arizona, and from competitive retail and wholesale bulk power
markets in the western United States. The revenues are expected to be affected
by electricity sales volumes related to customer mix, customer growth and
average usage per customer, as well as electricity prices and variations in
weather from period to period.
<PAGE>
-22-
In our regulated retail market area, we will provide electricity services to
standard-offer, full-service customers and to energy delivery customers who have
chosen another provider for their electricity commodity needs (unbundled
customers). Customer growth in our service territory averaged 3.9% a year for
the three years 1997 through 1999; we currently expect customer growth to
average 3.5% to 4% a year for 2000 through 2002. We currently estimate that
electricity sales in kilowatt-hours will grow 4% to 5% a year in 2000 through
2002, before the effects of weather variations. The customer growth and sales
growth referred to in this paragraph apply to energy delivery customers. As
industry restructuring continues in the regulated market area, we cannot predict
the number of standard offer customers that will switch to unbundled service.
Bulk power marketing and trading activities will be affected by electricity
prices and costs of available fuel and purchased power from time to time in the
western United States, as well as competitive market conditions and regulatory
and legislative changes in various state and federal jurisdictions. These
factors have significantly affected our wholesale marketing and trading
activities and their resultant earnings contributions over the last several
years. We cannot predict future contributions from bulk power marketing and
trading activities.
Fuel and purchased power costs are impacted by our electricity sales volumes,
existing contracts for generation fuel and purchased power, our power plant
performance, prevailing market prices, and our hedging program for managing such
costs.
Utility operations and maintenance expenses are expected to be affected by sales
mix and volumes, inflation, and other factors.
Depreciation and amortization expenses are expected to be affected by net
additions to existing utility plant and other property and changes in regulatory
asset amortization. See Note 5 for the regulatory asset amortization that is
being recorded in 1999 through 2004 pursuant to the Settlement Agreement. See
Note 1 of Notes to Consolidated Financial Statements in the 1999 10-K regarding
current depreciation rates.
Taxes other than income taxes consist primarily of property taxes, which are
affected by tax rates and the value of property in service and under
construction. We expect property taxes to grow primarily due to our additions to
existing facilities.
Interest expense is affected by the amount of debt outstanding and the interest
rates on that debt.
Our financial results may be affected by a number of broad factors. See
"Forward-Looking Statements" for further information on such factors, which may
cause our actual future results to differ from those we currently seek or
anticipate.
<PAGE>
-23-
COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING
See Note 5 for a discussion of regulatory accounting. See Note 6 for a
discussion of a Settlement Agreement related to the implementation of retail
electric competition and to Arizona and federal legal and regulatory
developments.
RATE MATTERS
See Note 6 for a discussion of a price reduction effective as of July 1, 2000,
and for a discussion of a Settlement Agreement that will, among other things,
result in five annual price reductions over a four-year period ending July 1,
2003.
FORWARD-LOOKING STATEMENTS
The above discussion contains forward-looking statements that involve risks and
uncertainties. Words such as "estimates," "expects," "anticipates," "plans,"
"believes," "projects," and similar expressions identify forward-looking
statements. These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric industry; the outcome of the regulatory
proceedings relating to the restructuring; regulatory, tax, and environmental
legislation; our ability to successfully compete outside traditional regulated
markets; regional economic conditions, which could affect customer growth; the
cost of debt and equity capital; weather variations affecting customer usage;
technological developments in the electric industry; the successful completion
of large-scale construction projects; and successfully managing market risks.
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>
-24-
ITEM 3. MARKET RISKS
Our operations include managing market risks related to changes in commodity
prices, interest rates, and investments held by the nuclear decommissioning
trust fund.
We are exposed to the impact of market fluctuations in the price and
transportation costs of electricity, natural gas, coal, and emissions
allowances. We employ established procedures to manage our risks associated with
these market fluctuations by utilizing various commodity derivatives, including
exchange-traded futures and options and over-the-counter forwards, options, and
swaps. As part of our overall risk management program, we enter into these
derivative transactions to hedge purchases and sales of electricity, fuels and
emissions allowances/credits. In addition, we engage in trading activities
intended to profit from favorable movements of market prices.
As of September 30, 2000, a hypothetical adverse price movement of 10% in the
market price of our commodity derivative portfolio would decrease the fair
market value of these contracts by approximately $37 million. This analysis does
not include the favorable impact this same hypothetical price move would have on
the underlying physical exposures being hedged with the commodity derivative
portfolio. We plan to move our wholesale power marketing and trading activities
to the parent company by the end of 2000.
We are exposed to credit losses in the event of non-performance or non-payment
by counterparties. We use a credit management process to assess and monitor the
financial exposure of counterparties. Despite the fact that the great majority
of our trading counterparties are rated as investment grade by the credit rating
agencies, there is still a possibility that one or more of these companies could
default, resulting in a material impact on earnings for a given period.
Changing interest rates will affect interest paid on variable-rate debt and
interest earned by the nuclear decommissioning trust fund. Our policy is to
manage interest rates through the use of a combination of fixed-rate and
floating-rate debt. The nuclear decommissioning fund also has risks associated
with changing market values of equity investments. Nuclear decommissioning costs
are recovered in regulated electricity prices.
<PAGE>
-25-
PART II - OTHER INFORMATION
ITEM 5. OTHER INFORMATION
CONSTRUCTION AND FINANCING PROGRAMS
See "Liquidity and Capital Resources" in Part I, Item 2 of this report for a
discussion of construction and financing programs of the Company.
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
Purported Navajo Environmental Regulation
As previously reported, on June 29, 2000, at the request of the Court, we filed
a motion to dismiss Four Corners from a Petition for Review of EPA's regulations
on the grounds that the impact of the regulations on pre-existing binding
agreements was not "ripe" for judicial resolution based on EPA's issuance of an
official notice indicating that it had not yet determined whether the
pre-existing binding agreements with Four Corners and NGS were abrogated by the
Clean Air Act. See "Environmental Matters--Purported Navajo Environmental
Regulation" in Part II, Item 5 of the June 10-Q. The Court recently dismissed
Four Corners on the above-mentioned grounds.
WATER SUPPLY
As previously reported, we and other parties petitioned the U.S. Supreme Court
for review of an Arizona Supreme Court decision regarding groundwater rights,
and an issue important to the claims to water in the Lower Gila River Watershed
in Arizona was pending on appeal before the Arizona Supreme Court. See
"Environmental Matters - Water Supply" in Part I - Item 1 of the 1999 10-K. The
U.S. Supreme Court denied the petition. In addition, the Arizona Supreme Court
issued a decision affirming the lower court's definition of groundwater. We and
other parties have filed a motion for reconsideration on one aspect of that
decision.
PURCHASED POWER AGREEMENTS
As previously reported, in July 2000 we became involved in a dispute with
PacifiCorp relating to certain provisions of the Long-Term Power Transaction
Agreement dated September 1990. See "Purchased Power Agreements" in Part II,
Item 5 of the June 10-Q. We and PacifiCorp have settled the issues related to
the dispute. The resolution of this matter will not have a material adverse
impact on our financial position or results of operations.
<PAGE>
-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>
10.1 Articles of Incorporation 4.2 to Form S-3 Registration 1-4473 9-29-93
restated as of May 25, 1988 Nos. 33-33910 and 33-55248
by means of September 24,
1993 Form 8-K Report
10.2 Bylaws, amended as of 3.1 to 1995 Form 10-K Report 1-4473 3-29-96
February 20, 1996
10.3 Addendum to Settlement Agreement 10.1 to Pinnacle West September 1-8962 11-14-00
2000 10-Q
</TABLE>
(b) Reports on Form 8-K
During the quarter ended September 30, 2000, and the period from October 1
through November 14, 2000, we filed the following reports on Form 8-K:
Report dated July 12, 2000, relating to a preliminary ruling issued by a
Maricopa County Superior Court judge on cross-motions for summary judgment in
connection with lawsuits filed relating to the adoption or amendment of the
retail electric competition rules.
Report dated August 2, 2000 comprised of Exhibits to the Company's Registration
Statements (Registration Nos. 333-58445 and 333-94277) relating to the Company's
offering of $300 million of Notes.
----------
(a) Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of
the Securities and Exchange Commission located in Washington, D.C.
<PAGE>
-27-
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 14, 2000 By: Michael V. Palmeri
------------------------------------
Michael V. Palmeri
Vice President, Finance
(Principal Accounting Officer
and Officer Duly Authorized
to sign this Report)
